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, 2001
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. [ ]
The aggregate market value of the voting stock held by non-affiliates at March
1, 2002 was approximately $418,510,995.
The number of shares of common stock outstanding as of December 31, 2001 was
24,795,564 shares of common stock, $.01 par value.
Documents Incorporated by Reference
Document Incorporated as to
Notice and Proxy Statement for the Part III, Items 10, 11, 12, and 13
AnnualMeeting of Shareholders to
be held May 14, 2002
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 5
Item 3. Legal Proceedings 19
Item 4. Submission of Matters to a Vote of
Security Holders 19
Part II
Item 5. Market for the Registrant's Common
Equity and Related Stockholder Matters 19
Item 6. Selected Financial Data 20
Item 7. Management's Discussion and
Analysis of Financial Condition
and Results of Operations 23
Item 7A. Quantitative and Qualitative Disclosures
About Market Risk 32
Item 8. Financial Statements and Supple-
mentary Data 34
Item 9. Changes in and Disagreements with
Accountants on Accounting and
Financial Disclosure 60
Part III
Item 10. Directors and Executive Officers of
the Registrant (1) 60
Item 11. Executive Compensation (1) 60
Item 12. Security Ownership of Certain Bene-
ficial Owners and Management (1) 60
Item 13. Certain Relationships and Related
Transactions (1) 60
Part IV
Item 14. Exhibits, Financial Statement
Schedules and Reports on Form 8-K 61
(1) Incorporated by reference from Notice and Proxy Statement for the
Annual Meeting of Shareholders to be held May 14, 2002.
2
PART I
Items 1 and 2. Business and Properties
See pages 17 and 18 for explanations of abbreviations and terms used
herein.
General
Swift Energy Company is engaged in developing, exploring, acquiring, and
operating oil and gas properties, with a focus on onshore oil and natural gas
reserves in Texas and Louisiana and onshore oil and natural gas reserves in New
Zealand. The Company was founded in 1979 and is headquartered in Houston, Texas.
As of December 31, 2001, we had interests in 1,235 wells located domestically in
five states, in federal offshore waters, and in New Zealand. We operated 854 of
these wells representing 95% our proved reserves. At year-end 2001, we had
estimated proved reserves of 645.8 Bcfe, of which approximately 50% was natural
gas and 50% was proved developed. Our proved reserves are concentrated 53% in
Texas, 28% in Louisiana, and 16% in New Zealand.
We currently focus primarily on development and exploration in four
domestic core areas and in New Zealand:
% of Year-End % of 2001
Area Location 2001 Proved Reserves Production
------------------------- -------------------------- --------------------------- ----------------
AWP Olmos South Texas 32% 29%
Brookeland East Texas 9% 15%
Lake Washington South Louisiana 11% 3%
Masters Creek Central Louisiana 16% 34%
New Zealand New Zealand 16% 1%
--------------------------- ---------------
% of Total 84% 82%
The AWP Olmos and Lake Washington areas and New Zealand are characterized
by long-lived reserves that we expect to be steadily produced over a long period
of time. The Brookeland and Masters Creek areas are characterized by
shorter-lived reserves with high initial rates of production that decline
rapidly. We believe these shorter-lived reserves complement our long-lived
reserves. We focus on drilling the long-lived properties during periods of
decreasing commodity prices, while the shorter-lived properties provide
additional drillable projects in periods of rising commodity prices. Based on
2001 year-end domestic proved reserves and 2001 domestic production, our average
domestic reserve life was 12.3 years. Based on a report by an independent
engineering firm, prepared as part of the mining license application process,
the Rimu/Kauri development area is estimated to have a 25-30 year economic life.
We purchased interests in the Brookeland and Masters Creek areas from Sonat
Exploration Company in the third quarter of 1998 for approximately $85.8 million
in cash. Of this purchase price, $55.5 million was spent for producing
properties, $15.0 million for 20% interests in two natural gas processing
plants, and $15.3 million for leasehold properties. This acquisition generated
two new core areas. Then in late December 1999, we purchased additional working
interests in the Masters Creek area from Dominion Reserves, Inc., for
approximately $14.0 million in cash and purchased additional working interests
in the S. Burr Ferry portion of the Masters Creek area from Union Pacific for
approximately $1.9 million. We expect to use our operating expertise in this
geological trend to continue to successfully develop and exploit these
properties.
In the first quarter of 2001, we purchased interests in the Lake Washington
field from Elysium Energy, LLC, for approximately $30.5 million in cash. This
acquisition created the newest core area for the Company.
3
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 addition, we seek to enhance the results of
our drilling and production efforts through the implementation of advanced
technologies. For 1999, in response to lower oil and gas prices in 1998 that
continued in the first half of 1999, we decreased our capital expenditures
budget to $54.2 million, of which $36.0 million was targeted for drilling, $31.3
million for development drilling, and $4.7 million for exploratory drilling. The
remaining $18.2 million was targeted principally for leasehold, seismic, and
geological costs of prospects. After oil and gas prices rebounded in the second
half of the year, we increased our capital expenditures during the fourth
quarter. We funded the $78.1 million of capital expenditures spent in 1999
primarily through our internally generated cash flows of $73.6 million, while
the remainder was funded with net proceeds from our third quarter 1999 public
offering of common stock and Senior Notes that remained after paying off our
bank debt.
For 2000, in response to the strengthening of oil and gas prices and the
resulting increase in cash flows generated from these commodity prices, we
increased our capital expenditures to $173.3 million, of which $105.8 million
was targeted for drilling in the United States, with $90.3 million for
development drilling and $15.5 million for exploratory drilling. We spent $9.7
million in drilling to further delineate our Rimu discovery in New Zealand.
Additionally, $33.4 million was spent for producing property acquisitions. The
remaining $24.4 million was used principally for leasehold, seismic, and
geological costs of prospects. We funded the $173.3 million of capital
expenditures in 2000 primarily through our internally generated cash flows of
$128.2 million, while the remainder was funded with net proceeds from our third
quarter 1999 public offering of common stock and Senior Notes that remained
after paying off our bank debt and funding capital expenditures in 1999.
During 2001, as oil and gas prices continued to rise early in the year and
stayed strong through the first half of the year, our cash flow generated due to
these commodity prices increased as well. As a result of this cash flow and our
continued efforts in New Zealand, along with the opportunity to acquire the Lake
Washington assets, we increased our capital expenditures to $275.1 million. Of
this amount, $157.0 million was spent on drilling in the United States, with
$120.6 million for development drilling and $36.4 million for exploratory
drilling. We spent $26.2 million on drilling in New Zealand, with $19.0 million
on development drilling and $7.2 million on exploratory drilling. We also spent
$17.9 million constructing a gas processing plant in New Zealand and $40.5
million for domestic producing property acquisitions, primarily for the Lake
Washington acquisition. The remaining $33.5 million was spent primarily on
leasehold, seismic and geological costs of prospects, both in the United States
and New Zealand. During 2001, we relied upon internally generated cash flows of
$139.9 million to partially fund our capital expenditures; the remainder was
funded with increases in borrowings under our bank credit facility.
Due to falling oil and gas prices in the second half of 2001 and continuing
into 2002, we have again reduced our 2002 capital expenditures budget and intend
on focusing on low risk development drilling on long-lived reserve properties.
Therefore, our 2002 drilling will focus in Lake Washington and on developing our
Rimu and Kauri areas in New Zealand. We anticipate spending approximately $132.5
million in 2002 for capital expenditures, with approximately $50.9 million of
this amount for drilling activity. The TAWN acquisition, which closed in January
2002, accounted for $54.4 million of this budget. This $132.5 million budget
also excludes any property acquisition that may present itself in this low price
environment and also excludes any property sales.
We have increased our proved reserves from 258.7 Bcfe at year-end 1996 to
645.8 Bcfe at year-end 2001, which has resulted in the replacement of 302% of
our production during the same five-year period. In 2001, we increased our
proved reserves by 3%, which replaced 136% of our 2001 production. Our five-year
average reserves replacement costs were $1.26 per Mcfe. Our 2001 production
increased by 6% in relation to 2000 production. We have increased our production
from 19.4 Bcfe at year-end 1996 to 44.8 Bcfe at year-end 2001. Primarily due to
increased production, along with strong 2001 commodity prices, this has resulted
in average annual growth in net cash provided by operating activities of 30% per
year from year-end 1996 to year-end 2001.
4
Domestic Properties
AWP Olmos Area. As of December 31, 2001, we owned approximately 28,562 net
acres in the AWP Olmos area. We have extensive expertise and a long history of
experience with low-permeability, tight-sand formations typical of this area,
having acquired our first acreage there in 1988. These reserves are
approximately 74% gas. At year-end 2001, we owned interests in 496 wells and
were the operator of 492 wells in this area producing gas from the Olmos sand
formation at a depth of approximately 10,000 to 11,500 feet. We own nearly 100%
of the working interests in all wells in which we are the operator.
In 2001, we drilled 11 development wells in the AWP Olmos area, all of
which were successful. At year-end 2001, we had 122 proved undeveloped
locations. Also in 2001, we purchased interests in the AWP Olmos area from
partnerships we manage. Our planned 2002 capital expenditures in this area will
focus on performing fracture extensions and installing coiled tubing velocity
strings.
Brookeland Area. As of December 31, 2001, we owned drilling and production
rights in 127,703 gross acres (79,874 net acres) and 15,000 fee mineral acres in
this area, which contains substantial proved undeveloped reserves. This area was
part of the acquisition from Sonat in 1998 and is located in East Texas near the
border of Louisiana in Jasper and Newton counties. It primarily contains
horizontal wells producing from the Austin Chalk formation. The reserves are
approximately 60% oil and natural gas liquids. In 2001, we drilled or
participated in the drilling of 11 development wells there, all of which were
successful. At year-end 2001, we had 17 proved undeveloped locations in this
area.
Lake Washington Field. As of December 31, 2001, we owned drilling and
production rights in 13,595 net acres in the Lake Washington field. This area is
located in Plaquemines Parish in South Louisiana. The reserves are approximately
95% oil and natural gas liquids. We acquired interests in the Lake Washington
field in March 2001. This field produces oil from multiple Miocene sands ranging
in depth from less than 2,000 feet to greater than 10,000 feet. The field is
located on a salt dome and has produced over 300 million BOE since its
inception. The area around the dome is heavily faulted, thereby creating a large
number of potential traps. Oil and gas from approximately 25 producing wells is
gathered from four platforms located in water depths from 6 to 11 feet, with
drilling and workover operations performed with barge rigs. In 2001, four
development wells and one exploratory well were drilled in the area, all of
which were successful. At year-end 2001, we had 29 proved undeveloped locations
in this field. Our planned 2002 capital expenditures in this area are
approximately $25.0 million and include 20 development wells and two exploratory
wells.
Masters Creek Area. As of December 31, 2001, we owned drilling and
production rights in 194,212 gross acres (149,400 net acres) and 141,000 fee
mineral acres in this area, which contains substantial proved undeveloped
reserves. This area was also part of the acquisition from Sonat in 1998. It is
located in Central Louisiana near the Texas-Louisiana border in the two parishes
of Vernon and Rapides. It contains horizontal wells producing both oil and gas
from the Austin Chalk formation. The reserves are approximately 74% oil and
natural gas liquids. In 2001, we drilled nine development wells in the area, all
of which were successful. At year-end 2001, we had 18 proved undeveloped
locations in the area.
Exploration and Development Drilling Activities
We pursue a "controlled risk" approach to exploratory and development
drilling, focusing our domestic activities on specific regions in which our
technical staff has considerable experience and which are located close to known
producing horizons. In our foreign operations, we chose New Zealand based on its
hydrocarbon potential combined with its political and economic attributes. We
seek to minimize our exploration risk by investing in multiple prospects,
farming out interests to third parties, using advanced technologies, and
drilling in diverse types of geological formations, often in areas with multiple
objectives. We use basin studies to analyze targeted formations based on their
potential size, risk profile, and economic characteristics.
5
In 1991, we began an intensive effort to develop an inventory of
exploration and development drilling prospects, identifying drilling locations
through integrated geological and geophysical studies of our undeveloped acreage
and other prospects. As a result, we added 64.9 Bcfe of proved reserves through
drilling in 1999, 184.7 Bcfe in 2000 (122.5 Bcfe from New Zealand), and 105.8
Bcfe in 2001 (17.4 Bcfe from New Zealand). The 2001 additions were a result of
our development success rate, as 38 of 40 development wells drilled were
successful, while 6 of 13 exploratory wells were successful.
Our development strategy is designed to maximize the value and productivity
of our existing properties through development drilling and recovery methods,
enhancing production results through improved field production techniques,
lowering production costs, and applying our technical expertise and resources to
exploit producing properties efficiently. We utilize various recovery
techniques, which include employing water flooding and acid treatments,
fracturing reservoir rock through the injection of high-pressure fluid, and
inserting coiled tubing velocity strings to enhance and maintain gas flow. We
believe that the application of fracturing technology and coiled tubing over the
years has resulted in significant increases in production and decreases in
completion and operating costs, particularly in our AWP Olmos area. In 2001,
however, as the exploration and production industry rushed to get new projects
into production to take advantage of the commodity prices in the first half of
the year, service sector capacity was constrained and the costs of services
skyrocketed. This, along with increased severance and ad-valorem taxes, caused
our production costs to increase in 2001.
Our exploration and development activities are conducted by our staff of
professionals, including reservoir engineers, geologists, geophysicists,
petrophysicists, landmen, and drilling and production engineers. We believe that
one of the keys to our success has been our team approach, which integrates
multiple disciplines to maximize efficient utilization of information leading to
drillable projects.
We have increasingly used advanced seismic technology to enhance the
results of our drilling and production efforts, including 2-D and 3-D seismic
analysis, amplitude versus offset studies, and detailed formation depletion
studies. We have a number of computer workstations from which seismic data is
analyzed and enhanced with advanced software programs, including Landmark,
Geographix, and SMT workstations. As a result, we have maintained internal
seismic expertise and have compiled an extensive database.
During 1997, we completed our first international seismic acquisition
program in two key areas in New Zealand. In the Rimu prospect, we acquired 30
kilometers (18.7 miles) of 2-D cross-swath data, as well as 14.5 kilometers (9
miles) of 2-D line data in the Tawa prospect, complementing existing 2-D seismic
coverage. Following our 1999 Rimu discovery, we conducted a second seismic
acquisition in March 2000 in which we obtained 42 kilometers (26 miles) of 2-D
lines to more fully identify the extent of the Rimu structure. We also obtained
approximately 72.5 kilometers (45 miles) of data from a number of 2-D
transitional zone seismic lines tied to existing marine and land seismic grids
in order to study the Kauri structure to the southeast of Rimu. During 2001, we
acquired approximately 30 kilometers (18.7 miles) of 2-D line data in PEP 38730,
in which we own a 100% working interest. Further processing and analysis of the
data will continue in 2002.
Also in 1997, we acquired 21 miles of 2-D data in the AWP Olmos area in
south Texas and 51 miles of data in the Fayette County portion of the Giddings
area. Two more prospects in the North Louisiana Salt Basin were shot in the form
of 2-D swaths of approximately 16 miles each. During 1998, we performed two
additional 2-D acquisitions in Fayette County, Texas. In all our current and
future projects, we have an on-going program in which we license existing
seismic data for reprocessing with available new technologies. In certain areas
we also complement existing data with proprietary seismic data designed for
specific geologic targets. This results in an integrated approach to exploration
(multidiscipline data analysis and interpretation) that helped identify a number
of our exploration prospects for 2001.
In addition to operation, development and exploration activities in the AWP
Olmos, Brookeland, Lake Washington and Masters Creek areas, we are currently
pursuing development and exploration activities in the following emerging growth
areas and in New Zealand.
6
The Frio Trend. Swift Energy has been focusing on the deep sands of the
Frio formation (10,000 to 16,000 feet) in an area that straddles the border of
Kenedy County and Willacy County in the southern tip of Texas and is identified
as Garcia Ranch. Retaining a 65% working interest, Swift had two discoveries in
the area in 2001, one in the Rome prospect in Willacy County at a depth of
16,388 feet, and the other in the Siena prospect in Kenedy County at a depth of
16,300 feet.
The Wilcox Sands. The Company had three discoveries in the Wilcox sands
during 2001, two of which were located in Goliad County, Texas: the Nita
prospect drilled to a depth of approximately 15,000 feet and the Brandon
prospect drilled to a depth of about 13,000 feet. Swift's working interests in
the two wells are 73% and 60%, respectively. The third well, in which the
Company has a 25% working interest, was in the Falcon Ridge prospect in Zapata
County, Texas.
The Woodbine Formation. Swift drilled one well to the Woodbine formation
during 2001--in the Lion prospect in San Jacinto County, Texas, down to a depth
of 16,300 feet. Although hydrocarbon-bearing intervals were found, the well was
determined to be noncommercial.
The Miocene Sands. Swift successfully drilled its first exploratory well in
the Miocene sands in its new Lake Washington area in Plaquemines Parish,
Louisiana--to a depth of 3,348 feet with a retained interest of 100%. This area
has substantial exploration and development potential, with sands extending from
shallow depths down to 10,000 feet or more. Current plans are to drill another
exploratory well in the area during 2002.
Also in Plaquemines Parish, about 50 miles north of the Lake Washington
area, is the Delacroix area where the Company has also been developing prospects
for both shallow and deep horizons in the Miocene sands. The first well in this
area, in the Grand Lake prospect, was drilled to a depth of 18,571 feet early in
2002 and was temporarily abandoned for a possible future sidetrack well.
New Zealand. We operate permit 38719 with a 90% working interest. After
working several years and analyzing extensive seismic data, we commenced
drilling a successful exploratory well, the Rimu-A1, in July 1999. In 2000, we
drilled two successful Rimu development wells. Our permit contains 50,300 gross
acres, including 12,800 adjacent offshore acres. In 2001, we drilled three
development wells to further delineate our Rimu area, one of which was
successful. We also drilled two exploratory wells in the Kauri area, one still
being evaluated and the other one unsuccessful. In addition, we drilled one
successful development well in our Kauri area and participated in a non-operated
exploratory well in another permit area that was temporarily abandoned in 2001.
The Tawa prospect is located northwest of the Rimu and Kauri areas in the
same permit. Its main targets are the Tikorangi limestone, the Kauri sandstone,
and the Tariki sandstone. Consisting of a combination of structural and
stratigraphic traps, this prospect was developed based upon Swift's analysis of
existing three-dimensional seismic data plus two-dimensional seismic data
acquired during Company surveys in 1997 and 2000.
The Matai prospect, located on the southeast flank of the Tawa prospect
also in permit 37819, will target the Moki sandstone. It was identified based
upon the analysis of the two-dimensional seismic data Swift acquired in 2000.
7
The following table sets forth the results of our drilling activities
during the three years ended December 31, 2001:
Gross Wells Net Wells
-------------------------------------- --------------------------------------
Temporarily Temporarily
Year Type of Well Total Producing Dry Abandoned Total Producing Dry Abandoned
- ------------------------------------------------------------------------- -------------------------------------
1999 Exploratory-Domestic 3 1 2 -- 1.5 1.2 --
0.3
Development-Domestic 22 19 3 -- 10.7 1.3 --
9.4
Exploratory-New Zealand 2 1 -- 1 1.0 0.9 -- 0.1
2000 Exploratory-Domestic 9 5 4 -- 6.2 3.4 2.8 --
Development-Domestic 59 52 7 -- 42.4 37.1 5.3 --
Development-New Zealand 2 2 -- -- 1.8 1.8 -- --
2001 Exploratory-Domestic 11 6 5 -- 6.2 4.0 2.2 --
Development-Domestic 36 36 -- -- 29.5 29.5 -- --
Exploratory-New Zealand 2 -- 1 1 1.1 -- 0.9 0.2
Development-New Zealand 4 2 2 -- 3.6 1.8 1.8 --
Operations
We generally seek to be operator in the wells in which we have a
significant economic interest. As operator, we design and manage the development
of a well and supervise operation and maintenance activities on a day-to-day
basis. We do not own drilling rigs or other oil field services equipment used
for drilling or maintaining wells on properties we operate. Independent
contractors supervised by us provide all the equipment and personnel. We employ
drilling, production, and reservoir engineers, geologists, and other specialists
who work to improve production rates, increase reserves, and lower the cost of
operating our oil and gas properties.
Oil and gas properties are customarily operated under the terms of a joint
operating agreement. These agreements usually provide for reimbursement of the
operator's direct expenses and for payment of monthly per-well supervision fees.
Supervision fees vary widely depending on the geographic location and depth of
the well and whether the well produces oil or gas. The fees for these activities
paid to us in 2001 ranged from $200 to $2,216 per well per month and totaled
$6.2 million.
Marketing of Production
We typically sell our oil and gas production at market prices near the
wellhead, although in some cases it must be gathered and delivered to a central
point. Gas production is sold in the spot market on a monthly basis, while we
sell our oil production at prevailing market prices. We do not refine any oil we
produce. Two oil or gas purchasers accounted for 10% or more of our total
revenues during the year ended December 31, 2001, with those purchasers
accounting for approximately 29% of revenues in the aggregate. For the year
ended December 31, 2000, two purchasers accounted for approximately 37% of our
total revenues. However, due to the availability of other purchasers, we do not
believe that the loss of any single oil or gas purchaser or contract would
materially affect our revenues.
In 1998, we entered into gas processing and gas transportation agreements
for our gas production in the AWP Olmos area with PG&E Energy Trading
Corporation, which was assumed in December 2000 by El Paso Hydrocarbon, LP, and
El Paso Industrial, LP, both affiliates of El Paso Merchant Energy, for up to
75,000 Mcf per day, which provided for a ten-year term with automatic one-year
extensions unless earlier terminated. We believe that these arrangements
adequately provide for our gas transportation and processing needs in the AWP
Olmos area for the foreseeable future. Additionally, the gas processed and
transported under these agreements may be sold to El Paso based upon current
natural gas prices.
8
Our oil production from the Brookeland and Masters Creek areas is sold to
various purchasers at prevailing market prices. Our gas production from these
areas is processed under long-term gas processing contracts with Duke Energy
Field Services, Inc. The processed liquids and residue gas production are sold
in the spot market at prevailing prices.
Our oil production from the Lake Washington area is delivered into
ExxonMobil's crude oil pipeline system for sales to various purchasers at
prevailing market prices. Our gas production from this area is either consumed
on the lease or is delivered into El Paso's Tennessee Gas Pipeline system and
then sold in the spot market at prevailing prices.
Our oil production in New Zealand is sold into the international market at
prices tied to the Asia Petroleum Price Index Tapis posting, less the cost of
storage, trucking, and transportation.
Our gas production from our TAWN fields, which we acquired and closed on in
January 2002, is sold under a long-term contract with Contact Energy. Upon
commissioning of the Rimu Production Station, our gas production from the Rimu
field will be sold to Genesis Power Ltd. under a long-term contract.
Swift natural gas liquids production from the TAWN fields is sold to
RockGas under long-term contracts tied to New Zealand's domestic natural gas
liquids market. Upon commissioning of the Rimu Production Station, our natural
gas liquids from the Rimu Field also will be sold to RockGas.
The following table summarizes sales volumes, sales prices, and production
cost information for our net oil and gas production for the three-year period
ended December 31, 2001. "Net" production is production that is owned by us
either directly or indirectly through partnerships or joint venture interests
and is produced to our interest after deducting royalty, limited partner, and
other similar interests.
Year Ended December 31,
-------------------------------------------------------------------
2001 2000 1999
------------------- ---------------------- ------------------
Net Sales Volume:
Oil (Bbls) (1) 3,055,374 2,472,014 2,564,924
Gas (Mcf)(2) 26,458,958 27,524,621 27,484,759
Gas equivalents (Mcfe) 44,791,202 42,356,705 42,874,303
Average Sales Price:
Oil (Per Bbl) (1) $ 22.64 $ 29.35 $ 16.75
Gas (Per Mcf) $ 4.23 $ 4.24 $ 2.40
Average Production Cost (per Mcfe) $ 0.82 $ 0.69 $ 0.46
(1) Oil production for 2001 includes New Zealand production of 84,261
barrels, at an average price per barrel of $21.64.
(2) Natural gas production for 2000 and 1999 includes 405,130 and 728,235
Mcf, respectively, delivered under the volumetric production payment agreement
pursuant to which we were obligated to deliver certain monthly quantities of
natural gas (see Note 1 to the Consolidated Financial Statements). Under the
volumetric production payment entered into in 1992, we delivered the last
remaining commitment of gas in October 2000, when such agreement expired.
Acquisition Activities
We use a disciplined, market-driven approach to acquisitions. Generally we
seek to acquire properties with the potential for additional reserves and
production through development and exploration efforts. In 142 transactions from
1979 to 2001, we have acquired approximately $631.5 million of producing oil and
gas properties on behalf of ourselves and our co-investors. We acquired, for our
own account, approximately $275.0 million of producing properties, with original
proved
9
reserves estimated at 394.3 Bcfe. Our producing property acquisition
expenditures in the past three years were $41.3 million in 2001, $34.2 million
in 2000, and $18.5 million in 1999. Our acquisition costs have averaged $0.82
per Mcfe over this three-year period. Our acquisition cost in 2001 averaged
$0.76 per Mcfe. During 2002, we intend to actively look for acquisition
opportunities in this environment of lower commodity prices.
Foreign Activities
New Zealand
Swift Operated Permits. Our activity in New Zealand began in 1995 with the
issuance of the first of two petroleum exploration permits. After surrendering a
portion of our permit acreage in 1998, combining the two permits and expanding
the permit acreage in 1999, and relinquishing 50% of the acreage in 2001 as we
extended our petroleum exploration permit, our permit 38719 as of year-end 2001
covered approximately 50,300 acres in the Taranaki Basin of New Zealand's north
island, with all but 12,800 acres onshore. At December 31, 2001, we had a 90%
working interest in this permit and had fulfilled all current obligations under
this permit.
In late 1999, we completed our first exploratory well on this permit, the
Rimu-A1, and a production test was performed. During the second half of 2000, we
drilled and successfully tested two development wells, the Rimu-B1 and the
Rimu-B2. In 2001 we drilled and tested three more Rimu development wells, the
Rimu-A2, Rimu-A3 and Rimu-B3. The Rimu-A3 was successful; the Rimu-A2 and
Rimu-B3 were dry. Early in 2002, the Rimu-A2 was sidetracked to the Tariki sand
and is currently awaiting completion. The Rimu-B3 was also sidetracked in early
2002 and again was unsuccessful. In 2001, we also drilled the Kauri-A1
exploratory well, the Kauri-A2 development well, and the Kauri-B1 exploratory
well. In the Kauri-A-1 we tested the Upper Tariki sands and still have further
zones to test. The Kauri-A2 well successfully tested the Manutahi sands. The
Kauri-B1 was drilled approximately 1.75 miles to the southeast of the Kauri-A
pad and targeted the Manutahi sands. This well was plugged and abandoned in
2001. Our portion of the drilling, completion, and testing costs incurred on the
wells within our permits during 2001 was approximately $26.0 million. Our
portion of prospect costs on our permits during 2001 was approximately $5.1
million, which included obtaining 2-D seismic data in the last half of the year
for the Rata prospect. We incurred $22.5 million on the production facilities
that we expect to be commissioned near the end of the first quarter of 2002. In
2002, we plan to drill six development wells in the Rimu and Kauri areas, to
participate in a non-operated exploratory well in another permit area, and to
complete production facilities with $24.6 million budgeted to be spent. This
compares to $54.5 million spent in 2001 and $17.4 million spent in 2000.
Our New Zealand production is subject to a royalty which is a hybrid
consisting of a 5% ad valorem royalty, or "AVR," and a 20% accounting profits
royalty, or "APR." Until a mining permit is obtained for our producing area,
only the AVR will apply to all production, and thereafter the royalty will be
the greater of the AVR or APR, calculated on an annual basis. The AVR is based
on net sales revenues. The APR is based on the excess of net sales revenues over
allowable deductions, which deductions include production, capital, and indirect
costs, but not interest or income tax expense or "head office costs" above 2.5%
of other costs. Operating losses and capital costs may be carried forward to
subsequent periods until fully utilized.
In 2000, we entered into an agreement with Fletcher Challenge Energy
Limited whereby we would earn a 25% participating interest in petroleum
exploration permit 38730 containing approximately 48,900 acres. In May 2001,
Fletcher relinquished their interest in the permit, and we then assumed 100%
working interest in such permit by means of committing to an acceptable work
plan. Such plan required us to acquire a minimum of 30 kilometers of new 2D
seismic data, which we completed in 2001. Rather than commit to drill a new well
in 2002 as the work plan called for, we surrendered this project in February
2002.
Non-Operated Permits. In 1998, we entered into agreements for a 25% working
interest in an exploration permit, permit 38712, held by Marabella Enterprises
Ltd., a subsidiary of Bligh Oil & Minerals, an Australian company, and a 7.5%
working interest held by Antrim Oil and Gas Limited, a Canadian company in a
second permit, permit 38716, operated by Marabella. In turn, Bligh and Antrim
each became 5% working interest owners in our permit 38719. Unsuccessful
exploratory wells were
10
drilled on these two permits, and we charged $0.4 million against earnings in
1998 and $0.3 million in 1999. All of the acreage on the permit 38712 was
surrendered in 2000. The exploratory well on permit 38716 has been temporarily
abandoned pending a further evaluation. It is currently anticipated that this
well will be re-entered and sidetracked to target a location to the west of the
initial well. A five-year extension was granted on permit 38716 in 2001 upon the
surrender of 50% of the acreage.
In 2000, we entered into an agreement with Fletcher Challenge Energy
Limited whereby we will earn a 20% participating interest in petroleum
exploration permit 38718 containing approximately 57,400 acres. In January 2001,
the operator temporarily abandoned the Tuihu #1 exploratory well on permit 38718
pending further analysis. The permit now contains approximately 28,700 acres
after a scheduled surrender during December 2000.
Costs Incurred. During 2001, our costs incurred in New Zealand totaled
$54.5 million, including $25.7 million for drilling, $5.5 million for prospect
costs, $22.5 million for production facilities, and $0.8 million in evaluation
costs for the acquisition of the TAWN assets, which closed in January 2002.
These costs also included $0.6 million of costs incurred on permits operated by
others: $0.2 million of drilling costs and $0.4 million of prospect costs. As of
December 31, 2001, our investment in New Zealand totaled approximately $84.4
million. As we have recorded proved undeveloped reserves relating to our
successful drilling activities, $45.5 million of our investment costs has been
included in the proved properties portion of oil and gas properties and $38.8
million has been included as unproved properties at the end of 2001. Our
development strategy includes having Rimu/Kauri production on line for oil and
gas sales in New Zealand near the end of the first quarter of 2002.
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. We retain a minimum 6% net
profits interest from the sale of hydrocarbon products from the fields. The
value of our net profits interest depends upon either the successful development
of production from the fields by others or their sale of the fields.
Oil and Gas Reserves
The following table presents information regarding proved reserves of oil
and gas attributable to our interests in producing properties as of December 31,
2001, 2000, and 1999. The information set forth in the table regarding reserves
is based on proved reserves reports prepared by us and audited by H. J. Gruy and
Associates, Inc., Houston, Texas, independent petroleum engineers. Gruy's audit
was based upon review of production histories and other geological, economic,
ownership, and engineering data provided by Swift.
In accordance with Securities and Exchange Commission guidelines, estimates
of future net revenues from our proved reserves and the PV-10 Value must be made
using oil and gas sales prices in effect as of the dates of such estimates and
are held constant throughout the life of the properties, except where such
guidelines permit alternate treatment, including, in the case of gas contracts,
the use of fixed and determinable contractual price escalations. Proved reserves
as of December 31, 2001, were estimated based upon prices in effect at year-end.
The weighted averages of such year-end prices domestically were $2.68 per Mcf of
natural gas and $18.51 per barrel of oil, compared to $11.25 and $25.50 at
year-end 2000 and $2.58 and $23.69 at year-end 1999. The weighted averages of
such year-end 2001 prices for New Zealand were $1.18 per Mcf of natural gas and
$18.25 per barrel of oil, compared to $0.71 and $22.30 in 2000. The weighted
averages of such year-end 2001 prices for all our reserves, both domestically
and in New Zealand, were $2.51 per Mcf of natural gas and $18.45 per barrel of
oil, compared to $9.86 and $24.62 in 2000. We have interests in certain tracts
that are estimated to have additional hydrocarbon reserves that cannot be
classified as proved and are not reflected in the following table. The proved
reserves presented for all periods also exclude any reserves attributable to the
volumetric production payment that was in effect in 2000 and 1999.
11
The table sets forth estimates of future net revenues presented on the
basis of unescalated prices and costs in accordance with criteria prescribed by
the Securities and Exchange Commission and their PV-10 Value. Operating costs,
development costs, and certain production-related taxes were deducted in
arriving at the estimated future net revenues. No provision was made for income
taxes. The estimates of future net revenues and their present value differ in
this respect from the standardized measure of discounted future net cash flows
set forth in Supplemental Information to our Consolidated Financial Statements,
which is calculated after provision for future income taxes
Year Ended December 31, 2001
---------------------------------------------------------------
Total Domestic New Zealand
---------------------- ----------------- -------------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed 181,651,578 167,401,736 14,249,842
Proved undeveloped 143,260,547 121,087,764 22,172,783
---------------------- ------------------ ------------------
Total 324,912,125 288,489,500 36,422,625
====================== ================== ==================
Net oil reserves (Bbl):
Proved developed 23,759,574 20,393,142 3,366,432
Proved undeveloped 29,723,062 22,171,591 7,551,471
---------------------- ------------------ ------------------
Total 53,482,636 42,564,733 10,917,903
====================== ================== ==================
Estimated Present Value of Proved Reserves
Estimated present value of future net cash flows from
proved
reserves discounted at 10% annum:
Proved developed $ 344,478,834 $ 306,095,381 $ 38,383,453
Proved undeveloped 258,507,354 186,012,413 72,494,941
---------------------- ------------------ ------------------
Total $ 602,986,188 $ 492,107,794 $ 110,878,394
====================== ================== ==================
Year Ended December 31, 2000
---------------------------------------------------------------
Total Domestic New Zealand
---------------------- ----------------- -------------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed 215,169,833 215,169,833 --
Proved undeveloped 203,444,143 148,130,666 55,313,477
---------------------- ------------------ ------------------
Total 418,613,976 363,300,499 55,313,477
====================== ================== ==================
Net oil reserves (Bbl):
Proved developed 10,980,196 10,980,196 --
Proved undeveloped 24,153,400 12,962,513 11,190,887
---------------------- ------------------ ------------------
Total 35,133,596 23,942,709 11,190,887
====================== ================== ==================
Estimated Present Value of Proved Reserves
Estimated present value of future net cash flows from
proved
reserves discounted at 10% annum:
Proved developed $ 1,257,570,764 $ 1,257,570,764 $ --
Proved undeveloped 1,055,684,045 919,388,009 136,296,036
---------------------- ------------------ ------------------
Total $ 2,313,254,809 $ 2,176,958,773 $ 136,296,036
====================== ================== ==================
12
Year Ended December 31, 1999
---------------------------------------------------------------
Total Domestic New Zealand
---------------------- ------------------ -------------------
Estimated Proved Oil and Gas Reserves
Net natural gas reserves (Mcf):
Proved developed 174,046,096 174,046,096 --
Proved undeveloped 155,913,654 155,913,654 --
---------------------- ------------------ ------------------
Total 329,959,750 329,959,750 --
====================== ================== ==================
Net oil reserves (Bbl):
Proved developed 8,437,299 8,437,299 --
Proved undeveloped 12,368,964 12,368,964 --
---------------------- ------------------ ------------------
Total 20,806,263 20,806,263 --
====================== ================== ==================
Estimated Present Value of Proved Reserves
Estimated present value of future net cash flows from
proved
reserves discounted at 10% annum:
Proved developed $ 301,199,660 $ 301,199,660 $ --
Proved undeveloped 262,854,849 262,854,849 --
---------------------- ------------------ ------------------
Total $ 564,054,509 $ 564,054,509 $ --
====================== ================== ==================
At year-end 2001, 50% of the proved reserves were developed reserves. At
year-end 2000, 45% of proved reserves were developed.
Changes in quantity estimates and the estimated present value of proved
reserves are affected by the change in crude oil and natural gas prices at the
end of each year. While our total proved reserves quantities, on an equivalent
Bcfe basis, at year-end 2001 increased by 3% over reserves quantities a year
earlier, the PV-10 Value of those reserves decreased 74% from the PV-10 Value at
year-end 2000. This decrease in prices resulted in 47.1 Bcfe of downward reserve
revision, solely attributed to the decrease in prices used in 2001. Our total
proved reserves quantities at year-end 2000 increased by 38% over reserves
quantities a year earlier, while the PV-10 Value of those reserves increased
310% from the PV-10 Value at year-end 1999. The PV-10 Value decrease in 2001 and
the PV-10 increase in 2000 were heavily influenced by pricing decreases at
year-end 2001 as compared to year-end 2000 and by pricing increases from
year-end 2000 as compared to year-end 1999. Product prices for natural gas
decreased 75% during 2001, from $9.86 per Mcf at December 31, 2000, to $2.51 per
Mcf at year-end 2001, while oil prices decreased 25% between the two dates, from
$24.62 to $18.45 per barrel. Product prices for natural gas increased 282%
during 2000, from $2.58 per Mcf at December 31, 1999, to $9.86 per Mcf at
year-end 2000, while oil prices increased 4% between the two dates, from $23.69
to $24.62 per barrel. Product prices for natural gas increased 16% during 1999,
from $2.23 per Mcf at December 31, 1998, to $2.58 per Mcf at year-end 1999,
matched by a 111% increase in the price of oil between the two dates, from
$11.23 to $23.69 per barrel.
Proved reserves are estimates of hydrocarbons to be recovered in the
future. Reservoir engineering is a subjective process of estimating the sizes of
underground accumulations of oil and gas that cannot be measured in an exact
way. The accuracy of any reserves estimate is a function of the quality of
available data and of engineering and geological interpretation and judgment.
Reserves reports of other engineers might differ from the reports contained
herein. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimates. Future prices received for
the sale of oil and gas may be different from those used in preparing these
reports. The amounts and timing of future operating and development costs may
also differ from those used. Accordingly, reserves estimates are often different
from the quantities of oil and gas that are ultimately recovered. There can be
no assurance that these estimates are accurate predictions of the present value
of future net cash flows from oil and gas reserves.
A portion of our proved reserves has been accumulated through our interests
in the limited partnerships for which we serve as general partner. The estimates
of future net cash flows and their present values, based on period end prices,
assume that some of the limited partnerships in which we
13
own interests will achieve payout status in the future. At December 31, 2001, 32
of the limited partnerships managed by us had achieved payout status.
No other reports on our reserves have been filed with any federal agency.
Oil and Gas Wells
As we continue to liquidate partnerships for those partnerships which voted
to do so, our total well count decreased. Acquisitions such as Lake Washington,
where we own nearly a 100% interest in all operated wells, have increased well
ownership on a net basis. The following table sets forth the gross and net wells
in which we owned an interest at the following dates:
Total
Oil Wells Gas Wells Wells(1)
---------- ----------- -----------
December 31, 2001:
Gross 396 786 1,182
Net 297.0 467.9 764.9
December 31, 2000:
Gross 599 904 1,503
Net 165.2 484.7 649.9
December 31, 1999:
Gross 577 947 1,524
Net 105.5 449.2 554.7
(1) Excludes 48 service wells in 2001, 25 service wells in 2000, and 33 service
wells in 1999. Also excludes 5 wells in 2001 and 3 wells in 2000 in New
Zealand that were temporarily shut-in awaiting the commissioning of the
Rimu Production Station.
Oil and Gas Acreage
As is customary in the industry, we generally acquire oil and gas acreage
without any warranty of title except as to claims made by, through, or under the
transferor. Although we have title to developed acreage examined prior to
acquisition in those cases in which the economic significance of the acreage
justifies the cost, there can be no assurance that losses will not result from
title defects or from defects in the assignment of leasehold rights. In many
instances, title opinions may not be obtained if in our judgment it would be
uneconomical or impractical to do so.
The following table sets forth the developed and undeveloped leasehold
acreage held by us at December 31, 2001:
Developed (1) Undeveloped (1)
Gross Net Gross Net
------------- ------------- ------------- ------------
Alabama 10,091.69 2,861.81 775.72 291.86
Arkansas 762.00 557.57 2,040.15 679.48
Kansas --- --- 4,520.00 1,908.80
Louisiana 135,147.70 92,488.90 138,532.41 89,803.71
Mississippi 730.00 176.00 --- ---
Texas 232,257.73 145,162.59 96,816.92 64,807.04
Wyoming 522.49 120.19 84,211.97 74,997.20
All other states --- --- 5,928.45 981.43
Offshore Louisiana 4,609.37 276.56 25,000.00 1,535.62
Offshore Texas 14,400.00 1,600.79 450.00 23.25
------------- ------------- ------------- ------------
Total-Domestic 398,520.98 243,244.41 358,275.62 235,028.39
New Zealand (2) 24,900.79 22,410.71 135,458.82 79,552.21
------------- ------------- ------------- ------------
Total 423,421.77 265,655.12 493,734.44 314,580.60
============= ============= ============= ============
14
(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 114,655 undeveloped fee mineral
acres for a total of 141,000 fee mineral acres.
(2) Excludes 24,602 gross, and 23,805 net acres acquired in the TAWN
acquisition that closed in January 2002, as well as 2,478 net acres
acquired in the Antrim acquisition which closed in March 2002.
Partnerships
Prior to 1995, we funded a substantial portion of our operations through
109 limited partnerships which we formed and for which we have served as
managing general partner. These partnerships raised a total of $509.5 million of
capital, with the largest portion (81%) raised to acquire interests in producing
properties. Eight of the earliest partnerships and 13 of the most recently
formed partnerships were created to drill for oil and gas. In all of these
partnerships Swift paid for varying percentages of the capital or front-end
costs and continuing costs of the partnerships and, in return, received
differing percentage ownership interests in the partnerships, along with
reimbursement of costs and/or payment of certain fees. At year-end 2001, we
continued to serve as managing general partner of 71 of these various
partnerships, of which 65 are production purchase partnerships that have been in
existence from six to fifteen years and the remainder are drilling partnerships
that have been in existence from three to five years.
During 1997 and 1998, eight drilling partnerships formed between 1979 and
1985 and 21 of the production purchase partnerships sold their properties and
were dissolved, in each case following a vote of the investors in the particular
partnerships approving such liquidations. Between 1999 and 2001, the investors
in all but six of the remaining partnerships voted to sell the properties or
their interests in the partnerships and dissolve. During 2001, seven drilling
partnerships and two production purchase partnerships were dissolved. We
anticipate that the liquidation and dissolution of the additional 65
partnerships should be substantially completed by the end of 2002. The remaining
six partnerships will continue to operate until their limited partners vote
otherwise.
Risk Management
Our operations are subject to all of the risks normally incident to the
exploration for and the production of oil and gas, including blowouts,
cratering, pipe failure, casing collapse, oil spills, and fires, each of which
could result in severe damage to or destruction of oil and gas wells, production
facilities or other property, or individual injuries. The oil and gas
exploration business is also subject to environmental hazards, such as oil
spills, gas leaks, and ruptures and discharges of toxic substances or gases that
could expose us to substantial liability due to pollution and other
environmental damage. Additionally, as managing general partner of limited
partnerships, we are solely responsible for the day-to-day conduct of the
limited partnerships' affairs and accordingly have liability for expenses and
liabilities of the limited partnerships. We maintain comprehensive insurance
coverage, including general liability insurance in an amount not less than $50.0
million, as well as general partner liability insurance. We believe that our
insurance is adequate and customary for companies of a similar size engaged in
comparable operations, but losses could occur for uninsurable or uninsured risks
or in amounts in excess of existing insurance coverage.
Competition
We operate in a highly competitive environment, competing with major
integrated and independent energy companies for desirable oil and gas
properties, as well as for equipment, labor and materials required to develop
and operate such properties. Many of these competitors have financial and
technological resources substantially greater than ours. The market for oil and
gas properties is highly competitive and we may lack technological information
or expertise available to other bidders. We may incur higher costs or be unable
to acquire and develop desirable properties at costs we consider reasonable
because of this competition.
15
Regulations
Environmental Regulations
Our exploration, production and marketing operations are regulated
extensively at the International, federal and state and local levels. These
regulations affect the costs, manner and feasibility of our operations. As an
owner of oil and gas properties, we are subject to international, federal, state
and local regulation of discharge of materials into, and protection of, the
environment. We have made and will continue to make significant expenditures in
our efforts to comply with the requirements of these environmental regulations,
which may impose liability on us for the cost of pollution clean-up resulting
from operations, subject us to liability for pollution damages and require
suspension or cessation of operations in affected areas. Changes in or additions
to regulations regarding the protection of the environment could increase our
compliance costs and might hurt our business.
We are subject to state and local regulations domestically and are subject
to New Zealand regulations that impose permitting, reclamation, land use,
conservation and other restrictions on our ability to drill and produce. These
laws and regulations can require well and facility sites to be closed and
reclaimed. We frequently buy and sell interests in properties that have been
operated in the past, and as a result of these transactions we may retain or
assume clean-up or reclamation obligations for our own operations or those of
third parties.
Federal and State 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. 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.
Federal Leases
Some of our properties are located on federal oil and gas leases
administered by various federal agencies, including the Bureau of Land
Management. Various regulations and orders affect the terms of leases,
exploration and development plans, methods of operation, and related matters.
Employees
At December 31, 2001, we employed 209 persons. None of those employees were
represented by a union. Relations with employees are considered to be good.
Facilities
We occupy approximately 91,000 square feet of office space at 16825
Northchase Drive, Houston, Texas, under a ten-year lease expiring in 2005. The
lease requires payments of approximately $116,000 per month. We have field
offices in various locations from which our employees supervise local oil and
gas operations.
16
Glossary of Abbreviations and Terms
The following abbreviations and terms have the indicated meanings when used in
this report:
Bbl -- Barrel or barrels of oil.
Bcf -- Billion cubic feet of natural gas.
Bcfe -- Billion cubic feet of natural gas equivalent (see Mcfe).
BOE -- Barrels of oil equivalent.
Development Well -- A well drilled within the presently proved productive area
of an oil or natural gas reservoir, as indicated by reasonable interpretation
of available data, with the objective of completing in that reservoir.
Discovery Cost -- With respect to proved reserves, a three-year average (unless
otherwise indicated) calculated by dividing total incurred exploration and
development costs (exclusive of future development costs) by net reserves
added during the period through extensions, discoveries, and other additions.
Dry Well -- An exploratory or development well that is not a producing well.
Exploratory Well -- A well drilled either in search of a new, as yet
undiscovered oil or natural gas reservoir or to greatly extend the known
limits of a previously discovered reservoir.
Gigajoules -- A unit of energy equivalent to .95 Mcf of 1,000 Btu of natural
gas.
Gross Acre -- An acre in which a working interest is owned. The number of gross
acres is the total number of acres in which a working interest is owned.
Gross Well -- A well in which a working interest is owned. The number of gross
wells is the total number of wells in which a working interest is owned.
MBbl -- Thousand barrels of oil.
Mcf -- Thousand cubic feet of natural gas.
Mcfe -- Thousand cubic feet of natural gas equivalent, which is determined using
the ratio of one barrel of oil, condensate, or natural gas liquids to 6 Mcf
of natural gas.
MMBbl -- Million barrels of oil.
MMBtu -- Million British thermal units, which is a heating equivalent measure
for natural gas and is an alternate measure of natural gas reserves, as
opposed to Mcf, which is strictly a measure of natural gas volumes.
Typically, prices quoted for natural gas are designated as price per MMBtu,
the same basis on which natural gas is contracted for sale.
MMcf -- Million cubic feet of natural gas.
MMcfe -- Million cubic feet of natural gas equivalent (see Mcfe).
NetAcre -- A net acre is deemed to exist when the sum of fractional working
interests owned in gross acres equals one. The number of net acres is the sum
of fractional working interests owned in gross acres expressed as whole
numbers and fractions thereof.
17
NetWell -- A net well is deemed to exist when the sum of fractional working
interests owned in gross wells equals one. The number of net wells is the sum
of fractional working interests owned in gross wells expressed as whole
numbers and fractions thereof.
NGL -- Natural gas liquid.
Petajoules -- A unit of energy equivalent to .95 Bcf of 1,000 Btu of natural
gas.
Producing Well -- An exploratory or development well found to be capable of
producing either oil or natural gas in sufficient quantities to justify
completion as an oil or natural gas well.
Proved Developed Oil and Gas Reserves -- Reserves that can be expected to be
recovered through existing wells with existing equipment and operating
methods.
Proved Oil and Gas Reserves -- The estimated quantities of crude oil, natural
gas, and natural gas liquids that geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, that is, prices
and costs as of the date the estimate is made.
Proved Undeveloped Oil and Gas Reserves -- Reserves that are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion.
Proved Undeveloped (PUD) Locations -- A location containing proved undeveloped
reserves. Proved undeveloped oil and gas reserves are reserves that are
expected to be recovered from new wells on undrilled acreage or from existing
wells where a relatively major expenditure is required for recompletion.
PV-10 Value -- The estimated future net revenues to be generated from the
production of proved reserves discounted to present value using an annual
discount rate of 10%. These amounts are calculated net of estimated
production costs and future development costs, using prices and costs in
effect as of a certain date, without escalation and without giving effect to
non-property related expenses, such as general and administrative expenses,
debt service, future income tax expense, or depreciation, depletion, and
amortization.
Reserves Replacement Cost -- With respect to proved reserves, a three-year
average (unless otherwise indicated) calculated by dividing total incurred
acquisition, exploration, and development costs (exclusive of future
development costs) by net reserves added during the period.
SFAS-- Statement of Financial Accounting Standards.
TAWN -- New Zealand producing properties acquired by Swift in January 2002. TAWN
is comprised of the Tariki, Ahuroa, Waihapa and Ngaere fields.
Volumetric Production Payment -- The 1992 agreement pursuant to which we
financed the purchase of certain oil and natural gas interests and committed
to deliver certain monthly quantities of natural gas.
18
Item 3. Legal Proceedings
No material legal proceedings are pending other than ordinary, routine
litigation incidental to the Company's business.
Item 4. Submission of Matters to a Vote of Security Holders
No matters were submitted during the fourth quarter of 2001 to a vote of
security holders.
PART II
Item 5. Market for the Registrant's Common Equity and Related Stockholder
Matters
COMMON STOCK, 2000 AND 2001
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 2000 and 2001 were as follows:
2000 2001
------------------------------------- ---------------------------------
First Second Third Fourth First Second Third Fourth
Quarter Quarter Quarter Quarter Quarter Quarter Quarter Quarter
------------------------------------- ----------------------------------
Low $9.75 $15.00 $20.38 $28.81 $28.91 $27.70 $19.00 $16.66
High $17.88 $29.56 $41.88 $43.50 $37.50 $37.70 $32.55 $25.14
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 383 stockholders of record as of December 31, 2001.
19
Item 6. Selected Financial Data
2001 2000 1999 1998 1997
Revenues
Oil and Gas Sales $181,184,635 $189,138,947 $108,898,696 $80,067,837 $69,015,189
Fees and Earned Interests(2) $427,583 $331,497 $229,749 $333,940 $745,856
Interest Income $49,281 $1,339,386 $833,204 $107,374 $2,395,406
Other, Net $2,145,991 $815,116 $709,358 $1,960,070 $2,555,729
Total Revenues $183,807,490 $191,624,946 $110,671,007 $82,469,221 $74,712,180
Operating Income (Loss) ($ 34,192,333) $93,079,346 $29,736,151 ($73,391,581) $33,129,606
Net Income (Loss) ($22,347,765) $59,184,008 $19,286,574 ($48,225,204) $22,310,189
Net Cash Provided by Operating Activities $139,884,255 $128,197,227 $73,603,426 $54,249,017 $55,255,965
Per Share Data
Weighted Average Shares Outstanding(3) 24,732,099 21,244,684 18,050,106 16,436,972 16,492,856
Earnings (Loss) per Share--Basic(3) ($0.90) $2.79 $1.07 ($2.93) $1.35
Earnings (Loss) per Share--Diluted(3) ($0.90) $2.51 $1.07 ($2.93) $1.26
Shares Outstanding at Year-End 24,795,564 24,608,344 20,823,729 16,291,242 16,459,156
Book Value per Share $12.61 $13.50 $8.18 $6.71 $9.69
Market Price(3)
High $37.70 $43.50 $13.31 $21.00 $34.20
Low $16.66 $9.75 $5.69 $6.94 $16.93
Year-End Close $20.20 $37.63 $11.50 $7.38 $21.06
Pro forma amounts assuming 1994 change in
Accounting principle is applied retroactively(2)
Net Income (Loss) ($22,347,765) $59,184,008 $19,286,574 ($48,225,204) $22,310,189
Earnings (Loss) per Share--Basic (3) ($0.90) $2.79 $1.07 ($2.93) $1.35
Earnings (Loss) per Share--Diluted (3) ($0.90) $2.51 $1.07 ($2.93) $1.26
Assets
Current Assets $36,752,980 $41,872,879 $50,605,488 $35,246,431 $29,981,786
Oil and Gas Properties, Net of Accumulated
Depreciation, Depletion, and Amortization $628,304,060 $524,052,828 $392,986,589 $356,711,711 $301,312,847
Total Assets $671,684,833 $572,387,001 $454,299,414 $403,645,267 $339,115,390
Liabilities
Current Liabilities $73,245,335 $64,324,771 $34,070,085 $31,415,054 $28,517,664
Long-Term Debt $258,197,128 $134,729,485 $239,068,423 $261,200,000 $122,915,000
Total Liabilities $359,032,113 $240,232,846 $283,895,297 $294,282,628 $179,714,470
Stockholders' Equity $312,652,720 $332,154,155 $170,404,117 $109,362,639 $159,400,920
Number of Employees 209 181 173 203 194
Producing Wells
Swift Operated 854 817 769 836 650
Outside Operated 381 711 788 917 917
Total Producing Wells 1,235 1,528 1,557 1,753 1,567
Wells Drilled (Gross) 53 70 27 75 182
Proved Reserves
Natural Gas (Mcf) 324,912,125 418,613,976 329,959,750 352,400,835 314,305,669
Oil, NGL, & Condensate (barrels) 53,482,636 35,133,596 20,806,263 13,957,925 7,858,918
Total Proved Reserves (Mcf equivalent) 645,807,939 629,415,552 454,797,327 436,148,385 361,459,177
Production (Mcf equivalent)(4) 44,791,202 42,356,705 42,874,303 39,030,030 25,393,744
Average Sales Price
Natural Gas (per Mcf) $4.23 $4.24 $2.40 $2.08 $2.68
Oil (per barrel) $22.64 $29.35 $16.75 $11.86 $17.59
1)Additional 1994 Data: Income Before Cumulative Effect of Change in Accounting
Principle-$3,725,671; Cumulative Effect of Change in Accounting
Principle-$(16,772,698); Per Share Amounts-Basic-Income Before Cumulative Effect
of Change in Accounting Principle-$0.51, Cumulative Effect of Change in
Accounting Principle-$(2.29); Per Share Amounts-Diluted-Income Before Cumulative
Effect of Change in Accounting Principle-$0.51, Cumulative Effect of Change in
Accounting Principle-$(2.29).
2)As of January 1, 1994, we changed our revenue recognition policy for earned
interests. Accordingly, in 1994 to 1999, "Fees and Earned Interests" does not
include earned interests revenues.
3)Amounts have been retroactively restated in all periods presented to give
recognition to: (a) an equivalent change in capital structure as a result of two
10% stock dividends, one in September 1994, the other in October 1997 (see Note
2 to the Consolidated Financial Statements); and (b) the adoption in 1998 of
Statement of Financial Accounting Standards No. 128, "Earnings per Share" (see
Note 2 to the Consolidated Financial Statements).
20
4)Natural gas production for 1992, 1993, 1994, 1995, 1996, 1997, 1998, 1999, and
2000 includes 1,148,862, 1,581,206, 1,358,375, 1,211,255, 1,156,361, 1,015,226,
866,232, 728,235, and 405,130 Mcf, respectively, delivered under our volumetric
production payment agreement (see Note 1 to the Consolidated Financial
Statements).
21
1996 1995 1994 (1) 1993 1992 1991
$52,770,672 $22,527,892 $19,802,188 $15,535,671 $12,420,222 $8,361,771
$937,238 $590,441 $701,528 $4,071,970 $2,716,277 $2,231,729
$433,352 $212,329 $47,980 $201,584 $113,387 $192,694
$2,156,764 $1,761,568 $1,072,535 $604,599 $515,931 $541,502
$56,298,026 $25,092,230 $21,624,231 $20,413,824 $15,765,817 $11,327,696
$28,785,783 $6,894,537 $4,837,829 $6,628,608 $4,687,519 $3,748,741
$19,025,450 $4,912,512 ($13,047,027) $4,896,253 $4,084,760 $2,512,815
$37,102,578 $14,376,463 $10,394,514 $7,238,340 $6,349,080 $5,911,588
15,000,901 10,035,143 7,308,673 7,246,884 6,748,548 5,899,629
$1.27 $0.49 ($1.79) $0.68 $0.61 $0.43
$1.25 $0.49 ($1.79) $0.64 $0.61 $0.43
15,176,417 12,509,700 6,685,137 6,001,075 5,968,579 4,955,134
$9.41 $7.46 $6.30 $9.08 $8.26 $7.80
$28.86 $11.48 $10.35 $11.57 $7.85 $9.09
$9.89 $7.05 $7.75 $7.14 $4.65 $4.34
$27.16 $10.91 $8.86 $7.85 $7.55 $4.95
$19,025,450 $4,912,512 $3,725,671 $4,322,478 $3,729,851 $2,950,245
$1.27 $0.49 $0.51 $0.60 $0.55 $0.50
$1.25 $0.49 $0.51 $0.57 $0.55 $0.50
$101,619,478 $43,380,454 $39,208,418 $65,307,120 $30,830,173 $47,859,278
$200,010,375 $125,217,872 $88,415,612 $89,656,577 $64,301,509 $47,655,917
$310,375,264 $175,252,707 $135,672,743 $160,892,917 $100,243,469 $101,421,573
$32,915,616 $40,133,269 $52,345,859 $55,565,437 $27,876,687 $50,851,447
$115,000,000 $28,750,000 $28,750,000 $28,750,000 $0 $0
$167,613,654 $81,906,742 $93,545,612 $106,427,203 $50,962,183 $62,761,217
$142,761,610 $93,345,965 $42,127,131 $54,465,714 $49,281,286 $38,660,356
191 176 209 188 178 171
842 767 750 795 688 674
986 3,316 3,422 3,407 1,978 2,331
1,828 4,083 4,172 4,202 2,666 3,005
153 76 44 34 40 27
225,758,201 143,567,520 76,263,964 64,462,805 41,638,100 36,685,881
5,484,309 5,421,981 4,553,237 4,271,069 2,901,621 1,950,209
258,664,055 176,099,406 103,583,566 90,089,219 59,047,824 48,387,138
19,437,114 11,186,573 9,600,867 7,368,757 5,678,772 3,980,460
$2.57 $1.77 $1.93 $1.96 $1.90 $1.58
$19.82 $15.66 $14.35 $15.10 $17.19 $18.26
22
Item 7. Management's Discussion and Analysis of Financial Condition and Results
of Operations
The following discussion should be read in conjunction with our
Consolidated Financial Statements and Notes thereto.
General
Over the last several years, we have emphasized adding reserves through
drilling activity. We also add reserves through strategic purchases of producing
properties when oil and gas prices are at lower levels and other market
conditions are appropriate. During the past three years, we have used this
flexible strategy of employing both drilling and acquisitions to add more
reserves than we have depleted through production.
Proved Oil and Gas Reserves. At year-end 2001, our total proved reserves
were 645.8 Bcfe with a PV-10 Value of $603.0 million. In 2001, our proved
natural gas reserves decreased 93.7 Bcf, or 22%, while our proved oil reserves
increased 18.3 MMBbl, or 52%, for a total equivalent increase of 16.4 Bcfe, or
3%. From 1999 to 2000, our proved natural gas reserves increased by 88.7 Bcf, or
27%, while our proved oil reserves increased by 14.3 MMBbl, or 69%, for a total
equivalent increase of 174.6 Bcfe, or 38%. We added reserves from 2000 to 2001
through both our drilling activity and through purchases of minerals in place.
Through drilling we added 105.8 Bcfe (17.4 Bcfe of which came from New Zealand)
of proved reserves in 2001, 184.7 Bcfe (122.5 Bcfe of which came from New
Zealand) in 2000, and 64.9 Bcfe in 1999. Through acquisitions we added 54.6 Bcfe
of proved reserves in 2001, 39.7 Bcfe in 2000, and 20.1 Bcfe in 1999. At
year-end 2001, 50% of our total proved reserves were proved developed, compared
with 45% at year-end 2000 and 49% at year-end 1999.
While our total proved reserves quantities increased by 3% during 2001, the
PV-10 Value of those reserves decreased 74%, due to much lower prices at
year-end 2001 than at year-end 2000. Between those two year-ends, there was a
75% decrease in natural gas prices and a 25% decrease in oil prices. This
decrease in prices resulted in 47.1 Bcfe of downward reserve revisions, solely
attributed to the decrease in prices at year-end 2001. Gas prices were $2.51 per
Mcf at year-end 2001, compared to $9.86 per Mcf at year-end 2000. Oil prices
were $18.45 per Bbl at year-end 2001, compared to $24.62 a year earlier. Under
SEC guidelines, estimates of proved reserves must be made using year-end oil and
gas sales prices and are held constant throughout the life of the properties.
Subsequent changes to such year-end oil and gas prices could have a significant
impact on the calculated PV-10 Value. The year-end 2001 gas price of $2.51 was
significantly lower than the average gas price of $4.23 we received during 2001.
The year-end 2001 oil price of $18.45 per barrel was also lower than the average
oil price of $22.64 we received in 2001. Had year-end reserves been calculated
using the average 2001 prices we received, $22.64 for oil and $4.23 for gas, the
PV-10 Value would have been approximately $947.8 million compared to the $603.0
million reported using year-end prices.
Critical Accounting Policies
The following summarizes several of our critical accounting policies. See a
complete list of significant accounting policies in Note 1 to the Consolidated
Financial Statements.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from estimates.
Property and Equipment. We follow the "full-cost" method of accounting for
oil and gas property and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the exploration, development, and
acquisition of oil and gas reserves are capitalized.
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
23
costs should be impaired, our management evaluates, among other factors, 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 income.
Full Cost Ceiling Test. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties, net of related deferred income
taxes, is limited to the sum of the estimated future net revenues from proved
properties using period-end prices, discounted at 10%, and the lower of cost or
fair value of unproved properties, adjusted for related income tax effects
("Ceiling Test"). This calculation is done on a country-by-country basis for
those countries with proved reserves.
The calculation of the Ceiling Test is based on estimates of proved
reserves. There are numerous uncertainties inherent in estimating quantities of
proved reserves and in projecting the future rates of production, timing, and
plan of development. The accuracy of any reserves estimate is a function of the
quality of available data and of engineering and geological interpretation and
judgment. Results of drilling, testing, and production subsequent to the date of
the estimate may justify revision of such estimate. Accordingly, reserves
estimates are often different from the quantities of oil and gas that are
ultimately recovered.
In 2001, as a result of low oil and gas prices at December 31, 2001, we
reported a non-cash write-down on a before-tax basis of $98.9 million ($63.5
million after tax) on our domestic properties. We had no write-down on our New
Zealand properties.
In addition, any unsuccessful exploratory well costs in countries in which
there are no proved reserves are charged to expense as incurred. During the
second quarter of 1999, we charged to income as additional depreciation,
depletion, and amortization costs our portion of drilling costs associated with
an unsuccessful exploratory well drilled by another operator in New Zealand.
This charge was $290,000.
Because of the delineation of our 1999 Rimu discovery with two successful
delineation wells drilled in 2000, proved reserves were recognized in New
Zealand as of December 31, 2000.
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
significantly, even if only for a short period, it is possible that additional
write-downs of oil and gas properties could occur in the future.
Price-Risk Management Activities. In June 1998, the Financial Accounting
Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." The statement establishes accounting and reporting
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or a liability measured at its fair value. SFAS No. 133
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special accounting
for qualifying hedges allows the gains and losses on derivatives to offset
related results on the hedged item in the income statements and requires that a
company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. SFAS No. 133, as amended by SFAS No.
137 and SFAS No. 138, was adopted by us on January 1, 2001.
We have a policy to use derivative instruments, mainly the buying of
protection price floors, to protect against price declines in oil and gas
prices. We elected not to designate our price floors for special hedge
accounting treatment under SFAS No. 133, as amended. However, we have elected to
use mark-to-market accounting treatment for our derivative contracts. Upon
adoption of SFAS No. 133 on January 1, 2001, we recorded a net of taxes charge
of $392,868, which is recorded as a Cumulative Effect of Change in Accounting
Principle. During 2001 we recognized net gains of $1,173,094 relating to our
derivative activities, with $16,784 in unrealized losses at year-end 2001.
24
This activity is recorded in Price-risk management and other, net on the
accompanying statements of income.
At December 31, 2001, we had open price floor contracts covering notional
volumes of 2.0 million MMBtu of natural gas. These natural gas price floor
contracts relate to the NYMEX contract months of February and March 2002 at an
average price of $2.33 per MMBtu. The fair value of our open price floor
contracts at December 31, 2001, totaled $296,000 and is included in Other
current assets on the accompanying balance sheet.
Related-Party Transactions
We are the operator of a number of properties owned by our affiliated
limited partnerships and joint ventures and, accordingly, charge these entities
and third-party joint interest owners operating fees. The operating fees charged
to the partnerships in 2001, 2000, and 1999 totaled approximately $925,000,
$1,775,000, and $1,970,000, respectively. We are also reimbursed for direct,
administrative, and overhead costs incurred in conducting the business of the
limited partnerships, which totaled approximately $3,140,000, $4,465,000, and
$4,000,000 in 2001, 2000, and 1999, respectively. In partnerships in which the
limited partners have voted to sell their remaining properties and liquidate
their limited partnerships, we are also reimbursed for direct, administrative,
and overhead costs incurred in the disposition of such properties, which costs
totaled approximately $2,360,000, $1,220,000, and $850,000 in 2001, 2000, and
1999, respectively.
Contractual Commitments and Obligations
Our contractual commitments for the next four years and thereafter are as
follows:
2002 2003 2004 2005 Thereafter Total
--------------------------------------------------------------------------------
Non-cancelable operating lease commitments $1,393,095 $1,480,092 $1,492,268 $ 248,711 $ --- $ 4,614,166
Senior Notes due August 2009 --- --- --- --- 125,000,000 125,000,000
Credit Facility which expires in October --- --- --- 134,000,000 --- 134,000,000
2005 (1)
--------------------------------------------------------------------------------
$1,393,095 $1,480,092 $1,492,268 $134,248,711 $125,000,000 $263,614,166
================================================================================
1)The repayment of the credit facility is based upon the balance at December 31,
2001. The amount borrowed under this facility has increased from 2001 year-end
levels. This amount excludes $0.8 million of a standby letter of credit issued
under this facility.
Liquidity and Capital Resources
During 2001, we relied both upon internally generated cash flows of $139.9
million and $123.4 million of additional borrowings from our bank credit
facility to fund capital expenditures of $275.1 million. During 2000, we
primarily used internally generated cash flows of $128.2 million to fund capital
expenditures of $173.3 million, along with the remaining net proceeds from our
third quarter 1999 issuance of Senior Notes and common stock.
Net Cash Provided by Operating Activities. In 2001, net cash provided by our
operating activities increased by 9% to $139.9 million, as compared to $128.2
million in 2000 and $73.6 million in 1999. The 2001 increase of $11.7 million
was primarily due to reductions in working capital as oil and gas sales
receivables decreased in 2001 along with a reduction in interest expense of $3.3
million. These increases in cash flow were offset by an $8.0 million reduction
of oil and gas sales, a $7.5 million increase in oil and gas production costs,
and a $2.6 million increase in general and administrative expense. The 2000
increase of $54.6 million was primarily due to $80.2 million of additional oil
and gas sales, partially offset by $12.2 million of increases in oil and gas
production costs and interest expense.
25
Existing Credit Facilities. At December 31, 2001, we had $134.0 million in
outstanding borrowings under our credit facility. Our credit facility at
year-end 2001 consisted of a $250.0 million revolving line of credit with a
$200.0 million borrowing base. The borrowing base is redetermined at least every
six months. Our revolving credit facility includes, among other restrictions,
requirements as to maintenance of certain minimum financial ratios (principally
pertaining to working capital, debt, and equity ratios) and limitations on
incurring other debt. We are in compliance with the provisions of this
agreement. The credit facility extends until October 2005. At December 31, 2000,
we had $10.6 million in outstanding borrowings under this facility.
Subsequent to December 31, 2001, upon the closing of the New Zealand TAWN
acquisition, the credit facility was increased to $300.0 million and the
borrowing base became $275.0 million.
Working Capital. Our working capital decreased from a deficit of $22.5 million
at December 31, 2000, to a deficit of $36.5 million at December 31, 2001. The
decrease was primarily due to reductions in oil and gas sales receivables, as
oil and gas prices were lower at year-end 2001, and an increase in payables to
partnerships related to December 2001 oil and gas property sales.
Capital Expenditures. In 2001, our capital expenditures of approximately $275.1
million included:
Domestic Activities of $224.3 million as follows:
o $120.6 million, or 44%, on developmental drilling;
o $40.5 million, or 15%, for producing properties acquisitions, with
approximately $32.6 million spent on the Lake Washington acquisition and
the remainder for the purchase of property interests from partnerships
managed by us;
o $36.4 million, or 13%, on exploratory drilling;
o $25.3 million, or 9%, on domestic prospect costs, principally leasehold,
seismic, and geological costs;
o $1.1 million, or less than 1%, for fixed assets;
o $0.3 million on field compression facilities; and
o $0.1 million on gas processing plants in the Brookeland and Masters Creek
areas.
New Zealand Activities of $50.8 million as follows:
o $19.0 million, or 7%, on developmental drilling to further delineate the
Rimu and Kauri areas;
o $17.9 million, or 7%, on the Rimu Production Station;
o $7.2 million, or 3%, for exploratory drilling in the Rimu and Kauri
areas;
o $5.5 million, or 2%, on prospect costs, principally seismic and
geological costs;
o $0.8 million, or less than 1%, on producing properties acquisition
evaluation costs related to our TAWN acquisition; and
o $0.4 million for fixed assets, principally computers and office furniture
and fixtures.
In 2001, we participated in drilling 40 development wells and 13
exploratory wells, of which 38 development wells and six exploratory wells were
successes. Four of the development wells were drilled in New Zealand to
delineate the Rimu and Kauri areas, two of which were successful. Two of the
exploratory wells were drilled in New Zealnad; one unsuccessful and one was
temporarily abandoned. Of our $95.9 million of unproved property costs, $72.3
million relates to our inventory of developmental and exploratory acreage to
sustain drilling activity for future growth, while the remaining $23.6 million
pertains to the Rimu Production Station which will be reclassified to proved
properties once it comes on-line near the end of the first quarter of 2002.
Capital expenditures for 2002 are estimated to be approximately $132.5
million. Approximately $39.8 million of the 2002 budget is allocated to domestic
drilling, primarily in the Lake Washington area. In New Zealand, approximately
$11.2 million of the 2002 budget is allocated to drilling, with another $8.7
million expected to be spent primarily for production facilities. In 2002, we
anticipate drilling 20 development wells and 2 exploratory wells domestically,
along with six development wells and one exploratory well in New Zealand.
Approximately $54.6 million is targeted towards producing property acquisitions,
the majority for the TAWN properties in New Zealand that closed in January 2002.
Of the remainder $13.5 million will be used primarily for domestic leasehold,
seismic, and geological costs, and $4.7 million is budgeted for such costs in
New Zealand. This $132.5 million budget also excludes any producing property
acquisitions that may arise in this low price environment
26
and also excludes any property sales. Although we expect our 2002 total
production to incrase by 10% to 20% over 2001 due to the focus of our budget in
the Lake Washington area and in New Zealand, we expect production to decline in
our other core areas as no new drilling is currently budgeted to offset their
natural production decline.
We believe that the anticipated internally generated cash flows for 2002,
together with bank borrowings under our credit facility, will be sufficient to
finance the costs associated with our currently budgeted 2002 capital
expenditures. Should other producing property acquisitions activity become
attractive in the current environment, the Company would intend to explore the
use of debt and or equity offerings to fund such activity.
Our capital expenditures were approximately $173.3 million in 2000 and
$78.1 million in 1999. During 1999, we used internally generated cash flows of
$73.6 million to fund capital expenditures of $78.1 million. During 2000, we
primarily used internally generated cash flows of $128.2 million to fund capital
expenditures of $173.3 million, along with part of the remaining net proceeds
from our third quarter 1999 issuance of Senior Notes and common stock. Our
capital expenditures in 2000 included:
Domestic Activities of $157.9 million as follows:
o $90.3 million, or 52%, on developmental drilling;
o $33.4 million, or 19%, for producing properties acquisitions,
approximately half of which was for the purchase of property interests
from partnerships managed by us, with the other half purchased from a
third party;
o $16.3 million, or 9%, on domestic prospect costs, principally leasehold,
seismic, and geological costs;
o $15.5 million, or 9%, on exploratory drilling;
o $1.4 million, or 1%, for fixed assets;
o $0.8 million, or less than 1%, on gas processing plants in the Brookeland
and Masters Creek areas; and
o $0.2 million on field compression facilities.
New Zealand Activities of $15.4 million as follows:
o $7.6 million, or 4%, on developmental drilling to further delineate the
Rimu area;
o $4.5 million, or 3%, on prospect costs, principally seismic and
geological costs;
o $2.1 million, or 1%, for exploratory drilling;
o $1.1 million, or 1%, on the initial stages of production facilities; and
o $0.1 million, or less than 1%, for fixed assets, principally a field
office and warehouse.
In 2000, we participated in drilling 61 development wells and nine
exploratory wells, of which 54 development wells and five exploratory wells were
successes. Two of the exploratory wells were drilled in New Zealand to delineate
the Rimu area, both of which were successful.
Subsequent Events
TAWN Acquisition. Through our subsidiary, Swift Energy New Zealand Limited,
we acquired Southern Petroleum Exploration Limited ("Southern NZ") in January
2002 for approximately $54.4 million in cash. 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. As of December 31, 2001, the
reserves associated with this acquisition were estimated to be approximately
62.1 Bcfe, all of which were proved developed. This acquisition was accounted
for by the purchase method of accounting. Upon the closing of this acquisition,
our credit facility was increased to $300.0 million, and the borrowing base
became $275.0 million.
In conjunction with the TAWN acquisition, we granted Shell New Zealand a
short-term option to acquire an undivided 25% interest in our permit 38719,
which includes our Rimu and Kauri areas, as well as a 25% interest in our Rimu
Production Station. We do not know if Shell New Zealand will exercise this
option. The option would be subject to numerous notifications, governmental
approvals and consents if exercised. If the option is exercised, our credit
facility would be reduced to $275.0 million and our borrowing base would be
$250.0 million.
27
Antrim Acquisition. We purchased through our subsidiary, Swift Energy New
Zealand Limited, all of the New Zealand assets owned by Antrim Oil and Gas
Limited for 220,000 shares of Swift Energy Company common stock. Antrim owned a
5% interest in permit 38719 and a 7.5% interest in permit 38716. As of December
31, 2001, the reserves associated with this acquisition were estimated to be
approximately 5.7 Bcfe. This transaction closed in March 2002.
Results of Operations
Revenues. Our revenues in 2001 decreased by 4% compared to revenues in 2000
due primarily to decreases in oil prices.
Oil and gas sales revenues in 2001 decreased by 4%, or $8.0 million, from
the level of those revenues for 2000 even though our net sales volumes in 2001
increased by 6%, or 2.4 Bcfe, over net sales volumes in 2000. Average prices
received for oil decreased to $22.64 per Bbl in 2001 from $29.35 per Bbl in
2000. Average gas prices received decreased slightly to $4.23 per Mcf in 2001
from $4.24 per Mcf in 2000.
In 2001, our $8.0 million decrease in oil and gas sales resulted from:
o Price variances that had a $20.6 million unfavorable impact on sales, of
which $20.5 million was attributable to the 23% decrease in average oil
prices received and $0.1 million was attributable to the slight decrease
in average gas prices received; and
o Volume variances that had a $12.6 million favorable impact on sales, with
$17.1 million of increases coming from the 583,000 Bbl increase in oil
sales volumes, offset somewhat by a decrease of $4.5 million from the 1.1
Bcf decrease in gas sales volumes.
Revenues in 2000 increased by 73% compared to 1999 revenues. In 2000, oil
and gas sales revenues increased by 74%, or $80.2 million, over those revenues
in 1999. In 2000, net sales volumes decreased by 1%, or 0.5 Bcfe, compared to
net sales volumes in 1999. Average oil prices received went from $16.75 per Bbl
in 1999 to $29.35 per Bbl in 2000, and average gas prices received increased
from $2.40 per Mcf in 1999 to $4.24 per Mcf in 2000.
In 2000, our $80.2 million increase in oil and gas sales resulted from:
o Price variances that had an $81.7 million favorable impact on sales, of
which $31.1 million was attributable to the 75% increase in average oil
prices received and $50.6 million was attributable to the 77% increase in
average gas prices received; and
o Volume variances that had a $1.5 million unfavorable impact on sales,
with $1.6 million of decreases coming from the 93,000 Bbl decrease in oil
sales volumes, partially offset by an increase of $0.1 million from the
40,000 Mcf increase in gas sales volumes.
The following table provides additional information regarding the changes
in the sources of our oil and gas sales and volumes from our four domestic core
areas and New Zealand:
Revenues Net Sales Volume
(In millions) (Bcfe)
------------------------ --------------------------
Area 2001 2000 2001 2000
----------------- --------- ----------- --------- ----------
AWP Olmos $ 56.1 $ 56.6 13.0 13.5
Brookeland 25.1 20.3 6.5 4.5
Lake Washington 4.6 - 1.2 -
Masters Creek 62.3 89.2 15.3 18.7
Other Domestic 31.3 23.0 8.3 5.7
--------- ----------- --------- ----------
Total Domestic $ 179.4 $ 189.1 44.3 42.4
New Zealand 1.8 - 0.5 -
--------- ----------- --------- ----------
Total $ 181.2 $ 189.1 44.8 42.4
28
Our 2001 drilling activity increased production in the Brookeland area and
stabilized production in the AWP Olmos area, but did not prevent a decline in
production in the Masters Creek area.
The following table provides additional information regarding our oil and
gas sales:
Net Sales Volume Average Sales Price
--------------------------------------- -----------------------
Oil Gas Combined Oil Gas
(MBbl) (Bcf) (Bcfe) (Bbl) (Mcf)
--------- ------- -------------- --------- ---------
1999:
First Qtr. 728 7.2 11.6 $10.87 $1.82
Second Qtr. 644 6.7 10.6 $15.25 $2.05
Third Qtr. 612 6.9 10.5 $18.46 $2.84
Fourth Qtr. 581 6.7 10.2 $23.99 $2.91
--------- ------- --------------
2,565 27.5 42.9 $16.75 $2.40
========= ======= ==============
2000:
First Qtr. 653 6.6 10.6 $27.35 $2.93
Second Qtr. 650 6.9 10.8 $27.55 $3.99
Third Qtr. 591 7.0 10.5 $30.68 $4.39
Fourth Qtr. 578 7.0 10.5 $32.26 $5.55
--------- ------- --------------
2,472 27.5 42.4 $29.35 $4.24
========= ======= ==============
2001:
First Qtr. 603 6.7 10.3 $27.63 $6.86
Second Qtr. 691 7.1 11.3 $26.05 $4.66
Third Qtr. 813 6.8 11.7 $23.76 $2.94
Fourth Qtr. 948 5.9 11.5 $16.02 $2.21
--------- ------- --------------
3,055 26.5 44.8 $22.64 $4.23
========= ======= ==============
Revenues from our oil and gas sales comprised 99% of total revenues for
both 2001 and 2000 and 98% of total revenues for 1999. Natural gas production
made up 59% of our production volumes in 2001, 65% in 2000, and 64% in 1999.
Costs and Expenses. Our general and administrative expenses, net in 2001
increased $2.6 million, or 47%, from the level of such expenses in 2000, while
2000 general and administrative expenses increased $1.1 million, or 24%, over
1999 levels. These increases reflect the increase in our corporate activities
along with a reduction in reimbursement from partnerships we manage as these
continue undergoing planned liquidation as voted upon by their limited partners.
Our general and administrative expenses per Mcfe produced increased to $0.18 per
Mcfe in 2001 from $0.13 per Mcfe in 2000 and $0.10 per Mcfe in 1999. The portion
of supervision fees netted from general and administrative expenses was $3.1
million for 2001, $3.4 million for 2000, and $3.2 million for 1999.
Depreciation, depletion, and amortization of our assets, or DD&A, increased
$11.7 million, or 25%, in 2001 from 2000, while 2000 DD&A increased $5.4
million, or 13%, from 1999 levels. In 2001, the increase was primarily due to
additional dollars spent to add to our reserves and increased associated costs
in an environment where demand for such services had increased compared to 2000,
along with a 6% increase in production. In 2000, the increase was primarily due
to the additional dollars spent to add to our reserves and associated costs in
2000 over 1999. Our DD&A rate per Mcfe of production was $1.33 in 2001, $1.13 in
2000, and $0.99 in 1999, reflecting variations in per unit cost of reserves
additions.
Our production costs in 2001 increased $7.5 million, or 26%, over such
expenses in 2000, while those expenses in 2000 increased $9.6 million, or 49%,
over 1999 costs. Our production costs per Mcfe produced were $0.82 in 2001,
$0.69 in 2000, and $0.46 in 1999. The portion of supervision fees netted from
production costs was $3.1 million for 2001, $3.4 million for 2000, and $3.2
million for 1999. Approximately $1.7 million of the increase in production costs
during 2001 was related to severance taxes. Severance taxes increased primarily
from the expiration of certain specific well severance tax
29
exemptions. The remainder of the increase reflected costs associated with new
wells drilled and acquired and the related increase in costs in procuring such
services in an environment where demand for such services has increased from the
prior year.
While our production costs increased 49% in 2000, our oil and gas sales
increased 74%. That increase in oil and gas sales had a direct impact on the
increase in production costs, as severance taxes have a direct correlation to
sales and were $4.9 million higher in 2000. Also, the increase in commodity
prices brought increased demand and competition for field services that resulted
in an increase in the cost of those services. Remedial well work and workover
costs increased $1.2 million over 1999 levels. In the Masters Creek area,
salt-water disposal charges, which increased $0.4 million over 1999 charges,
increased as the volume of water associated with that production increased. Also
in the Masters Creek area, production chemical costs increased $0.6 million as
we began our scale inhibitor program in that area.
Interest expense on our Senior Notes issued in July 1999, including
amortization of debt issuance costs, totaled $13.1 million in both 2001 and 2000
and $5.3 million in 1999. Interest expense on our Convertible Notes due 2006,
including amortization of debt issuance costs, totaled $7.4 million in 2000 and
$7.5 million in 1999. Interest expense on the credit facility, including
commitment fees and amortization of debt issuance costs, totaled $5.8 million in
2001, $0.7 million in 2000 and $6.1 million in 1999. The total interest expense
in 2001 was $18.9 million, of which $6.3 million was capitalized. The 2000 total
interest expense was $21.2 million, of which $5.2 million was capitalized. The
1999 total interest expense was $18.9 million, of which $4.5 million was
capitalized. We capitalize that portion of interest related to our exploration,
partnership, and foreign business development activities. The decrease in total
interest expense in 2001 was attributed to the conversion and extinguishment of
our Convertible Notes in December 2000 and the increase in capitalized interest,
partially offset by the increase in interest paid on our credit facility. The
increase in interest expense in 2000 was attributed to the replacement of our
bank borrowings in August 1999 with the Senior Notes that carry a higher
interest rate.
In the fourth quarter of 2001, we took a domestic non-cash write-down of
oil and gas properties, as discussed in Note 1 to the Consolidated Financial
Statements. Lower prices for both oil and natural gas at December 31, 2001,
necessitated a pre-tax domestic full-cost ceiling write-down of $98.9 million,
or $63.5 million after tax. In addition to this domestic ceiling write-down, we
also expensed $2.1 million of non-recurring charges in the fourth quarter of
2001 for certain delinquent accounts receivable, the majority of which is
related to gas sold to Enron, and a write-off of debt issuance costs for a
planned offering that was cancelled based upon market conditions following the
events of September 11, 2001.
As discussed in Note 1 to the Consolidated Financial Statements, we adopted
SFAS No. 133, amended by SFAS No. 137 and SFAS No. 138, on January 1, 2001. Our
adoption of SFAS No. 133 resulted in a one-time net of taxes charge of $392,868,
which is recorded as a Cumulative Effect of Change in Accounting Principle on
our Consolidated Statement of Income.
In the fourth quarter of 2000, we recorded a $0.6 million non-recurring
loss on the early extinguishment of debt (net of taxes), as discussed in Note 4
to the Consolidated Financial Statements. We called our Convertible Notes for
redemption effective December 26, 2000. Holders of approximately $100.0 million
of the Convertible Notes elected to convert their notes into shares of our
common stock. Holders of the remaining $15.0 million of the Convertible Notes
elected to redeem their notes for cash plus accrued interest. This cash
redemption resulted in this non-recurring item.
Net Income (Loss). Our loss before extraordinary item and change in
accounting principle in 2001 of $(22.0) million was 137% lower and Basic loss
per share ("Basic EPS") before extraordinary item and change in accounting
principle of $(0.89) was 132% lower than our 2000 net income of $59.8 million
and Basic EPS of $2.82. These decreases reflected the effect of $101.0 million
in non-recurring charges in 2001 as described above. The lower percentage
decrease in Basic EPS reflects a 16% increase in weighted average shares
outstanding in 2001, primarily due to the conversion of our Convertible Notes
into 3.2 million shares of common stock in December 2000.
30
Our net loss for 2001 was $(22.3) million with a loss per share of $(0.90)
per diluted share. Our net income for 2001, excluding non-recurring charges of
$101.0 million as described above, totaled $42.5 million with EPS of $1.67 per
diluted share. These amounts are lower than our 2000 net income of $59.8 million
and EPS of $2.53 per diluted share, primarily due to significantly lower oil
prices and overall increased costs.
Our income before extraordinary item in 2000 of $59.8 million was 210%
higher and Basic EPS before extraordinary item of $2.82 was 164% higher than our
1999 net income of $19.3 million and Basic EPS of $1.07. These increases
reflected the effect of the 75% increase in average oil prices received and 77%
increase in average gas prices received. Oil and gas prices rose each quarter
and resulted in quarterly sequential increases in earnings. The lower percentage
increase in Basic EPS reflects an 18% increase in weighted average shares
outstanding in 2000, primarily due to our third-quarter 1999 public sale of 4.6
million shares of common stock.
Forward Looking Statements
The statements contained in this report that are not historical facts are
forward-looking statements as that term is defined in Section 21E of the
Securities and Exchange Act of 1934, as amended. Such forward-looking statements
may pertain to, among other things, financial results, capital expenditures,
drilling activity, development activities, cost savings, production efforts and
volumes, hydrocarbon reserves, hydrocarbon prices, liquidity, regulatory
matters, and competition. Such forward-looking statements generally are
accompanied by words such as "plan," "future," "estimate," "expect," "budget,"
"predict," "anticipate," "projected," "should," "believe," or other words that
convey the uncertainty of future events or outcomes. Such forward-looking
information is based upon management's current plans, expectations, estimates,
and assumptions, upon current market conditions, and upon engineering and
geologic information available at this time, and is subject to change and to a
number of risks and uncertainties, and, therefore, actual results may differ
materially. Among the factors that could cause actual results to differ
materially are: volatility in oil and natural gas prices, internationally or in
the United States; availability of services and supplies; fluctuations of the
prices received or demand for our oil and natural gas; the uncertainty of
drilling results and reserve estimates; operating hazards; requirements for
capital; general economic conditions; changes in geologic or engineering
information; changes in market conditions; competition and government
regulations; as well as the risks and uncertainties discussed herein, and set
forth from time to time in our other public reports, filings, and public
statements. Also, because of the volatility in oil and gas prices and other
factors, interim results are not necessarily indicative of those for a full
year.
31
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Commodity Risk. Our major market risk exposure is the commodity pricing
applicable to our oil and natural gas production. Realized commodity prices
received for such production are primarily driven by the prevailing worldwide
price for crude oil and spot prices applicable to natural gas. The effects of
such pricing volatility are discussed above, and such volatility is expected to
continue.
Our price risk program permits the utilization of agreements and financial
instruments (such as futures, forward and options contracts, and swaps) to
mitigate price risk associated with fluctuations in oil and natural gas prices.
Below is a description of the financial instruments we have utilized to hedge
our exposure to price risk.
o Price Floors - In 2001 we elected not to designate our price floors for
special hedge accounting treatment, and instead used mark-to-market
accounting treatment. Our adoption of SFAS No. 133, as amended, is
discussed in Note 1 to the Consolidated Financial Statements. Below is a
summary of the utilization of price floors for the years ending December
31, 2001, 2000, and 1999.
o During 2001 we recognized net gains of $1,173,094 related to our hedging
activities, with $16,784 of losses unrealized at year-end 2001. This
activity is recorded in Price-risk management and other, net on the
accompanying statements of income. At December 31, 2001, we had open
price floor contracts covering notional volumes of 2.0 million MMBtu of
natural gas. These contracts relate to the NYMEX contract months of
February and March 2002 at an average price of $2.33 per MMBtu. The fair
value of our open contracts at December 31, 2001, totaled $296,000 and is
included in the Other current assets account on the accompanying balance
sheet.
Prior to adopting SFAS No. 133 in 2001, costs and any benefits derived
from price floors were recorded as a reduction or increase, as
applicable, in oil and gas sales revenues for 2000 and 1999. The costs to
purchase put options were amortized over the option periods in 2000 and
1999.
o The costs related to 2000 hedging activities totaled approximately
$1,083,000, with benefits of approximately $579,000 being received,
resulting in a net cash outlay of approximately $504,000, or $0.012 per
Mcfe. The costs related to the open contracts as of December 31, 2000,
totaled approximately $823,000, which was our maximum exposure under
those contracts. Those open contracts covering production for 2001 had a
fair market value of approximately $209,000 at that date. Each of those
contracts expired on or before March 31, 2001.
o The costs related to 1999 hedging activities totaled approximately
$909,000, with benefits of approximately $348,000 being received,
resulting in a net cash outlay of approximately $561,000, or $0.013 per
Mcfe. The costs related to the open contracts as of December 31, 1999,
totaled approximately $98,000 and had a fair market value of $112,500.
o Participating Collars - During the fourth quarter of 1999, we entered into
participating collars to hedge oil production through June 2000. Below is a
summary of the collar arrangements for 2000. The participating collars were
designated as hedges, and realized losses were recognized in oil and gas
revenues when the associated production occurred.
o We hedged 100,000 Bbls of oil per month for the months January through
June 2000, with a floor price of $19.00 per Bbl and a ceiling price of
$23.60 per Bbl, whereby we participate in 75% of any amount above the
$23.60 ceiling price. These participating collars closed with our
recording a loss of approximately $610,000, or $0.014 per Mcfe produced.
There were no open participating collars at either year-end 2000 or 2001.
Interest Rate Risk. Our Senior Notes have a fixed interest rate, so
consequently we are not exposed to cash flow or fair value risk from market
interest rate changes on our Senior Notes. At December 31, 2001, we had $134.0
million borrowed under our credit facility, which is subject to floating rates
and therefore susceptible to interest rate fluctuations. The result of a 10%
fluctuation in
32
the bank's base rate would constitute 48 basis points and would impact 2002 cash
flows by approximately $0.6 million based on this same level of borrowing.
Financial Instruments & Debt Maturities. Our financial instruments consist
of cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
highly liquid nature of these short-term instruments. The fair values of the
bank borrowings approximate the carrying amounts as of December 31, 2001 and
2000, and were determined based upon interest rates currently available to us
for borrowings with similar terms. Based on quoted market prices as of the
respective dates, the fair value of our Senior Notes was $126.5 million at
December 31, 2001, and $115.1 million at December 31, 2000. Our credit facility
with the banks expires October 1, 2005. Our $125.0 million Senior Notes mature
on August 1, 2009.
33
Item 8. Financial Statements and Supplementary Data
Report of Independent Public Accountants.............................35
Consolidated Balance Sheets..........................................36
Consolidated Statements of Income....................................37
Consolidated Statements of Stockholders' Equity......................38
Consolidated Statements of Cash Flows................................39
Notes to Consolidated Financial Statements...........................40
1. Summary of Significant Accounting Policies.....................40
2. Earnings Per Share.............................................43
3. Provision for Income Taxes.....................................44
4. Long-Term Debt ................................................45
5. Commitments and Contingencies..................................46
6. Stockholders' Equity...........................................47
7. Related-Party Transactions.....................................49
8. Foreign Activities.............................................50
9. Subsequent Events..............................................51
Supplemental Information (Unaudited).................................52
34
Report of Independent Public Accountants
To the Stockholders and Board of Directors of Swift Energy Company:
We have audited the accompanying consolidated balance sheets of Swift
Energy Company (a Texas corporation) and subsidiaries as of December 31, 2001
and 2000, and the related consolidated statements of income, stockholders'
equity, and cash flows for each of the three years in the period ended December
31, 2001. These financial statements are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit includes examining, on a test basis,
evidence supporting the amounts and disclosures in the financial statements. An
audit also includes assessing the accounting principles used and significant
estimates made by management, as well as evaluating the overall financial
statement presentation. We believe that our audits provide a reasonable basis
for our opinion.
In our opinion, the financial statements referred to above present fairly,
in all material respects, the financial position of Swift Energy Company and
subsidiaries as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2001, in conformity with accounting principles generally accepted
in the United States.
ARTHUR ANDERSEN LLP
Houston, Texas
February 18, 2002
35
Consolidated Balance Sheets
Swift Energy Company and Subsidiaries
December 31,
ASSETS 2001 2000
-------------- ---------------
Current Assets:
Cash and cash equivalents $ 2,149,086 $ 1,986,932
Accounts receivable-
Oil and gas sales 14,215,189 26,939,472
Associated limited partnerships and joint ventures 6,259,604 2,685,003
Joint interest owners 11,467,461 7,181,974
Other current assets 2,661,640 3,079,498
------------- ---------------
Total Current Assets 36,752,980 41,872,879
-------------- ---------------
Property and Equipment:
Oil and gas, using full-cost accounting
Proved properties 974,698,428 753,426,124
Unproved properties 95,943,163 55,512,872
-------------- ---------------
1,070,641,591 808,938,996
Furniture, fixtures, and other equipment 8,706,414 8,873,266
-------------- ---------------
1,079,348,005 817,812,262
Less - Accumulated depreciation, depletion, and amortization (448,139,334) (290,725,112)
-------------- ---------------
631,208,671 527,087,150
-------------- ---------------
Other Assets:
Deferred charges 3,723,182 3,426,972
-------------- ---------------
3,723,182 3,426,972
-------------- ---------------
$ 671,684,833 $ 572,387,001
============== ===============
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Accounts payable and accrued liabilities $ 38,884,380 $ 54,977,397
Payable to associated limited partnerships 26,573,490 1,291,787
Undistributed oil and gas revenues 7,787,465 8,055,587
-------------- ---------------
Total Current Liabilities 73,245,335 64,324,771
-------------- ---------------
Long-Term Debt 258,197,128 134,729,485
Deferred Income Taxes 27,589,650 41,178,590
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 and 35,000,000 shares
authorized,25,634,598 and 25,452,148 shares issued, and
24,795,564 and 24,608,344shares outstanding, respectively 256,346 254,521
Additional paid-in capital 296,172,820 293,396,723
Treasury stock held, at cost, 839,034 and 843,804 shares,
respectively (12,032,791) (12,101,199)
Retained earnings 28,256,345 50,604,110
-------------- ---------------
312,652,720 332,154,155
-------------- ---------------
$ 671,684,833 $ 572,387,001
============== ===============
See accompanying Notes to Consolidated Financial Statements.
36
Consolidated Statements of Income
Swift Energy Company and Subsidiaries
Year Ended December 31,
2001 2000 1999
--------------------------------------------------------
Revenues:
Oil and gas sales $ 181,184,635 $ 189,138,947 $ 108,898,696
Fees from limited partnerships and joint ventures 427,583 331,497 229,749
Interest income 49,281 1,339,386 833,204
Price-risk management and other, net 2,145,991 815,116 709,358
---------------- ----------------- --------------
183,807,490 191,624,946 110,671,007
---------------- ----------------- --------------
Costs and Expenses:
General and administrative, net of reimbursement 8,186,654 5,585,487 4,497,400
Depreciation, depletion, and amortization 59,502,040 47,771,393 42,348,901
Oil and gas production 36,719,609 29,220,315 19,645,740
Interest expense, net 12,627,022 15,968,405 14,442,815
Other expenses 2,102,251 --- ---
Write-down of oil and gas properties 98,862,247 --- ---
---------------- ----------------- --------------
217,999,823 98,545,600 80,934,856
---------------- ----------------- --------------
Income (Loss) Before Income Taxes, Extraordinary Item
and Change in Accounting Principle (34,192,333) 93,079,346 29,736,151
Provision (Benefit) for Income Taxes (12,237,436) 33,265,480 10,449,577
---------------- ----------------- --------------
Income (Loss) Before Extraordinary Item and Change $ (21,954,897) $ 59,813,866 $ 19,286,574
In Accounting Principle
Extraordinary Loss on Early Extinguishment of Debt (net of --- 629,858 ---
taxes)
Cumulative Effect of Change in Accounting Principle (net of 392,868 --- ---
taxes)
---------------- ----------------- --------------
Net Income (Loss) $ (22,347,765) $ 59,184,008 $ 19,286,574
================ ================= ==============
Per Share Amounts-
Basic: Income (Loss) Before Extraordinary Item
and Change in Accounting Principle $ (0.89) $ 2.82 $ 1.07
Extraordinary Loss --- (0.03) ---
Change in Accounting Principle (0.01) --- ---
---------------- ----------------- --------------
Net Income (Loss) $ (0.90) $ 2.79 $ 1.07
================ ================= ==============
Diluted: Income (Loss) Before Extraordinary Item $ (0.89) $ 2.53 $ 1.07
and Change in Accounting Principle
Extraordinary Loss --- (0.02) ---
Change in Accounting Principle (0.01) --- ---
---------------- ----------------- --------------
Net Income (Loss) $ (0.90) $ 2.51 $ 1.07
================ ================= ==============
Weighted Average Shares Outstanding 24,732,099 21,244,684 18,050,106
================ ================= ==============
See accompanying Notes to Consolidated Financial Statements.
37
Consolidated Statements of Stockholders' Equity
Swift Energy Company and Subsidiaries
Additional Retained
Common Paid-in Treasury Earnings
Stock (1) Capital Stock (Deficit) Total
---------- -------------- ------------- -------------- --------------
Balance, December 31, 1998 $ 169,725 $ 148,901,270 $ (11,841,884) $ (27,866,472) $ 109,362,639
Stock issued for benefit
plans(90,738 shares) 224 (366,408) 978,956 - 612,772
Stock options exercised
(65,477 shares) 655 461,102 - - 461,757
Employee stock purchase
plan (22,771 shares) 228 181,577 - - 181,805
Public stock offering
(4,600,000 shares) 46,000 41,915,310 - - 41,961,310
Purchase of 246,500 shares
as treasury stock - - (1,462,740) - (1,462,740)
Net income - - - 19,286,574 19,286,574
---------- -------------- ------------- -------------- --------------
Balance, December 31, 1999 $ 216,832 $ 191,092,851 $ (12,325,668) $ (8,579,898) $ 170,404,117
Stock issued for benefit
plans(46,632 shares) 310 297,060 224,469 - 521,839
Stock options exercised
(543,450 shares) 5,434 4,316,446 - - 4,321,880
Employee stock purchase
plan(29,889 shares) 299 297,414 - - 297,713
Subordinated notes
conversion(3,164,644
shares) 31,646 97,392,952 - - 97,424,598
Net income - - - 59,184,008 59,184,008
---------- -------------- ------------- -------------- --------------
Balance, December 31, 2000 $ 254,521 $ 293,396,723 $ (12,101,199) $ 50,604,110 $ 332,154,155
Stock issued for benefit
plans(11,945 shares) 72 354,973 68,408 - 423,453
Stock options exercised
(152,915 shares) 1,529 1,942,634 - - 1,944,163
Employee stock purchase
plan(22,360 shares) 224 478,490 - - 478,714
Net loss - - - (22,347,765) (22,347,765)
---------- -------------- ------------- -------------- --------------
Balance, December 31, 2001 $ 256,346 $ 296,172,820 $ (12,032,791) $ 28,256,345 $ 312,652,720
========== ============== ============= ============== ==============
(1)$.01 par value.
See accompanying Notes to Consolidated Financial Statements.
38
Consolidated Statements of Cash Flows
Swift Energy Company and Subsidiaries
Year Ended December 31,
------------------------------------------------------
2001 2000 1999
----------------- ----------------- ---------------
Cash Flows from Operating Activities:
Net income (loss) $ (22,347,765) $ 59,184,008 $ 19,286,574
Adjustments to reconcile net income (loss) to net cash
provided by operating activities-
Depreciation, depletion, and amortization 59,502,040 47,771,393 42,348,901
Write-down of oil and gas properties 98,862,247 --- ---
Deferred income taxes (12,555,618) 33,413,626 10,435,115
Deferred revenue amortization related to production
payment --- (587,629) (1,056,284)
Other 509,973 1,075,848 628,614
Change in assets and liabilities-
(Increase) decrease in accounts receivable 16,207,377 (14,308,274) (2,889,530)
Increase in accounts payable and accrued
liabilities, excluding income taxes payable 12,984 1,601,042 4,850,036
Increase (decrease) in income taxes payable (306,983) 47,213 ---
----------------- ----------------- ---------------
Net Cash Provided by Operating Activities 139,884,255 128,197,227 73,603,426
----------------- ----------------- ---------------
Cash Flows from Investing Activities:
Additions to property and equipment (275,126,333) (173,277,356) (78,112,550)
Proceeds from the sale of property and equipment 9,274,440 3,844,375 4,531,935
Net cash received as operator of oil and gas properties 5,927,539 19,769,213 5,995,842
Net cash received (distributed) as operator of
partnerships and joint ventures (3,574,601) 2,674,593 (433,114)
Other (534,898) (1,329) (131,135)
----------------- ----------------- ---------------
Net Cash Used in Investing Activities (264,033,853) (146,990,504) (68,149,022)
----------------- ----------------- ---------------
Cash Flows from Financing Activities:
Proceeds from (payments of) long-term debt --- (15,203,000) 124,045,000
Net proceeds from (payments of) bank borrowings 123,400,000 10,600,000 (146,200,000)
Net proceeds from issuances of common stock 1,633,508 2,697,561 42,719,776
Purchase of treasury stock --- --- (1,462,740)
Payments of debt issuance costs (721,756) --- (3,501,441)
----------------- ----------------- ---------------
Net Cash Provided by (Used in) Financing
Activities 124,311,752 (1,905,439) 15,600,595
----------------- ----------------- ---------------
Net Increase (Decrease) in Cash and Cash Equivalents $ 162,154 $ (20,698,716) $ 21,054,999
Cash and Cash Equivalents at Beginning of Year 1,986,932 22,685,648 1,630,649
----------------- ----------------- ---------------
Cash and Cash Equivalents at End of Year $ 2,149,086 $ 1,986,932 $ 22,685,648
================= ================= ===============
Supplemental Disclosures of Cash Flows Information:
Cash paid during year for interest, net of amounts capitalized $ 12,207,205 $ 15,528,280 $ 8,618,020
Cash paid during year for income taxes $ 441,926 $ --- $ ---
Non-Cash Financing Activity:
Conversion of convertible notes to common stock $ --- $ 99,797,000 $ ---
See accompanying Notes to Consolidated Financial Statements.
39
Notes to Consolidated Financial Statements
Swift Energy Company and Subsidiaries
1. Summary of Significant Accounting Policies
Principles of Consolidation. The accompanying consolidated financial
statements include the accounts of Swift Energy Company (Swift) and our wholly
owned subsidiaries, which are engaged in the exploration, development,
acquisition, and operation of oil and natural gas properties, with a focus on
onshore oil and natural gas reserves in Texas and Louisiana, as well as onshore
oil and natural gas reserves in New Zealand. Our investments in associated oil
and gas partnerships and joint ventures are accounted for using the
proportionate consolidation method, whereby our proportionate share of each
entity's assets, liabilities, revenues, and expenses are included in the
appropriate classifications in the consolidated financial statements.
Intercompany balances and transactions have been eliminated in preparing the
consolidated financial statements. Certain reclassifications have been made to
prior year amounts to conform to current year presentation.
Use of Estimates. The preparation of financial statements in conformity
with accounting principles generally accepted in the United States requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and disclosure of contingent assets and liabilities, if
any, at the date of the financial statements and the reported amounts of
revenues and expenses during the reporting period. Actual results could differ
from estimates.
Property and Equipment. We follow the "full-cost" method of accounting for
oil and gas property and equipment costs. Under this method of accounting, all
productive and nonproductive costs incurred in the exploration, development and
acquisition of oil and gas reserves are capitalized. Under the full-cost method
of accounting, such costs may be incurred both prior to or after the acquisition
of a property and include lease acquisitions, geological and geophysical
services, drilling, completion, equipment, and certain general and
administrative costs directly associated with acquisition, exploration, and
development activities. Interest costs related to unproved properties are also
capitalized to unproved oil and gas properties. 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. The proceeds from the sale of oil and gas properties are generally
treated as a reduction of oil and gas property costs. Fees from associated oil
and gas exploration and development limited partnerships are credited to oil and
gas property costs to the extent they do not represent reimbursement of general
and administrative expenses currently charged to expense.
Future development, site restoration, and dismantlement and abandonment
costs, net of salvage values, are estimated property by property based on
current economic conditions, and are amortized to expense as our capitalized oil
and gas property costs are amortized. The vast majority of our properties are
onshore, and historically the salvage value of the tangible equipment offsets
our site restoration and dismantlement and abandonment costs.
We compute the provision for depreciation, depletion, and amortization of
oil and gas properties by the unit-of-production method. Under this method, we
compute the provision by multiplying the total unamortized costs of oil and gas
properties--including future development, site restoration, and dismantlement
and abandonment costs but excluding costs of unproved properties--by an overall
rate determined by dividing the physical units of oil and gas produced during
the period by the total estimated units of proved oil and gas reserves. This
calculation is done on a country-by-country basis. All other equipment is
depreciated by the straight-line method at rates based on the estimated useful
lives of the property. Repairs and maintenance are charged to expense as
incurred. Renewals and betterments are capitalized.
The cost of unproved properties not being amortized is assessed quarterly,
on a country-by-country basis, to determine whether such
40
properties have been impaired. In determining whether such costs should be
impaired, we evaluate, among other factors, 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 income.
Full Cost Ceiling Test. At the end of each quarterly reporting period, the
unamortized cost of oil and gas properties, net of related deferred income
taxes, is limited to the sum of the estimated future net revenues from proved
properties using period-end prices, discounted at 10%, and the lower of cost or
fair value of unproved properties, adjusted for related income tax effects
("Ceiling Test"). This calculation is done on a country-by-country basis for
those countries with proved reserves.
The calculation of the Ceiling Test and provision for depreciation,
depletion, and amortization is based on estimates of proved reserves. There are
numerous uncertainties inherent in estimating quantities of proved reserves and
in projecting the future rates of production, timing, and plan of development.
The accuracy of any reserves estimate is a function of the quality of available
data and of engineering and geological interpretation and judgment. Results of
drilling, testing, and production subsequent to the date of the estimate may
justify revision of such estimate. Accordingly, reserves estimates are often
different from the quantities of oil and gas that are ultimately recovered.
In 2001, as a result of low oil and gas prices at December 31, 2001, we
reported a non-cash write-down on a before-tax basis of $98.9 million ($63.5
million after tax) on our domestic properties. We had no write-down on our New
Zealand properties.
In addition, any unsuccessful exploratory well costs in countries in which
there are no proved reserves are charged to expense as incurred. During the
second quarter of 1999, we charged to income as additional depreciation,
depletion, and amortization costs our portion of drilling costs associated with
an unsuccessful exploratory well drilled by another operator in New Zealand.
This charge was $290,000.
Because of the delineation of our 1999 Rimu discovery with two successful
delineation wells drilled in 2000, proved reserves were recognized in New
Zealand as of December 31, 2000.
Given the volatility of oil and gas prices, it is reasonably possible that
our estimate of discounted future net cash flows from proved oil and gas
reserves could change in the near term. If oil and gas prices decline from the
Company's year-end prices used in the Ceiling Test, even if only for a short
period, it is possible that additional write-downs of oil and gas properties
could occur in the future.
Oil and Gas Revenues. Oil and gas revenues are reported, as the product is
delivered, using the entitlement method in which we recognize our ownership
interest in production as revenue. If our sales exceed our ownership share of
production, the differences are reported as deferred revenues. Natural gas
balancing receivables are reported when our ownership share of production
exceeds sales. As of December 31, 2001, we did not have any material natural gas
imbalances.
Deferred Charges. Legal and accounting fees, underwriting fees, printing
costs, and other direct expenses associated with the public offering in November
1996 of our 6.25% Convertible Subordinated Notes (the "Convertible Notes"), with
the public offering in August 1999 of our 10.25% Senior Subordinated Notes (the
"Senior Notes"), and with our September 2001 extension of our bank credit
facility were capitalized and are amortized over the life of each of the
respective note offerings and credit facility. The Convertible Notes were called
for redemption effective December 26, 2000, and the balance of their unamortized
issuance costs at that time of $3,046,181 was either transferred to the common
stock equity accounts ($2,643,476) for the portion of the Convertible Notes
converted into common stock at the election of those note holders or was
recorded, net of taxes, as Extraordinary Loss on Early Extinguishment of Debt
($402,705) for the portion of the Convertible Notes redeemed for cash. The
Senior Notes mature on August 1, 2009, and the balance of their issuance costs
at December 31, 2001, was $2,956,306, net of accumulated amortization of
$545,135. The issuance costs associated with our revolving credit facility,
which closed in September 2001, have been capitalized and are being amortized
over the original life of the facility. The balance of revolving credit
41
facility issuance costs at December 31, 2001, was $766,876, net of accumulated
amortization of $513,573.
Limited Partnerships and Joint Ventures. We formed 88 limited partnerships
between 1984 and 1995 to acquire interests in producing oil and gas properties
and 13 partnerships between 1993 and 1998 to drill for oil and gas. In all of
these partnerships, Swift paid for varying percentages of the capital or
front-end costs and continuing costs of the partnerships and, in return,
received differing percentage ownership interests in the partnerships, along
with reimbursement of costs and/or payment of certain fees. At year-end 2001, we
continue to serve as managing general partner of 71 of these various
partnerships, and during fiscal 2001 approximately 2.9% of our total oil and gas
sales was attributable to our interests in those partnerships.
During 1997 and 1998, eight drilling partnerships formed between 1979 and
1985 and 21 of the production purchase partnerships sold their properties and
were dissolved, in each case following a vote of the investors in the particular
partnerships approving such liquidations. Between 1999 and 2001, the investors
in all but six of the remaining partnerships voted to sell the properties or
their interests in the partnerships and dissolve. During 2001, seven drilling
partnerships and two production purchase partnerships were dissolved. We
anticipate that the liquidation and dissolution of the additional 65
partnerships will be completed by the end of 2002. The remaining six
partnerships will continue to operate until their limited partners vote
otherwise.
Price-Risk Management Activities. In June 1998, the Financial Accounting
Standards Board issued SFAS No. 133, "Accounting for Derivative Instruments and
Hedging Activities." The statement establishes accounting and reporting
standards requiring that every derivative instrument (including certain
derivative instruments embedded in other contracts) be recorded in the balance
sheet as either an asset or a liability measured at its fair value. SFAS No. 133
requires that changes in the derivative's fair value be recognized currently in
earnings unless specific hedge accounting criteria are met. Special accounting
for qualifying hedges allows the gains and losses on derivatives to offset
related results on the hedged item in the income statements and requires that a
company must formally document, designate, and assess the effectiveness of
transactions that receive hedge accounting. SFAS No. 133, as amended by SFAS No.
137 and SFAS No. 138, was adopted by us on January 1, 2001.
We have a policy to use derivative instruments, mainly the buying of
protection price floors, to protect against price declines in oil and gas
prices. We elected not to designate our price floors for special hedge
accounting treatment under SFAS No. 133, as amended. However, we have elected to
use mark-to-market accounting treatment for our derivative contracts. Upon
adoption of SFAS No. 133 on January 1, 2001, we recorded a net of taxes charge
of $392,868, which is recorded as a Cumulative Effect of Change in Accounting
Principle. During 2001 we recognized net gains of $1,173,094 relating to our
derivative activities, with $16,784 in unrealized losses at year-end 2001. This
activity is recorded in Price-risk management and other, net on the accompanying
statements of income.
At December 31, 2001, we had open price floor contracts covering notional
volumes of 2.0 million MMBtu of natural gas. These natural gas price floor
contracts relate to the NYMEX contract months of February and March 2002 at an
average price of $2.33 per MMBtu. The fair value of our open price floor
contracts at December 31, 2001, totaled $296,000 and is included in Other
current assets on the accompanying balance sheets.
Income Taxes. Under SFAS No. 109, "Accounting for Income Taxes," deferred
taxes are determined based on the estimated future tax effects of differences
between the financial statement and tax bases of assets and liabilities, given
the provisions of the enacted tax laws.
Cash and Cash Equivalents. We consider all highly liquid debt instruments
with an initial maturity of three months or less to be cash equivalents.
Credit Risk Due to Certain Concentrations. We extend credit, primarily in
the form of monthly oil and gas sales and joint interest owners receivables, to
various companies in the oil and gas industry, which results in a concentration
of credit risk. The concentration of credit risk may be affected by
42
changes in economic or other conditions and may accordingly impact our overall
credit risk. However, we believe that the risk of these unsecured receivables is
mitigated by the size, reputation, and nature of the companies to which we
extend credit. During 2001, oil and gas sales to subsidiaries of Eastex Crude
Company were $31.6 million, or 18.1% of oil and gas sales, while sales to
subsidiaries of Enron were $18.2 million, or 10.4% of oil and gas sales. During
2000, oil and gas sales to subsidiaries of Eastex Crude Company were $47.4
million, or 25.7% of our oil and gas sales, while sales to subsidiaries of PG&E
Energy Trading Corporation were $21.2 million, or 11.5% of oil and gas sales.
During 1999, oil and gas sales to subsidiaries of Eastex Crude Company were
$21.7 million, or 19.4% of our oil and gas sales. Beginning in December 2000,
the subsidiaries of PG&E Energy Trading Corporation to which we made sales were
sold to subsidiaries of El Paso Corporation. All receivables from PG&E were
collected. During the fourth quarter of 2001, we wrote off $1.4 million due to
uncollected receivables related to gas sold to Enron in November 2001. This
amount is included in Other expenses on the Consolidated Statement of Income. We
have discontinued sales of oil and gas to Enron and are selling that production
to other purchasers.
Risk-Factors. Our revenues, profitability and cash flow are substantially
dependent upon the price of and demand for oil and gas. Prices for oil and gas
are subject to wide fluctuations in response to relatively minor changes in the
supply of and demand for oil and gas, market uncertainty, and a variety of
additional factors beyond our control. We are also dependent upon the continued
success of our domestic and New Zealand exploration and development programs.
Other factors that could affect revenues, profitability, and cash flow include
the inherent uncertainty in reserves estimates, our price-risk management
activities, and the ability to replace reserves and finance our growth.
Fair Value of Financial Instruments. Our financial instruments consist of
cash and cash equivalents, accounts receivable, accounts payable, bank
borrowings, and notes. The carrying amounts of cash and cash equivalents,
accounts receivable, and accounts payable approximate fair value due to the
highly liquid nature of these short-term instruments. The fair values of the
bank borrowings approximate the carrying amounts as of December 31, 2001 and
2000, and were determined based upon interest rates currently available to us
for borrowings with similar terms. Based on quoted market prices as of the
respective dates, the fair values of our Senior Notes were $126.5 million and
$115.1 million at December 31, 2001 and 2000, respectively. The carrying value
of our Senior Notes was $124.2 million and $124.1 million at December 31, 2001
and 2000, respectively.
New Accounting Pronouncements. In June 2001, the Financial Accounting
Standards Board issued SFAS No. 143, "Accounting for Asset Retirement
Obligations." The statement requires entities to record the fair value of a
liability for legal obligations associated with the retirement obligations of
tangible long-lived assets in the period in which it is incurred. When the
liability is initially recorded, the entity increases the carrying amount of the
related long-lived asset. Over time, accretion of the liability is recognized
each period, and the capitalized cost is depreciated over the useful life of the
related asset. Upon settlement of the liability, an entity either settles the
obligation for its recorded amount or incurs a gain or loss upon settlement. We
currently do not include dismantlement and abandonment costs in our depletion
calculation as the vast majority of our properties are onshore and the salvage
value of the tangible equipment offsets our dismantlement and abandonment costs.
This standard will require us to record a liability for the fair value of our
dismantlement and abandonment costs, excluding salvage values. The standard is
effective for fiscal years beginning after June 15, 2002, with earlier
application encouraged. The Company is currently evaluating the effect of
adopting Statement No. 143 on its financial statements and will adopt the
statement on January 1, 2003.
2. Earnings Per Share
Basic earnings per share ("Basic EPS") have been computed using the
weighted average number of common shares outstanding during the respective
periods. The calculation of diluted earnings per share ("Diluted EPS") for 1999
and 2000 assumes conversion of our Convertible Notes as of the beginning of the
respective periods and the elimination of the related after-tax interest
expense. The calculation of diluted earnings per share for all periods assumes,
as of the beginning of the period, exercise of stock options and warrants using
the treasury stock method. The assumed conversion of our Convertible Notes
applies only to the 2000 period since for the 1999 period they would have been
antidilutive and since they were extinguished at year-end 2000. Certain of our
stock options that would potentially dilute Basic EPS in the future were also
antidilutive for the 2001 and 1999 periods.
43
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,
2001, 2000, and 1999:
2001 2000 1999
----------------------------------- ----------------------------------- ---------------------------------
Net Per Share Net Per Share Net Per Share
Loss Shares Amount Income Shares Amount Income Shares Amount
------------- --------- --------- ------------ ---------- --------- ----------- ---------- ---------
Basic EPS:
Net Income (Loss)
and Share Amounts $ (22,347,765) 24,732,09 $ (0.90) $ 59,184,008 21,244,684 $ 2.79 $19,286,574 18,050,106 $ 1.07
Dilutive
Securities:
6.25% Convertible -- -- 4,772,418 3,546,933 -- --
Notes
Stock Options -- -- -- 713,112 -- 42,365
------------- --------- ------------ ---------- ----------- ----------
Diluted EPS:
Net Income (Loss)
and Assumed Share
Conversions $ (22,347,765) 24,732,09 $ (0.90) $ 63,956,426 25,504,729 $ 2.51 $19,286,574 18,092,471 $ 1.07
============= ========= ============ ========== =========== ==========
3. Provision for Income Taxes
The following is an analysis of the consolidated income tax provision
(benefit):
Year Ended December 31,
-----------------------------------------------------
2001 2000 1999
---------------- --------------- --------------
Current $ 114,611 $ (29,000) $ (11,819)
Deferred (12,352,047) 33,294,480 10,461,396
---------------- --------------- --------------
Total $ (12,237,436) $ 33,265,480 $ 10,449,577
================ =============== ==============
There are differences between income taxes computed using the federal
statutory rate (35% for 2001, 2000, and 1999) and our effective income tax rates
(35.8%, 35.7%, and 35.1% for 2001, 2000, and 1999, respectively), primarily as
the result of state income taxes, foreign income taxes and certain tax credits
available to the Company. Foreign net income for SENZ for 2001 was $1,234,919.
New Zealand's statutory rate and effective tax rate are 33%. Reconciliations of
income taxes computed using the statutory rate to the effective income tax rates
are as follows:
2001 2000 1999
--------------- -------------- ---------------
Income taxes computed at U.S. statutory rate $ (11,967,317) $ 32,577,772 $ 10,407,653
State tax provisions, net of federal benefits (279,875) 775,850 (7,801)
Provision for foreign income tax (24,698) --- ---
Other, net 34,454 (88,142) 49,725
--------------- -------------- ---------------
Provision (benefit) for income taxes $ (12,237,436) $ 33,265,480 $ 10,449,577
=============== ============== ================
44
The tax effects of temporary differences representing the net deferred tax
liability (asset) at December 31, 2001 and 2000, were as follows:
2001 2000
---------------- -----------------
Deferred tax assets:
Alternative minimum tax credits $ (1,979,399) $ (1,979,399)
Net operating loss carry forward (18,877,969) (16,194,060)
---------------- -----------------
Total deferred tax assets $ (20,857,368) $ (18,173,459)
Deferred tax liabilities:
Domestic Oil and gas properties $ 47,539,564 $ 59,097,793
Foreign Oil and gas properties 407,524 ---
Other 482,513 254,256
---------------- -----------------
Total deferred tax liabilities $ 48,429,601 $ 59,352,049
---------------- -----------------
Net deferred tax liability $ 27,572,233 $ 41,178,590
================ ==================
As of December 31, 2001, we had $52.7 million of net operating loss carry
forwards, which expire as follows: $29.0 million, $20.1 million, $3.0 million
and $0.6 million in 2013, 2014, 2015 and 2016, respectively.
We did not record any valuation allowances against deferred tax assets at
December 31, 2001 and 2000.
At December 31, 2001, we had alternative minimum tax credits of $1,979,399
that carry forward indefinitely and are available to reduce future regular tax
liability to the extent they exceed the related tentative minimum tax otherwise
due.
4. Long-Term Debt
Our long-term debt as of December 31, 2001 and 2000, is as follows:
2001 2000
--------------- ----------------
Bank Borrowings $ 134,000,000 $ 10,600,000
Senior Notes 124,197,128 124,129,485
--------------- ----------------
Long-Term Debt $ 258,197,128 $ 134,729,485
=============== ================
Bank Borrowings. At December 31, 2001, we had outstanding borrowings of
$134.0 million under our $250.0 million credit facility with a syndicate of nine
banks which has a borrowing base of $200 million. At December 31, 2000, we had
borrowings of $10.6 million under our credit facility. The interest rate is
either (a) the lead bank's prime rate (4.75% at December 31, 2001) or (b) the
adjusted London Interbank Offered Rate ("LIBOR") plus the applicable margin
depending on the level of outstanding debt. The applicable margin is based on
the ratio of the outstanding balance to the last calculated borrowing base. Of
the $134.0 million borrowed at December 31, 2001, $130.0 million was borrowed at
the LIBOR rate plus applicable margin, which averaged 3.64%. Of the $10.6
million borrowed at December 31, 2000, $5.0 million was borrowed at the LIBOR
rate plus applicable margin (which averaged 7.89% at December 31, 2000).
Upon closing of the New Zealand TAWN acquisition in January 2002, our
credit facility increased to $300.0 million and the borrowing base increased to
$275.0 million. For further information on this acquisition, see Footnote 9
"Subsequent Events."
45
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), requirements as to maintenance of certain minimum financial ratios
(principally pertaining to working capital, debt, and equity ratios), and
limitations on incurring other debt. Since inception, no cash dividends have
been declared on our common stock. We are currently in compliance with the
provisions of this agreement. Effective September 28, 2001, the credit facility
was extended until October 1, 2005.
Interest expense on the credit facility, including commitment fees and
amortization of debt issuance costs, totaled $5,833,564 in 2001, $654,936 in
2000, and $6,107,270 in 1999.
Convertible Notes. In November 1996, we sold $115.0 million of 6.25%
Convertible Subordinated Notes due 2006. The Convertible Notes were unsecured
and convertible into Swift common stock at the option of the holders at an
adjusted conversion price of $31.534 per share. Interest on the notes was
payable semiannually, on May 15 and November 15. On December 11, 2000, we called
for the redemption of our Convertible Notes effective December 26, 2000, at
103.75% of their principal amount. Holders of approximately $100.0 million of
the Convertible Notes elected to convert their notes into 3,164,644 shares of
our common stock. Holders of the remaining $15.0 million of the Convertible
Notes elected to redeem their notes for cash plus accrued interest. This cash
redemption resulted in our recognizing an Extraordinary Loss on the Early
Extinguishment of Debt (net of taxes) of $0.6 million, or $1.0 million before
taxes.
Interest expense on the Convertible Notes, including amortization of debt
issuance costs, totaled $7,426,599 in 2000 and $7,569,361 in 1999.
Senior Notes. Our Senior Notes consist of $125.0 million of 10.25% Senior
Subordinated Notes due 2009. The Senior Notes were issued at 99.236% of the
principal amount on August 4, 1999, and will mature on August 1, 2009. The
Senior Notes are unsecured senior subordinated obligations and are subordinated
in right of payment to all our existing and future senior debt, including our
bank debt. Interest on the Senior Notes is payable semiannually, on February 1
and August 1, and commenced with the first payment on February 1, 2000. On or
after August 1, 2004, the Senior Notes are redeemable for cash at the option of
Swift, with certain restrictions, at 105.125% of principal, declining to 100% in
2007. In addition, prior to August 1, 2002, we may redeem up to 33.33% of the
Senior Notes with the proceeds of qualified offerings of our equity at 110.25%
of the principal amount of the Senior Notes, together with accrued and unpaid
interest. Upon certain changes in control of Swift, each holder of Senior Notes
will have the right to require us to repurchase the Senior Notes at a purchase
price in cash equal to 101% of the principal amount, plus accrued and unpaid
interest to the date of purchase.
Interest expense on the Senior Notes, including amortization of debt
issuance costs and discount, totaled $13,123,052 in 2001, $13,092,127 in 2000,
and $5,303,266 in 1999.
Debt Maturities. Our bank borrowings are due in October 2005, and our
Senior Notes are due in August 2009.
5. Commitments and Contingencies
Total rental and lease expenses were $1,322,611 in 2001, $1,255,474 in
2000, and $1,272,497 in 1999. Our remaining minimum annual obligations under
non-cancelable operating lease commitments are $1,393,095 for 2002, $1,480,092
for 2003, $1,492,268 for 2004, and $248,711 for 2005. 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.
As of December 31, 2001, we were the managing general partner of 71 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
46
any such currently pending legal actions will not have a material adverse effect
on the financial position or results of operations of Swift.
6. Stockholders' Equity
Common Stock. During the third quarter of 1999, we issued 4.6 million
shares of common stock at a price of $9.75 per share. Gross proceeds from this
offering were $44,850,000, with issuance costs of $2,888,690.
In December 2000, the holders of approximately $100.0 million of our
Convertible Notes converted such notes into 3,164,644 shares of our common
stock, which resulted in an increase in our common stock capital accounts of
approximately $97.4 million.
Stock-Based Compensation Plans. We have two current stock option plans, the
2001 Omnibus Stock Compensation Plan, which was adopted by our board of
directors in February 2001 and was approved by shareholders at the 2001 Annual
Meeting of Shareholders, and the 1990 non-qualified plan. In addition, we have
an employee stock purchase plan. No further grants will be made under the 1990
non-qualified 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 may be
granted options to purchase shares of common stock. Both plans provide that the
exercise prices equal 100% of the fair value of the common stock on the date of
grant. Unless otherwise provided, options become exercisable for 20% of the
shares on the first anniversary of the grant of the option and are exercisable
for an additional 20% per year thereafter. Options granted expire 10 years after
the date of grant or earlier in the event of the optionee's separation from
employment. At the time the stock options are exercised, the option price is
credited to common stock and additional paid-in capital.
The employee stock purchase plan provides eligible employees the
opportunity to acquire shares of Swift common stock at a discount through
payroll deductions. The plan year is from June 1 to the following May 31. The
first year of the plan commenced June 1, 1993. To date, employees have been
allowed to authorize payroll deductions of up to 10% of their base salary during
the plan year by making an election to participate prior to the start of a plan
year. The purchase price for stock acquired under the plan is 85% of the lower
of the closing price of our common stock as quoted on the New York Stock
Exchange at the beginning or end of the plan year or a date during the year
chosen by the participant. Under this plan for the last three years, we have
issued 22,360 shares at a price of $21.41 in 2001, 29,889 shares at a price
range of $8.40 to $10.57 in 2000, and 22,771 shares at a price range of $5.21 to
$11.00 in 1999. The estimated weighted average fair value of shares issued under
this plan, as determined using the Black-Scholes option-pricing model, was $8.19
in 2001, $4.25 in 2000, and $4.74 in 1999. As of December 31, 2001, 362,428
shares remained available for issuance under this plan. There are no charges or
credits to income in connection with this plan.
47
We account for our stock option plans under Accounting Principles Board
Opinion No. 25, "Accounting for Stock Issued to Employees." As all options were
issued at a price equal to market price, no compensation expense has been
recognized. Had compensation expense for these plans been determined based on
the fair value of the options consistent with SFAS No. 123, "Accounting for
Stock-Based Compensation," our net income (loss) and earnings (loss) per share
would have been adjusted to the following pro forma amounts:
2001 2000 1999
------------ ----------- -----------
Net Income (Loss): As Reported $(22,347,765) $59,184,008 $19,286,574
Pro Forma $(26,632,624) $56,531,665 $16,869,122
Basic EPS: As Reported $(0.90) $2.79 $1.07
Pro Forma $(1.08) $2.66 $0.93
Diluted EPS: As Reported $(0.90) $2.51 $1.07
Pro Forma $(1.08) $2.40 $0.93
Pro forma compensation cost reflected above may not be representative of
the cost to be expected in future years.
The following is a summary of our stock options under these plans as of
December 31, 2001, 2000, and 1999:
2001 2000 1999
------------------------ -------------------------- --------------------------
Wtd. Avg. Wtd. Avg. Wtd. Avg.
Shares Exer. Price Shares Exer. Price Shares Exer. Price
------------------------ -------------------------- --------------------------
Options outstanding, beginning of period 2,076,593 $ 11.70 2,148,511 $ 9.08 2,266,146 $ 9.03
Options granted 747,073 $ 31.51 645,944 $ 16.88 25,000 $ 12.50
Options canceled (31,247) $ 14.09 (174,412) $ 8.71 (77,158) $ 8.95
Options exercised (152,915) $ 8.69 (543,450) $ 8.48 (65,477) $ 8.55
----------- ------------ ----------
Options outstanding, end of period 2,639,504 $ 17.44 2,076,593 $ 11.70 2,148,511 $ 9.08
=========== ============ ==========
Options exercisable, end of period 1,181,141 $ 11.49 897,711 $ 9.35 1,280,156 $ 8.87
=========== ============ ==========
Options available for future grant, end of
period 1,155,057 181,235 950,735
=========== ============ ==========
Estimated weighted average fair value per
share of options granted during the year $20.68 $10.90 $7.10
=========== ============ ==========
48
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 2001, 2000, and 1999,
respectively: no dividend yield; expected volatility factors of 46.9%, 46.7%,
and 44.2%; risk-free interest rates of 5.24%, 6.61%, and 5.60%; and expected
lives of 7.3, 6.7, and 7.5 years. The following table summarizes information
about stock options outstanding at December 31, 2001:
Options Outstanding Options Exercisable
---------------------------------------- -------------------------
Range of Number Wtd. Avg. Wtd. Avg. Number Wtd. Avg.
Exercise Outstanding Remaining Exercise Exercisable Exercise
Prices at 12/31/01 Contractual Price At 12/31/01 Price
Life
- -------------------- -------------- ------------ ----------- ------------- -----------
$ 5.00 to $16.99 1,592,597 5.7 $ 9.50 1,012,907 $ 9.20
$17.00 to $28.99 280,439 6.1 $ 23.25 153,785 $ 24.23
$29.00 to $41.00 766,468 9.1 $ 31.84 14,449 $ 36.69
-------------- -------------
$ 5.00 to $41.00 2,639,504 6.8 $ 17.44 1,181,141 $ 11.49
============== =============
Employee Stock Ownership Plan. In 1996, we established an Employee Stock
Ownership Plan ("ESOP") effective January 1, 1996. All employees over the age of
21 with one year of service are participants. This plan has a five-year cliff
vesting, and service is recognized after the ESOP effective date. The ESOP is
designed to enable our employees to accumulate stock ownership. While there will
be no employee contributions, participants will receive an allocation of stock
that has been contributed by Swift. Compensation expense is reported when such
shares are released to employees. The plan may also acquire Swift common stock,
purchased at fair market value. The ESOP can borrow money from Swift to buy
Swift stock. Benefits will be paid in a lump sum or installments, and the
participants generally have the choice of receiving cash or stock. At December
31, 2001, 2000 and 1999, all of the ESOP compensation was earned.
Employee Savings Plan. We have a savings plan under Section 401(k) of the
Internal Revenue Code. Eligible employees may make voluntary contributions into
the 401(k) savings plan with Swift contributing on behalf of the eligible
employee an amount equal to 100% of the first 2% of compensation and 75% of the
next 4% of compensation based on the contributions made by the eligible
employees. Our contribution to the 401(k) savings plan totaled $558,000,
$483,000, and $474,000 for the years ended December 31, 2001, 2000, and 1999,
respectively. The contribution in 2001 was made all in common stock, while the
2000 and 1999 contributions were made half in common stock and half in cash. The
shares of common stock contributed to the 401(k) savings plan totaled 28,798,
7,175, and 21,810 shares for the 2001, 2000, and 1999 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, 2001, 839,034 shares remain in treasury (net of 88,740 shares used to fund
ESOP and 401(k) contributions) with a total cost of $12,032,791 and are included
in "Treasury stock held, at cost" on the balance sheet.
Shareholder Rights Plan. In August 1997, the board of directors declared a
dividend of one preferred share purchase right on each outstanding share of
Swift common stock. The rights are not currently exercisable but would become
exercisable if certain events occurred relating to any person or group acquiring
or attempting to acquire 15% or more of our outstanding shares of common stock.
Thereafter, upon certain triggers, each right not owned by an acquirer allows
its holder to purchase Swift securities with a market value of two times the
$150 exercise price.
7. Related-Party Transactions
We are the operator of a number of properties owned by our affiliated
limited partnerships and joint ventures and, accordingly, charge these entities
and third-party joint interest owners operating fees. The operating fees charged
to the partnerships in 2001, 2000, and 1999 totaled approximately
49
$925,000, $1,775,000, and $1,970,000, respectively. We are also reimbursed for
direct, administrative, and overhead costs incurred in conducting the business
of the limited partnerships, which totaled approximately $3,140,000, $4,465,000,
and $4,000,000 in 2001, 2000, and 1999, respectively. In partnerships in which
the limited partners have voted to sell their remaining properties and liquidate
their limited partnerships, we are also reimbursed for direct, administrative,
and overhead costs incurred in the disposition of such properties, which costs
totaled approximately $2,360,000, $1,220,000, and $850,000 in 2001, 2000, and
1999, respectively.
8. Foreign Activities
New Zealand
Swift Operated Permits. Our activity in New Zealand began in 1995 with the
issuance of the first of two petroleum exploration permits. After surrendering a
portion of our permit acreage in 1998, combining the two permits and expanding
the permit acreage in 1999, and relinquishing 50% of the acreage in 2001 as we
extended our petroleum exploration permit, our permit 38719 as of year-end 2001
covered approximately 50,300 acres in the Taranaki Basin of New Zealand's north
island, with all but 12,800 acres onshore. At December 31, 2001, we had a 90%
working interest in this permit and had fulfilled all current obligations under
this permit.
In late 1999, we completed our first exploratory well on this permit, the
Rimu-A1, and a production test was performed. During the second half of 2000, we
drilled and successfully tested two development wells, the Rimu-B1 and the
Rimu-B2. In 2001 we drilled and tested three more Rimu development wells, the
Rimu-A2, Rimu-A3 and Rimu-B3. The Rimu-A3 was successful; the Rimu-A2 and
Rimu-B3 were dry. Early in 2002, the Rimu-A2 was sidetracked to the Tariki sand
and is currently awaiting completion. The Rimu-B3 was also sidetracked in early
2002 and again was unsuccessful. In 2001, we also drilled the Kauri-A1
exploratory well, the Kauri-A2 development well, and the Kauri-B1 exploratory
well. In the Kauri-A-1 we tested the Upper Tariki sands and still have further
zones to test. The Kauri-A2 well successfully tested the Manutahi sands. The
Kauri-B1 was drilled approximately 1.75 miles to the southeast of the Kauri-A
pad and targeted the Manutahi sands. This well was plugged and abandoned in
2001. Our portion of the drilling, completion, and testing costs incurred on the
wells within our permits during 2001 was approximately $26.0 million. Our
portion of prospect costs on our permits during 2001 was approximately $5.1
million, which included obtaining 2-D seismic data in the last half of the year
for the Rata prospect. We incurred $22.5 million on the production facilities
that we expect to be commissioned near the end of the first quarter of 2002.
In 2000, we entered into an agreement with Fletcher Challenge Energy
Limited whereby we would earn a 25% participating interest in petroleum
exploration permit 38730 containing approximately 48,900 acres. In May 2001,
Fletcher relinquished their interest in the permit, and we then assumed 100%
working interest in such permit by means of committing to an acceptable work
plan. Such plan required us to acquire a minimum of 30 kilometers of new 2D
seismic data, which we completed in 2001. Rather than commit to drill a new well
in 2002 as the work plan called for, we surrendered this project in February
2002.
Non-Operated Permits. In 1998, we entered into agreements for a 25% working
interest in an exploration permit, permit 38712, held by Marabella Enterprises
Ltd., a subsidiary of Bligh Oil & Minerals, an Australian company, and a 7.5%
working interest held by Antrim Oil and Gas Limited, a Canadian company, in a
second permit, permit 38716, operated by Marabella. In turn, Bligh and Antrim
each became 5% working interest owners in our permit 38719. Unsuccessful
exploratory wells were drilled on these two permits, and we charged $0.4 million
against earnings in 1998 and $0.3 million in 1999. All of the acreage on the
permit 38712 was surrendered in 2000. The exploratory well on permit 38716 has
been temporarily abandoned pending a further evaluation. It is currently
anticipated that this well will be re-entered and sidetracked to target a
location to the west of the initial well. A five-year extension was granted on
permit 38716 in 2001 upon the surrender of 50% of the acreage.
50
In 2000, we entered into an agreement with Fletcher Challenge Energy
Limited whereby we will earn a 20% participating interest in petroleum
exploration permit 38718 containing approximately 57,400 acres. In January 2001,
the operator temporarily abandoned the Tuihu #1 exploratory well on permit 38718
pending further analysis. The permit now contains approximately 28,700 acres
after a scheduled surrender during December 2000.
Costs Incurred. During 2001, our costs incurred in New Zealand totaled
$54.5 million, including $25.7 million for drilling, $5.5 million for prospect
costs, $22.5 million for production facilities, and $0.8 million in evaluation
costs for the acquisition of the TAWN assets, which closed in January 2002.
These costs also included $0.6 million of costs incurred on permits operated by
others: $0.2 million of drilling costs and $0.4 million of prospect costs. As of
December 31, 2001, our investment in New Zealand totaled approximately $84.4
million. As we have recorded proved undeveloped reserves relating to our
successful drilling activities, $45.5 million of our investment costs has been
included in the proved properties portion of oil and gas properties and $38.8
million has been included as unproved properties at the end of 2001. Our
development strategy includes having Rimu/Kauri production on line for oil and
gas sales in New Zealand near the end of the first quarter of 2002.
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. We retain a minimum 6% net
profits interest from the sale of hydrocarbon products from the fields. The
value of our net profits interest depends upon either the successful development
of production from the fields by others or their sale of the fields.
9. Subsequent Events
TAWN Acquisition. Through our subsidiary, Swift Energy New Zealand Limited,
we acquired Southern Petroleum Exploration Limited ("Southern NZ") in January
2002 for approximately $54.4 million in cash. 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 properties are
collectively called "TAWN," an acronym for the four fields that comprise the
property: Tariki, Ahuroa, Waihapa and Ngaere. This acquisition was accounted for
by the purchase method of accounting. Upon the closing of the New Zealand
acquisition, our credit facility was increased to $300.0 million and the
borrowing base became $275.0 million.
In conjunction with the TAWN acquisition, we granted Shell New Zealand a
short-term option to acquire an undivided 25% interest in our permit 38719,
which includes our Rimu and Kauri areas, as well as a 25% interest in our Rimu
Production Station. We do not know if Shell New Zealand will exercise this
option. The option would be subject to numerous notifications, governmental
approvals and consents if exercised. If the option is exercised, our credit
facility would be reduced to $275.0 million and our borrowing base would be
$250.0 million.
Antrim Acquisition. We purchased through our subsidiary, Swift Energy New
Zealand Limited, all of the New Zealand assets owned by Antrim Oil and Gas
Limited for 220,000 shares of Swift Energy Company common stock. Antrim owned a
5% interest in permit 38719 and a 7.5% interest in permit 38716. This
transaction closed in March 2002 (unaudited).
51
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, 2001:
Proved oil and gas properties $ 974,698,428 $ 929,172,460 $ 45,525,968
Unproved oil and gas properties 95,943,163 57,096,694 38,846,469
--------------------- ---------------- -----------------
1,070,641,591 986,269,154 84,372,437
Accumulated depreciation, depletion, and amortization (442,337,531) (442,166,052) (171,479)
--------------------- ---------------- -----------------
Net capitalized costs $ 628,304,060 $ 544,103,102 $ 84,200,958
===================== ================ =================
December 31, 2000:
Proved oil and gas properties $ 753,426,124 $ 732,265,674 $ 21,160,450
Unproved oil and gas properties 55,512,872 46,833,274 8,679,598
--------------------- ---------------- -----------------
808,938,996 779,098,948 29,840,048
Accumulated depreciation, depletion, and amortization (284,886,168) (284,886,168) --
--------------------- ---------------- -----------------
Net capitalized costs $ 524,052,828 $ 494,212,780 $ 29,840,048
===================== ================ =================
Of the $57,096,694 of domestic unproved property costs (primarily seismic
and lease acquisition costs) at December 31, 2001, excluded from the amortizable
base, $26,707,313 was incurred in 2001, $9,545,964 was incurred in 2000,
$5,640,587 was incurred in 1999, and $15,202,830 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. In response to market
conditions in 1998, we decreased our 1999 drilling expenditures when compared to
prior years, which, when coupled with the $15.3 million of leasehold properties
acquired in the Brookeland and Masters Creek areas in 1998, may extend the
evaluation time frame of such costs. Consequently, in response to market
conditions, we have decreased our 2002 drilling expenditures as well.
Of the $38,846,469 of net New Zealand unproved property costs at December
31, 2001, excluded from the amortizable base, $30,383,713 was incurred in 2001,
$5,013,539 was incurred in 2000, $907,972 was incurred in 1999, and $2,541,245
was incurred in prior years. We expect to continue drilling in New Zealand to
delineate our prospects there, with seven wells planned for drilling in 2002. We
expect to complete our evaluation of current unevaluated costs over the next two
to three years. Upon the startup of the Rimu Production Station near the end of
the first quarter of 2002, $23.6 million of these unproved property costs will
be moved to the proved properties classification and will begin being
depreciated.
52
Costs Incurred. The following table sets forth costs incurred related to
our oil and gas operations:
Year Ended December 31, 2001
----------------------------------------------------------
Total Domestic New Zealand
-------------------- --------------- ----------------
Acquisition of proved properties $ 41,286,539 $ 40,491,203 $ 795,336
Lease acquisitions (1) 31,225,493 25,688,068 5,537,425
Exploration 41,981,536 35,944,405 6,037,131
Development 132,246,713 112,597,856 19,648,857
-------------------- --------------- ----------------
Total acquisition, exploration, and development (2) $ 246,740,281 $ 214,721,532 $ 32,018,749
-------------------- --------------- ----------------
Processing plants $ 23,331,095 $ 817,454 $ 22,513,641
Field compression facilities 319,703 319,703 --
-------------------- --------------- ----------------
Total plants and facilities $ 23,650,798 $ 1,137,157 $ 22,513,641
-------------------- --------------- ----------------
Total costs incurred $ 270,391,079 $ 215,858,689 $ 54,532,390
==================== =============== ================
Year Ended December 31, 2000
----------------------------------------------------------
Total Domestic New Zealand
-------------------- --------------- -----------------
Acquisition of proved properties $ 34,191,883 $ 34,191,883 $ --
Lease acquisitions (1) 20,842,103 16,315,749 4,526,354
Exploration 20,150,834 18,524,883 1,625,951
Development 104,083,409 93,931,500 10,151,909
-------------------- --------------- ----------------
Total acquisition, exploration, and development (2) $ 179,268,229 $ 162,964,015 $ 16,304,214
-------------------- --------------- ----------------
Processing plants $ 1,819,464 $ 755,119 $ 1,064,345
Field compression facilities 203,789 203,789 --
-------------------- --------------- ----------------
Total plants and facilities $ 2,023,253 $ 958,908 $ 1,064,345
-------------------- --------------- ----------------
Total costs incurred $ 181,291,482 $ 163,922,923 $ 17,368,559
==================== =============== ================
Year Ended December 31, 1999
----------------------------------------------------------
Total Domestic New Zealand
-------------------- --------------- ----------------
Acquisition of proved properties $ 18,526,939 $ 18,526,939 $ --
Lease acquisitions (1) 10,382,672 9,251,658 1,131,014
Exploration 11,019,430 5,101,330 5,918,100
Development 39,891,868 39,891,868 --
-------------------- --------------- ----------------
Total acquisition, exploration, and development (2) $ 79,820,909 $ 72,771,795 $ 7,049,114
-------------------- --------------- ----------------
Processing plants $ 1,607,559 $ 1,607,559 $ --
Field compression facilities 171,535 171,535 --
-------------------- --------------- ----------------
Total plants and facilities $ 1,779,094 $ 1,779,094 $ --
--------------------- --------------- ----------------
Total costs incurred $ 81,600,003 $ 74,550,889 $ 7,049,114
===================== =============== ================
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 2001, 2000, and 1999 were $13,308,843, $16,791,834, and
$14,389,680, respectively.
2)Includes capitalized general and administrative costs directly associated with
the acquisition, exploration, and development efforts of approximately
$11,600,000, $10,300,000, and $8,500,000 in 2001, 2000, and 1999, respectively.
In addition, total includes $6,256,222, $5,043,206, and $4,142,098 in 2001,
2000, and 1999, respectively, of capitalized interest on unproved properties.
53
Results of Operations. New Zealand operations began in 2001 while all our
oil and gas operations in 2000 and 1999 were domestic. The following table sets
forth results of our oil and gas operations:
Year Ended December 31, 2001
----------------------------------------------------
Total Domestic New Zealand
--------------- --------------- ----------------
Oil and gas sales $ 181,184,635 $ 179,360,844 $ 1,823,791
Oil and gas production costs (36,719,609) (36,554,418) (165,191)
Depreciation and depletion (58,589,116) (58,417,637) (171,479)
Write-down of oil and gas properties (98,862,247) (98,862,247) --
--------------- --------------- ----------------
(12,986,337) (14,473,458) 1,487,121
Provision (benefit) for income taxes (4,647,810) (5,138,560) 490,750
--------------- --------------- ----------------
Results of producing activities $ (8,338,527) $ (9,334,898) $ 996,371
=============== =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.31 $ 1.32 $ 0.34
=============== =============== ================
Year Ended December 31, 2000
----------------------------------------------------
Total Domestic New Zealand
--------------- --------------- ----------------
Oil and gas sales $ 189,138,947 $ 189,138,947 $ --
Oil and gas production costs (29,220,315) (29,220,315) --
Depreciation and depletion (46,849,819) (46,849,819) --
--------------- --------------- ----------------
113,068,813 113,068,813 --
Provision (benefit) for income taxes 40,365,566 40,365,566 --
--------------- --------------- ----------------
Results of producing activities $ 72,703,247 $ 72,703,247 $ --
=============== =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 1.11 $ 1.11 $ --
=============== =============== ================
Year Ended December 31, 1999
---------------------------------------------------
Total Domestic New Zealand
--------------- --------------- ----------------
Oil and gas sales $ 108,898,696 $ 108,898,696 $ --
Oil and gas production costs (19,645,740) (19,645,740) --
Depreciation and depletion (41,410,106) (41,410,106) --
--------------- --------------- ----------------
47,842,850 47,842,850 --
Provision (benefit) for income taxes 16,792,840 16,792,840 --
--------------- --------------- ----------------
Results of producing activities $ 31,050,010 $ 31,050,010 $ --
=============== =============== ================
Amortization per physical unit of production
(equivalent Mcf of gas) $ 0.97 $ 0.97 $ --
=============== =============== ================
54
Supplemental Reserve Information. The following information presents
estimates of our proved oil and gas reserves. Reserves were determined by us and
audited by H. J. Gruy and Associates, Inc. ("Gruy"), independent petroleum
consultants. Gruy's summary report dated February 14, 2002, is set forth as an
exhibit to the Form 10-K Report for the year ended December 31, 2001, 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, 1998(1) 352,400,835 13,957,925 352,400,835 13,957,925 -- --
Revisions of previous estimates(2) (31,189,450) 2,058,725 (31,189,450) 2,058,725 -- --
Purchases of minerals in place 9,159,780 1,822,858 9,159,780 1,822,858 -- --
Sales of minerals in place (3,762,799) (260,287) (3,762,799) (260,287) -- --
Extensions, discoveries, and other
additions 30,107,908 5,791,966 30,107,908 5,791,966 -- --
Production(3) (26,756,524) (2,564,924) (26,756,524) (2,564,924) -- --
------------ ----------- ------------- ------------ ------------ -----------
Proved reserves as of December 31, 1999(1) 329,959,750 20,806,263 329,959,750 20,806,263 -- --
Revisions of previous estimates(2) (4,300,787) (455,606) (4,300,787) (455,606) -- --
Purchases of minerals in place 26,567,925 2,196,547 26,567,925 2,196,547 -- --
Sales of minerals in place (363,262) (76,288) (363,262) (76,288) -- --
Extensions, discoveries, and other
additions 93,869,841 15,134,694 38,556,364 3,943,807 55,313,477 11,190,887
Production(3) (27,119,491) (2,472,014) (27,119,491) (2,472,014) -- --
------------ ----------- ------------- ------------ ------------ -----------
Proved reserves as of December 31, 2000 418,613,976 35,133,596 363,300,499 23,942,709 55,313,477 11,190,887
Revisions of previous estimates(2) (122,127,541) 5,621,556 (101,693,477) 8,460,690 (20,434,064) (2,839,134)
Purchases of minerals in place 10,038,803 7,430,591 10,038,803 7,430,591 -- --
Sales of minerals in place (7,508,064) (555,586) (7,508,064) (555,586) -- --
Extensions, discoveries, and other
additions 52,353,909 8,907,852 50,810,697 6,257,441 1,543,212 2,650,411
Production(3) (26,458,958) (3,055,373) (26,458,958) (2,971,112) -- (84,261)
------------ ----------- ------------- ------------ ------------ -----------
Proved reserves as of December 31, 2001(4) 324,912,125 53,482,636 288,489,500 42,564,733 36,422,625 10,917,903
============ =========== ============= ============ ============ ===========
Proved developed reserves:
December 31, 1998 197,105,963 7,142,566 197,105,963 7,142,566 -- --
December 31, 1999 174,046,096 8,437,299 174,046,096 8,437,299 -- --
December 31, 2000 215,169,833 10,980,196 215,169,833 10,980,196 -- --
December 31, 2001(4) 181,651,578 23,759,574 167,401,736 20,393,142 14,249,842 3,366,432
1)Proved reserves exclude quantities subject to our volumetric production
payment agreement, which expired with the last required delivery of volumes in
October 2000.
2)Revisions of previous estimates are related to upward or downward variations
based on current engineering information for production rates, volumetrics, and
reservoir pressure. Additionally, changes in quantity estimates are affected by
the increase or decrease in crude oil and natural gas prices at each year-end.
Proved reserves, as of December 31, 2001, were based upon prices in effect at
year-end. The weighted average of such year-end prices for total, domestic, and
New Zealand were $2.51, $2.68, and $1.18 per Mcf of natural gas and $18.45,
$18.51, and $18.25 per barrel of oil, respectively. This compares to $9.86,
$11.25, and $0.71 per Mcf and $24.62, $25.50, and $22.30 per barrel as of
December 31, 2000, for total, domestic, and New Zealand, respectively.
55
3)Natural gas production for 1999 and 2000 excludes 728,235 and 405,130 Mcf,
respectively, delivered under our volumetric production payment agreement.
4)We acquired 62.1 Bcfe and 5.7 Bcfe from the TAWN and Antrim acquisitions,
respectively, in New Zealand. These reserves estimates at December 31, 2001, are
not included in the above table. The TAWN reserves were all proved developed
while the Antrim reserves were 34% proved developed.
56
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, 2001
---------------------------------------------------------
Total Domestic New Zealand
---------------- ---------------- ----------------
Future gross revenues $ 1,706,475,138 $ 1,485,480,927 $ 220,994,211
Future production costs (483,588,857) (436,141,429) (47,447,428)
Future development costs (198,172,628) (185,347,628) (12,825,000)
---------------- ---------------- ----------------
Future net cash flows before income taxes 1,024,713,653 863,991,870 160,721,783
Future income taxes (261,635,331) (208,726,729) (52,908,602)
---------------- ---------------- ----------------
Future net cash flows after income taxes 763,078,322 655,265,141 107,813,181
Discount at 10% per annum (308,520,417) (274,882,174) (33,638,243)
---------------- ---------------- ----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 454,557,905 $ 380,382,967 $ 74,174,938
================ ================ ================
Year Ended December 31, 2000
---------------------------------------------------------
Total Domestic New Zealand
---------------- ---------------- ----------------
Future gross revenues $ 4,995,951,799 $ 4,737,560,630 $ 258,391,169
Future production costs (817,127,348) (807,436,139) (9,691,209)
Future development costs (204,620,116) (180,320,116) (24,300,000)
---------------- ---------------- ----------------
Future net cash flows before income taxes 3,974,204,335 3,749,804,375 224,399,960
Future income taxes (1,321,061,952) (1,243,731,594) (77,330,358)
---------------- ---------------- ----------------
Future net cash flows after income taxes 2,653,142,383 2,506,072,781 147,069,602
Discount at 10% per annum (1,075,183,917) (1,017,995,158) (57,188,759)
---------------- ---------------- ----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 1,577,958,466 $ 1,488,077,623 $ 89,880,843
================ ================ ================
Year Ended December 31, 1999
---------------------------------------------------------
Total Domestic New Zealand
---------------- ---------------- ----------------
Future gross revenues $ 1,371,541,850 $ 1,371,541,850 $ --
Future production costs (353,594,258) (353,594,258) --
Future development costs (156,738,446) (156,738,446) --
---------------- ----------------- ----------------
Future net cash flows before income taxes 861,209,146 861,209,146 --
Future income taxes (226,725,033) (226,725,033) --
---------------- ---------------- ----------------
Future net cash flows after income taxes 634,484,113 634,484,113 --
Discount at 10% per annum (195,540,279) (195,540,279) --
---------------- ---------------- ----------------
Standardized measure of discounted future net cash flows
relating to proved oil and gas reserves $ 438,943,834 $ 438,943,834 $ --
================ ================ =================
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.
57
3. The future gross revenue streams are reduced by estimated future costs
to develop and to produce the proved reserves, as well as certain abandonment
costs based on year-end cost estimates and the estimated effect of future income
taxes.
4. Future income taxes are computed by applying the statutory tax rate to
future net cash flows reduced by the tax basis of the properties, the estimated
permanent differences applicable to future oil and gas producing activities, and
tax carry forwards.
The estimates of cash flows and reserves quantities shown above are based
on year-end oil and gas prices for each period. Subsequent changes to such
year-end oil and gas prices could have a significant impact on discounted future
net cash flows. Under Securities and Exchange Commission rules, companies that
follow the full-cost accounting method are required to make quarterly Ceiling
Test calculations, using prices in effect as of the period end date presented
(see Note 1 to the Consolidated Financial Statements). Application of these
rules during periods of relatively low oil and gas prices, even if of short-term
seasonal duration, may result in write-downs.
The standardized measure of discounted future net cash flows is not
intended to present the fair market value of our oil and gas property reserves.
An estimate of fair value would also take into account, among other things, the
recovery of reserves in excess of proved reserves, anticipated future changes in
prices and costs, an allowance for return on investment, and the risks inherent
in reserves estimates.
The following are the principal sources of change in the standardized
measure of discounted future net cash flows:
Year Ended December 31,
-------------------------------------------------------
2001 2000 1999
------------------ ----------------- --------------
Beginning balance $ 1,577,958,466 $ 438,943,834 $ 290,273,103
------------------ ----------------- --------------
Revisions to reserves proved in prior years--
Net changes in prices, production costs, and future
development costs (1,692,627,074) 1,523,487,598 123,447,890
Net changes due to revisions in quantity (93,669,181) (36,102,814) (23,746,974)
estimates
Accretion of discount 231,325,481 56,405,451 34,078,501
Other (204,768,815) (220,119,873) 2,032,696
------------------ ----------------- --------------
Total revisions (1,759,739,589) 1,323,670,362 135,812,113
New field discoveries and extensions, net of future
production and development costs 110,213,160 359,265,150 102,582,467
Purchases of minerals in place 39,544,163 160,240,785 39,282,292
Sales of minerals in place (50,131,970) (598,021) (5,360,428)
Sales of oil and gas produced, net of production (144,262,145) (159,331,003) (88,196,672)
costs
Previously estimated development costs incurred 94,107,760 65,953,028 39,149,732
Net change in income taxes 586,868,060 (610,185,669) ( 74,598,773)
------------------ ----------------- --------------
Net change in standardized measure of discounted
future net cash flows (1,123,400,561) 1,139,014,632 148,670,731
------------------ ----------------- --------------
Ending balance $ 454,557,905 $ 1,577,958,466 $ 438,943,834
================== ================= ==============
58
Quarterly Results. The following table presents summarized quarterly
financial information for the years ended December 31, 2000 and 2001:
Basic EPS Diluted EPS
Income/(Loss) Income/(Loss) Income/(Loss)
Before Before Before
Extraordinary Extraordinary Extraordinary Basic Diluted
Income/(Loss) Item and Item and Item and EPS EPS
Before Change In Net Change In Change In Net Net
Income Accounting Income/ Accounting Accounting Income/ Income/
Revenues Taxes Principle (Loss) Principle Principle (Loss) (Loss)
------------ ------------ ------------- ------------ --------------- ---------------- --------- ---------
2000:
First
Quarter $ 37,747,645 $ 14,919,044 9,589,828 $ 9,589,828 $ 0.46 $ 0.43 $ 0.46 $ 0.43
Second
Quarter 46,127,375 22,218,358 14,213,274 14,213,274 0.68 0.61 0.68 0.61
Third
Quarter 49,525,166 24,748,163 15,832,348 15,832,348 0.74 0.66 0.74 0.66
Fourth
Quarter 58,224,760 31,193,781 20,178,416 19,548,558 0.93 0.82 0.90 0.80
------------ ------------ ------------- ------------
Total $191,624,946 $ 93,079,346 59,813,866 $ 59,184,008 $ 2.82 $ 2.53 $ 2.79 $ 2.51
2001:
First
Quarter $ 62,392,014 $ 35,513,130 22,719,653 $ 22,326,785 $ 0.92 $ 0.89 $ 0.91 $ 0.88
Second
Quarter 52,303,265 23,408,900 14,972,946 14,972,946 0.61 0.59 0.61 0.59
Third
Quarter 41,244,583 11,607,563 7,420,090 7,420,090 0.30 0.29 0.30 0.29
Fourth
Quarter 27,867,628 (104,721,926) (67,067,586) (67,067,586) (2.71) (2.71) (2.71) (2.71)
------------ ------------ ------------- ------------
Total $ 183,807,490 (34,192,333) (21,954,897)$ 22,347,765 $ (0.89) $ (0.89) $ (0.90) $ (0.90)
============ ============ ============= ============
59
Item 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure
None.
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 14, 2002, 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 14, 2002, annual shareholders'
meeting is incorporated herein by reference.
Item 12. Security Ownership of Certain Beneficial Owners and Management
The information required under Item 12 which will be set forth in our
definitive proxy statement to be filed within 120 days after the close of the
fiscal year end in connection with our May 14, 2002, 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 14, 2002, annual shareholders'
meeting is incorporated herein by reference.
60
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K
(a) 1. The following consolidated financial statements of Swift
EnergyCompany together with the report thereon of Arthur Andersen LLP
datedFebruary 18, 2002, and the data contained therein are included in
Item8 hereof:
Report of Independent Public Accountants...........35
Consolidated Balance Sheets........................36
Consolidated Statements of Income..................37
Consolidated Statements of Stockholders' Equity....38
Consolidated Statements of Cash Flows..............39
Notes to Consolidated Financial Statements.........40
2. Financial Statement Schedules
None
3. Exhibits
3(a).1 1 Amended and Restated Articles of Incorporation of Swift
Energy Company.
3(b)* By-Laws, as amended through August 14, 1995.
4(a).1 7 Indenture dated as of July 29, 1999, between Swift
Energy Company and BankOne, N.A., as Trustee.
4(a).2 8 First Supplemental Indenture dated as of August 4,
1999, between Swift Energy Company and Bank One, N.A.,
including the form of 10.25% Senior Subordinated Notes
due 2009.
10.1* 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 5+ Amended and Restated Swift Energy Company 1990
Nonqualified Stock Option Plan, as of May 1997.
10.3 5+ Amended and Restated Swift Energy Company 1990 Stock
Compensation Plan, as of May 1997.
10.4 2+ Amendment to the Swift Energy Company 1990 Stock
Compensation Plan, as of May 9, 2000.
10.5 2+ Swift Energy Company 2001 Omnibus Stock Compensation
Plan.
10.6 3+ Amended and Restated Employment Agreement between Swift
Energy Company and A. Earl Swift, dated November 15,
2000.
10.7 1+ Amended and Restated Employment Agreement dated as of
May 9, 2001, by and between Swift Energy Company and
Terry E. Swift.
10.8 1+ Amended and Restated Employment Agreement dated as of
May 9, 2001, by and between Swift Energy Company and
James M. Kitterman.
61
10.9 1+ Amended and Restated Employment Agreement dated as of
May 9, 2001, by and between Swift Energy Company and
Bruce H. Vincent.
10.10 1+ Amended and Restated Employment Agreement dated as of
May 9, 2001, by and between Swift Energy Company and
Joseph A. D'Amico.
10.11 1+ Employment Agreement dated as of May 9, 2001, by and
between Swift Energy Company and Victor R. Moran.
10.12 1+ Employment Agreement dated as of May 9, 2001, by and
between Swift Energy Company and Donald L. Morgan.
10.13 1+ Amended and Restated Employment Agreement dated as of
May 9, 2001, by and between Swift Energy Company and
Alton D. Heckaman, Jr.
10.14 3+ Fourth Amended and Restated Agreement and Release, by
and between Swift Energy Company and Virgil Neil Swift,
dated November 20, 2000.
10.15 6 Amended and Restated Rights Agreement between Swift
Energy Company and American Stock Transfer & Trust
Company, dated March 31, 1999.
10.16 9 Amended and Restated Credit Agreement among Swift
Energy Company and Bank One, National Association 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.
12* Swift Energy Company Ratio of Earnings to Fixed
Charges.
21 4 List of Subsidiaries of Swift Energy Company.
23(a)* The consent of H. J. Gruy and Associates, Inc.
23(b)* The consent of Arthur Andersen LLP as to incorporation
by reference regarding Forms S-8 and S-3 Registration
Statements.
23(c)* Letter responsive to Temporary Note 3T to Article of
Regulation S-X
99* The summary of H. J. Gruy and Associates, Inc. report,
dated February 14, 2002.
(b) Reports on Form 8-K filed during the year 2001:
1. On May 3, 2001, the Company filed a Current Report on Form 8-K that
reported under Item 5, "Other Events," that the Company was amending
two of the four proposals contained in the Company's proxy statement
for the Company's annual meeting of shareholders to be held on May 8,
2001, and, subject to shareholder approval, the Company intended to
adjourn the meeting until June 7, 2001 to allow shareholders to vote on
the two amended proposals.
2. On December 17, 2001, the Company filed a Current Report on Form 8-K
that reported under Item 2 "Acquisition or Disposition of Assets," that
the Company had signed a Limited Share Sale and Purchase Agreement to
purchase all of the capital stock of Southern Petroleum (New Zealand)
Exploration Limited for approximately US $55 million in cash.
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 Registration Statement No. 333-67242 on Form
S-8 filed on August 10, 2001.
62
3)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.
4)Incorporated by reference from Registration Statement No. 33-60469 on Form S-2
filed on June 22, 1995.
5)Incorporated by reference from Swift Energy Company definitive proxy statement
for annual shareholders meeting filed April 14, 1997, 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 Exhibit 4.2 to Pre-Effective Amendment No. 1 to
Form S-3 Registration Statement No. 33-81651 of Swift Energy Company, filed
July 9, 1999, which Exhibit 4.2 is the form of such Indenture.
8)Incorporated by reference from Swift Energy Company Report on Form 8-K dated
August 4, 1999, File No. 1-8754.
9)Incorporated by reference from Swift Energy Company Quarterly Report on Form
10-Q for the quarterly period ended September 30, 2001.
*Filed herewith.
+Management contract or compensatory plan or arrangement.
63
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant, Swift Energy Company, has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
SWIFT ENERGY COMPANY
By /s/ A. Earl Swift
-----------------------------
A. Earl Swift
Chairman of the Board,
Pursuant to the requirements of the Securities Exchange Act of 1934,
this report has been signed below by the following persons on behalf of the
Registrant, Swift Energy Company, and in the capacities and on the dates
indicated:
Signatures Title Date
----------- ------ -----
/s/ A. Earl Swift
- ---------------------------- Chairman of the Board March 20, 2002
A. Earl Swift
/s/ Terry E. Swift Director
- ---------------------------- Chief Executive Officer March 20, 2002
Terry E. Swift President
/s/ Alton D. Heckaman Jr. Sr. Vice-President--Finance
- ---------------------------- Principal Financial Officer March 20, 2002
Alton D. Heckaman Jr.
/s/ David W. Wesson Controller
- ---------------------------- Principal Accounting Officer March 20, 2002
David W. Wesson
64
/s/ G. Robert Evans
- ---------------------------Director March 20, 2002
G. Robert Evans
/s/ Henry C. Montgomery
- ---------------------------Director March 20, 2002
Henry C. Montgomery
/s/ Clyde W. Smith, Jr.
- ---------------------------Director March 20, 2002
Clyde W. Smith, Jr.
/s/ Virgil N. Swift
- ---------------------------Director March 20, 2002
Virgil N. Swift
/s/ Harold J. Withrow
- ---------------------------Director March 20, 2002
Harold J. Withrow
65
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
EXHIBITS
TO
FORM 10-K REPORT
FOR THE
YEAR ENDED DECEMBER 31, 2001
SWIFT ENERGY COMPANY
16825 NORTHCHASE DRIVE, SUITE 400
HOUSTON, TEXAS 77060
66
EXHIBITS
3(b) By-Laws, as amended through August 14, 1995.
10.1 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).
12 Swift Energy Company Ratio of Earnings to Fixed Charges.
23 (a) The consent of H.J. Gruy and Associates, Inc.
23 (b) The consent of Arthur Andersen LLP as to incorporation by reference
regarding Forms S-8 and S-3 Registration Statements.
23 (c) Letter responsive to Temporary Note 3T to Article of Regulation S-X
99 The summary of H.J. Gruy and Associates, Inc. report, dated February 7,
2002.
67
Exhibit 3(B)
68
BYLAWS OF
SWIFT ENERGY COMPANY
ARTICLE I
SHAREHOLDERS
1. ANNUAL MEETING. The annual meeting of shareholders for the purpose
of electing directors shall be held on such date and time as may be fixed from
time to time by the board of directors and stated in the notice of the meeting.
Any business may be transacted at an annual meeting, except as otherwise
provided by law or by these Bylaws.
2. SPECIAL MEETING. A special meeting of shareholders may be called at
any time by the president or secretary at the request in writing of the holders
of at least ten percent (10%) of the outstanding stock entitled to be voted at
such meeting, or a special meeting of shareholders may be called at any time by
a majority of the members of the board of directors who are "Continuing
Directors," being those directors then in office who have been or will have been
directors for the two year period ending on the date notice of the meeting or
written consent to take such action is first provided to shareholders, or those
directors who have been nominated for election or elected to succeed such
directors by a majority of such directors, or by the chairman of the board or by
the president. Only such business shall be transacted at a special meeting as
may be stated or indicated in the notice of such meeting.
3. MANNER AND PLACE OF MEETING. The annual meeting of shareholders may
be held in any manner permitted by law or these Bylaws at any place within or
without the State of Texas designated by the board of directors. Special
meetings of shareholders may be held in any manner permitted by law or these
Bylaws at any place within or without the State of Texas designated by the
chairman of the board or the President, if he shall call the meeting, or the
board of directors, if they shall call the meeting. Any meeting may be held at
any place within or without the State of Texas designated in a waiver of notice
of such meeting held at the principal office of the corporation unless another
place is designated for meetings in the manner provided herein. Subject to the
provisions herein for notice of meetings, meetings of shareholders may be held
by means of conference telephone or similar communications equipment by means of
which all participants can hear each other.
4. NOTICE. Written or printed notice stating the place, day and hour of
each meeting of shareholders and, in case of a special meeting, the purpose or
purposes for which the meeting is called, shall be delivered not less than ten
(10) nor more than sixty (60) days before the date of the meeting, either
personally or by mail, to each shareholder of record entitled to vote at such
meeting. Whenever any notice is required to be given to any shareholder, a
waiver thereof in writing signed by such person(s) entitled to such notice
(whether signed before or after the time required for such notice) shall be
equivalent to the giving of such notice.
5. BUSINESS TO BE CONDUCTED AT ANNUAL OR SPECIAL MEETING. At an annual
meeting of the shareholders, only such business shall be conducted as shall have
been properly brought before the meeting. To be properly brought before an
annual or special meeting business must be (a) specified in the notice of
meeting (or any supplement thereto) given by or at the direction of the board of
directors, (b) otherwise properly brought before the meeting by or at the
direction of the board of directors, or (c) otherwise properly brought before
the meeting by a shareholder. For business to be
69
properly brought before an annual or special meeting by a shareholder, the
shareholder must have given timely notice thereof in writing to the secretary of
the corporation. To be timely, a shareholder's notice regarding business to be
conducted at an annual meeting must be delivered to or mailed and received at
the principal executive offices of the corporation, not less than 60 days nor
more than 90 days prior to the meeting; provided, however, that in the event
that less than 70 days' notice or prior public disclosure of the date of the
meeting is given or made to shareholders, notice by the shareholder to be timely
must be so received not later than the close of business on the 10th day
following the day on which such notice of the date of the annual meeting was
mailed or such public disclosure was made. To be timely, a shareholder's notice
regarding business to be conducted at a special meeting must be delivered to or
mailed and received at the principal executive offices of the corporation no
later than the date the notice required under Section 4 of this Article I is
provided to the shareholders; provided that, in no event shall the special
meeting be held sooner than forty (40) days after the notice is received by the
corporation. A shareholder's notice to the secretary shall be set forth as to
each matter the shareholder proposes to bring before the meeting (a) a brief
description of the business desired to be brought before the meeting and the
reasons for conducting such business at the meeting, (b) the name and address,
as they appear on the corporation's books, of the shareholder proposing such
business, (c) the class and number of shares of the corporation which are
beneficially owned by the shareholder, and (d) any material interest of the
shareholder in such business. Notwithstanding anything in the Bylaws to the
contrary, no business shall be conducted at any meeting except in accordance
with the procedures set forth in this Section 5. The chairman of the meeting
shall, if the facts warrant, determine and declare to the meeting that business
was not properly brought before the meeting and in accordance with the
provisions of this Section 5, and if he should so determine, he shall so declare
to the meeting and any such business not properly brought before the meeting
shall not be transacted.
6. QUORUM. Except as otherwise required by law, the Articles of
Incorporation or these Bylaws, the holders of at least a majority of the
outstanding shares entitled to vote thereat and present in person or by proxy
shall constitute a quorum. The shareholders present at any meeting, though less
than a quorum, may adjourn the meeting. No notice of adjournment, other than the
announcement at the meeting, need be given.
7. VOTE REQUIRED TO TAKE ACTION. Except as otherwise provided in these
Bylaws or the articles of incorporation, when a quorum is present at any
meeting, the vote of the holders of a majority of the stock having voting power
present in person or represented by proxy shall decide any question brought
before such meeting, unless the question is one upon which by express provision
of the statutes, of the rules of any exchange or quotation system upon which
securities of the corporation are traded, or of the certificate of incorporation
a different vote is required, in which case such express provision shall govern
and control the decision of such question. In addition to the foregoing voting
requirements, the affirmative vote of the holders of at least sixty-six and two
thirds percent (66-2/3%) of the outstanding shares of the capital stock of the
corporation entitled to vote generally in the election of directors shall be
required to sell, assign or dispose of all or substantially all of the
corporation's assets (consisting of more than fifty percent (50%) of either the
total assets or the total proved reserves of the corporation) in one or a series
of related transactions or to merge, consolidate or engage in a share exchange
with another corporation or other entity, or to enter into any transaction
(including the issuance or transfer of securities of the corporation), with any
holder of 20% of the outstanding capital stock of the corporation, if such
transaction is not approved by a majority of the Continuing Directors, as that
term is defined in Article I, Section 2.
8. PROXIES. At all meetings of shareholders, a shareholder may vote
either in person or by proxy executed in writing by the shareholder or by his
duly authorized attorney-in-fact. Such proxies shall be filed with the
corporation before or at the time of the meeting. No proxy shall be valid after
eleven (11) months from the date of its execution unless otherwise provided in
the proxy. Each proxy shall be revocable unless expressly provided therein to be
irrevocable or unless otherwise made irrevocable by law.
9. VOTING OF SHARES. Each outstanding share of a class entitled to vote
upon a matter submitted to a vote at a meeting of shareholders shall be entitled
to one vote on such matter except to the extent that the voting rights are
limited or denied by the Articles of Incorporation. No shareholder shall have
the right to cumulate his votes in the election of directors.
10. OFFICERS. The chairman of the board shall preside at and the
secretary shall keep the records of each meeting of shareholders, but in the
absence of the chairman, the president shall perform the chairman's duties,
70
and in the absence of the secretary and all assistant secretaries, his duties
shall be performed by some person appointed by the presiding officer.
11. LIST OF SHAREHOLDERS. A complete list of shareholders entitled to
vote at each shareholders' meeting, arranged in alphabetical order, with the
address of and number of shares held by each, shall be prepared by the officer
or agent having charge of the stock transfer books and filed at the registered
office of the corporation and shall be subject to inspection by any shareholder
during usual business hours for a period of ten (10) days prior to such
meeting and shall be produced at such meeting and at all times during such
meeting be subject to inspection by any shareholder.
12. ACTION BY WRITTEN CONSENT. Any action required or permitted by
statute, the Articles of Incorporation or these Bylaws to be taken at a meeting
of shareholders may be taken without a meeting if a consent in writing, setting
forth the action so taken, shall be signed by the holder or holders of shares
having not less than the minimum number of votes under these Bylaws or the
Articles of Incorporation of the corporation, or if not specified therein, then
under the provisions of the Texas Business Corporation Act, as amended, or any
similar successor provision (the "TBCA") that would be necessary to take such
action at a meeting at which the holders of all shares entitled to vote on the
action were present and voted. Such consent or consents shall be in such form
and shall be delivered to the corporation in such manner as is specified in
Article 9.10A of the TBCA.
ARTICLE II
BOARD OF DIRECTORS
1. MANAGEMENT. The business and affairs of the corporation shall be
managed by the board of directors. The board may exercise all such powers of the
corporation and do all such lawful acts and things as are not by statute, by the
Articles of Incorporation or these Bylaws directed or required to be exercised
or done by the shareholders.
2. NUMBER. The board of directors shall consist of seven directors, but
the number of directors may be increased or decreased (provided such decrease
does not shorten the term of any incumbent director) from time to time by a
majority of the Continuing Directors, provided that the number of directors
shall never be less than three nor more than nine.
3. ELECTION AND TERM.
(A) Commencing with the term of directors commencing upon conclusion
of the annual meeting of shareholders scheduled for May 1996, the directors
shall be divided into three classes, as nearly equal in number as the then total
number of directors constituting the entire board permits, with the term of
office of one class expiring each succeeding year. Commencing with the 1996
annual meeting of shareholders, directors of the first class shall be elected to
hold office for a term expiring at the next succeeding annual meeting, directors
of the second class shall be elected to hold office for a term expiring at the
second succeeding annual meeting, and directors of the third class shall be
elected to hold office for a term expiring at the third succeeding annual
meeting. Thereafter, at each annual meeting of shareholders the successors to
the class of directors whose term shall then expire, shall be elected to hold
office until the third succeeding annual meeting or until their respective
successors shall have been elected and qualified, unless removed in accordance
with these Bylaws. Directors need not be shareholders or residents of Texas.
(B) Any vacancies in the board of directors for any reason, and any
directorships resulting from any increase in the number of directors, may be
filled by the board of directors, acting by a majority of the directors then in
office, although less than a quorum, and any directors so chosen shall hold
office until the next election of the class for which such directors shall have
been chosen or until their successors shall be elected and qualified.
71
4. DIRECTOR NOMINATION PROCEDURES. Only persons who are nominated in
accordance with the procedures set forth in this Section 4 shall be eligible for
election as directors. Nominations of persons for election to the board of
directors of the corporation may be made at a meeting of shareholders (a) by or
at the direction of the board of directors or (b) by any shareholder of the
corporation entitled to vote for the election of directors at the meeting who
complies with the notice procedures set forth in this Section 4. Such
nominations, other than those made by or at the direction of the board of
directors, shall be made pursuant to timely notice in writing to the secretary
of the corporation. To be timely, a shareholder's notice shall be delivered to
or mailed and received at the principal executive offices of the corporation (a)
in the case of an annual meeting, not less than 60 days nor more than 90 days
prior to the first anniversary of the preceding year's annual meeting; provided,
however, that in the event that the date of the annual meeting is changed by
more than 30 days from such anniversary date, notice by the shareholder to be
timely must be so received not later than the close of business on the 10th day
following the day on which such notice of the date of the meeting was mailed or
public disclosure was made, and (b) in the case of a special meeting at which
directors are to be elected, not later than the close of business on the 10th
day following the day on which such notice of the date of the meeting was mailed
or public disclosure was made. Such shareholder's notice shall set forth (a) as
to each person whom the shareholder proposes to nominate for election or
re-election as a director, (i) the name, age, business address and residence
address of such person, (ii) the principal occupation or employment of such
person, (iii) the class and number of shares, if any, of the corporation which
are beneficially owned by such person, and (iv) any other information relating
to such person that is required to be disclosed in solicitations of proxies for
election of directors, or is otherwise required, in each case pursuant to
Regulation 14A under the Securities Exchange Act of 1934, as amended (including
without limitation such persons' written consent to being named in the proxy
statement as a nominee and to serving as a director if elected); and (b) as to
the shareholder giving the notice (i) the name and address, as they appear on
the corporation's books, of such shareholder and (ii) the class and number of
shares of the corporation which are beneficially owned by such shareholder. At
the request of the board of directors any person nominated by the board of
directors for election as a director shall furnish to the secretary of the
corporation that information required to be set forth in a shareholder's notice
of nomination which pertains to the nominee. No person shall be eligible for
election as a director of the corporation unless nominated in accordance with
the procedures set forth in this Section 4. The chairman of the meeting shall,
if the facts warrant, determine and declare to the meeting that a nomination was
not made in accordance with the procedures prescribed by the Bylaws, and if he
should so determine, he shall so declare to the meeting and the defective
nomination shall be disregarded.
5. REMOVAL. Any director or the entire board of directors of the
corporation may be removed at any time, with or without cause by the affirmative
vote of the holders of sixty-six and two-thirds percent (66-2/3%) or more of the
outstanding shares of capital stock of the corporation entitled to vote
generally in the election of directors cast at a meeting of the shareholders
called for that purpose and for which notice was provided in accordance with
these Bylaws.
6. MEETING OF DIRECTORS. The directors may hold their meetings and may
have an office and keep the books of the corporation, except as otherwise
provided by statute, in such place or places in the State of Texas, or outside
the State of Texas, as the board of directors may from time to time determine.
The directors may hold their meetings in any manner permitted by law, including,
by conference telephone or similar communications equipment by means of which
all participants can hear each other.
7. FIRST MEETING. Each newly elected board of directors may hold its
first meeting for the purpose of organization and the transaction of business,
if a quorum is present, immediately after and at the same place as the annual
meeting of the shareholders, and no notice of such meeting shall be necessary.
8. ELECTION OF OFFICERS. At the first meeting of the board of directors
in each year at which a quorum shall be present, directors shall proceed to the
election of the officers of the corporation.
9. REGULAR MEETINGS. Regular meetings of the board of directors shall
be held in any manner permitted by law or these Bylaws and at such times and
places as shall be designated, from time to time by resolution of the board of
directors. Notice of such regular meetings shall not be required.
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10. SPECIAL MEETINGS. Special meetings of the board of directors shall be
held in any manner permitted by law or these Bylaws and whenever called by the
chairman of the board, the president or by a majority of the Continuing
Directors (as that term is defined in Article I, Section 2).
11. NOTICE. The secretary shall give notice of each special meeting in
person, or by mail or telegraph at least two (2) days before the meeting to each
director. The attendance of a director at any meeting or the participation by a
director in a conference meeting shall constitute a waiver of notice of such
meeting, except where a director attends a meeting or participates in a
conference meeting for the express purpose of objecting to the transaction of
any business on the grounds that the meeting is not lawfully called or convened.
Neither the business to be transacted at, nor the purpose of, any regular or
special meeting of the board of directors need be specified in the notice or
waiver of notice of such meeting.
At any meeting at which every director shall be present in person or by
participation, even though without any notice, any business may be transacted.
Whenever any notice is required to be given to any director, a waiver
thereof in writing signed by such person(s) entitled thereto (whether signed
before or after the time required for such notice) shall be equivalent to the
giving of such notice.
12. QUORUM. A majority of the directors fixed by these Bylaws shall
constitute a quorum for the transaction of business, but if at any meeting of
the board of directors there be less than a quorum present, a majority of those
present or any director solely present may adjourn the meeting from time to time
without further notice. The act of a majority of the directors present at a
meeting at which a quorum is in attendance shall be the act of the board of
directors, unless the act of a greater number is required by statute, the
Articles of Incorporation, or by these Bylaws.
13. ORDER OF BUSINESS. At meetings of the board of directors, business
shall be transacted in such order as from time to time the board may determine.
At all meetings of the board of directors, the chairman of the board of
directors shall preside, and in the absence of the chairman of the board and the
president, a chairman shall be chosen by the board from among the directors
present.
The secretary of the corporation shall act as secretary of all meetings
of the board of directors, but in the absence of the secretary the presiding
officer may appoint any person to act as secretary of the meeting.
14. ACTION BY WRITTEN CONSENT. Any action required or permitted to be
taken by the board of directors or executive committee, under the applicable
provisions of the statutes, the Articles of Incorporation or these Bylaws, may
be taken without a meeting if a consent in writing, setting forth the action so
taken, is signed by all the members of the board of directors or executive
committee, as the case may be.
15. COMPENSATION. Directors as such shall not receive any stated salary
for their services, but by resolution of the board a fixed sum and expense of
attendance, if any, may be allowed for attendance at such regular or special
meetings of the board; provided that nothing contained herein shall be construed
to preclude any director from serving the corporation in any other capacity or
receiving compensation therefor.
16. PRESUMPTION OF ASSENT. A director of the corporation who is present
at a meeting of the board of directors at which action of any corporate matter
is taken shall be presumed to have assented to the action unless his dissent
shall be entered in the minutes of the meeting or unless he shall file his
written dissent to such action with the person acting as secretary of the
meeting before the adjournment thereof or shall forward such dissent by
registered mail to the secretary of the corporation immediately after the
adjournment of the meeting. Such right to dissent shall not apply to a director
who voted in favor of such action.
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17. COMMITTEES. The board of directors, by resolution adopted by a majority
of the number of directors fixed by these Bylaws, may designate one or more
directors to constitute an Executive Committee or any other committee, which
committees, to the extent provided in such resolution, shall have and may
exercise all of the authority of the board of directors in the business and
affairs of the corporation except where action of the board of directors is
specified by law, but the designation of any such committee and the delegation
thereto of authority shall not operate to relieve the board of directors, or any
member thereof, of any responsibility imposed upon it or him by law. The
executive committee shall keep regular minutes of its proceedings and report the
same to the board when required.
ARTICLE III
OFFICERS
1. NUMBER, TITLES AND TERM OF OFFICE. The officers of the corporation
shall be a chairman of the board, a president, one or more vice presidents, a
secretary, a treasurer, and such other officers as the board of directors may
from time to time elect or appoint. Each officer shall hold office until his
successor shall have been duly elected by the board and qualified or until his
death or until he shall resign or shall have been removed in the manner
hereinafter provided. One person may hold more than one office, except that the
president shall not hold the office of secretary. None of the officers need be a
director.
2. REMOVAL. Any officer or agent elected or appointed by the board of
directors may be removed by the board of directors whenever in its judgment the
best interests of the corporation will be served thereby, but such removal shall
be without prejudice to the contract rights, if any, of the person so removed.
Election or appointment of an officer or agent shall not of itself create
contract rights.
3. VACANCIES. A vacancy in the office of any officer may be filled by
vote of a majority of the directors for the unexpired portion of the term.
4. SALARIES. The salaries of all officers of the corporation shall be
fixed by the board of directors except as otherwise directed by the board.
5. POWERS AND DUTIES OF THE CHAIRMAN OF THE BOARD. The chairman of the
board shall preside at all meetings of the shareholders and of the board of
directors and shall have such other powers and duties as from time to time may
be assigned to him by the board of directors.
6. POWERS AND DUTIES OF THE PRESIDENT. The president shall be the chief
executive officer of the corporation and, subject to the board of directors, he
shall have general executive charge, management and control of the properties
and operations of the corporation in the ordinary course of its business with
all such powers with respect to such responsibilities; he shall preside in the
absence of the chairman of the board at all meetings of the shareholders and of
the board of directors; he shall be an ex-officio member of all standing
committees; he may agree upon and execute all division and transfer orders,
bonds, contracts and other obligations in the name of the corporation; he may
sign all certificates for shares of capital stock of the corporation; and he
shall see that all orders and resolutions of the board of directors are carried
into effect.
7. VICE PRESIDENTS. Each vice president shall have such powers and
duties as may be assigned to him by the board of directors and shall exercise
the powers of the president during that officer's absence or inability to act.
Any action taken by a vice president in the performance of the duties of the
president shall be conclusive evidence of the absence or inability to act of the
president at the time such action was taken.
8. TREASURER. The treasurer shall have custody of all the funds and
securities of the corporation which come into his hands. When necessary or
proper, he may endorse, on behalf of the corporation, for collection, checks,
notes and other obligations and shall deposit the same to the credit of the
corporation in such bank or banks or depositories as shall be designated in the
manner prescribed by the board of directors; he may sign all receipts and
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vouchers for payments made to the corporation, either alone or jointly with such
other officer as is designated by the board of directors. Whenever required by
the board of directors, he shall render a statement of his cash account; he
shall enter or cause to be entered regularly in the books of the corporation to
be kept by him for that purpose full and accurate accounts of all monies
received and paid out on account of the corporation; he shall perform all acts
incident to the position of treasurer subject to the control of the board of
directors; he shall, if required by the board of directors, give such bond for
the faithful discharge of his duties in such form as the board of directors may
require.
9. ASSISTANT TREASURER. Each assistant treasurer shall have the usual
powers and duties pertaining to his office, together with such other powers and
duties as may be assigned to him by the board of
directors. The assistant treasurer shall exercise the powers of the treasurer
during that officer's absence or inability to act.
10. SECRETARIES. The secretary shall keep the minutes of all meetings
of the board of directors and the minutes of all meetings of the shareholders in
books provided for that purpose or in any other form capable of being converted
into written form within a reasonable time; he shall attend to the giving and
serving of all notices; he may sign with the president in the name of the
corporation, all contracts of the corporation and affix the seal of the
corporation thereto; he may sign with the president all certificates for shares
of the capital stock of the corporation; he shall have charge of the certificate
books, transfer books and stock ledgers, and such other books and papers as the
board of directors may direct, all of which shall at all reasonable times be
open to the inspection of any director upon application at the office of the
corporation during business hours, and he shall in general perform all duties
incident to the office of secretary, subject to the control of the board of
directors.
11. ASSISTANT SECRETARIES. Each assistant secretary shall have the
usual powers and duties pertaining to his office, together with such other
powers and duties as may be assigned to him by the board of directors or the
secretary. The assistant secretaries shall exercise the powers of the secretary
during that officer's absence or inability to act.
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ARTICLE IV
INDEMNIFICATION AND INSURANCE
1. INDEMNIFICATION OF DIRECTORS
A. Definitions. For purposes of this Article:
-----------
(1) "Expenses" include court costs and
attorneys' fees.
(2) "Official capacity" means
(a) when used with respect to a director,
the office of director in the corporation,
and
(b) when used with respect to a person other
than a director, the elective or appointive
office in the corporation held by the
officer or the employment or agency
relationship undertaken by the employee or
agent on behalf of the corporation, but
(c) in both Paragraphs (a) and (b), such
term does not include service for any other
foreign or domestic corporation or any
partnership, joint venture, sole
proprietorship, trust, employee benefit
plan, or other enterprise, except as may
otherwise be specified in Section 2 or 3
hereunder.
(3) "Proceeding" means any threatened, pending,
or completed action, suit, or proceeding, whether civil, criminal,
administrative, arbitrative, or investigative, any appeal in such an action,
suit, or proceeding, and any inquiry or investigation that could lead to such an
action, suit, or proceeding.
B. Indemnification where director has been wholly
successful in the proceeding. The corporation shall indemnify a director
against reasonable expenses incurred by him in connection with a proceeding in
which he is a named defendant or respondent because he is or was a director if
he has been wholly successful, on the merits or otherwise, in the defense of
the proceeding.
C. Indemnification where director has not been wholly
successful in proceeding.
(1) The corporation shall indemnify a person
who was, is, or is threatened to be made a named defendant or respondent in
a proceeding because the person is or was a director of the corporation, and
who does not qualify for indemnification under subsection B of this Section,
if it is determined, in accordance with the procedure set out in Section F of
Article 2.02-1 of the Texas Business Corporation Act ("TBCA"), that the person:
(a) conducted himself in good faith;
(b) reasonably believed:
(i) in the case of conduct in
his official capacity as a
director of the corporation,
that his conduct was in the
corporation's best
interests; and
(ii) in all other cases, that his
conduct was at least not
opposed to the corporation's
best interests; and
(c) in the case of any criminal
proceeding, had no reasonable cause to
believe his conduct was unlawful.
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If it is determined pursuant to Section F of Article 2.02-1 of the TBCA
that indemnification is to be authorized, the corporation shall determine the
reasonableness of the expenses claimed by the director seeking indemnification
in accordance with the procedure set out in Section G of Article 2.02-1 of the
TBCA.
(2) The termination of a proceeding by
judgment,order, settlement, or conviction, or on a plea of nolo contendere
or itsequivalent, is not of itself determinative that the person did not meet
the requirements set forth in subsection C(1)hereof. A person shall be deemed to
have been found liable in respect of any claim, issue or matter only after the
person shall have been so adjudged by a court of competent jurisdiction after
exhaustion of all appeals therefrom.
(3) A person shall be indemnified under
subsection C(1) hereof against judgments, penalties(including excise and similar
taxes), fines, settlements, and reasonable expenses actually incurred by the
person inconnection with the proceeding; but if the person is found liable
to thecorporation or is found liable on the basis that personal benefit was
improperly received by the person, the indemnification (1) is limited to
reasonable expenses actually incurred by the person in connection with the
proceeding and (2) shall not be made in respect of any proceeding in which the
person shall have been found liable for willful or intentional misconduct in
the performance of his duty to the corporation.
(4) Except as otherwise provided in subsection
C(3), a director may not be indemnified under subsection C(1) of this Section
for obligations resulting from a proceeding:
(d) in which the director is found
liable on the basis that personal benefit
was improperly received by him, whether or
not the benefit resulted from an action in
the director's official capacity; or
(e) in which the director is found
liable to the corporation.
D. Court-ordered indemnification. A director may apply
to a court of competent jurisdiction for indemnification from the corporation,
whether or not he has met the requirements set forth in subsection C(1) hereof
or has been adjudged liable in the circumstances set out in the second clause
of subsection C(3) hereof. If a director of the corporation seeks to obtain
court-ordered indemnification pursuant hereto, the corporation and its board of
directors shall cooperate fully with such director in satisfying the procedural
steps required therefor.
E. Advancement of expenses. Reasonable expenses incurred
by a director who was, is, or is threatened to be made a named defendant or
respondent in a proceeding shall be paid or reimbursed by the corporation
in advance of the final disposition of the proceeding and without any of the
determinations specified in Sections F and G of Article 2.02-1 of the TBCA if
the requirements of Sections K and L of Article 2.02-1 of the TBCA are
atisfied. The board of directors may authorize the corporation's counsel to
represent such individual in any proceeding, whether or not the corporation is a
party thereto.
F. Directors as witnesses. The corporation shall pay
or reimburse expenses incurred by a director in connection with his appearance
as a witness or other participation in a proceeding at a time when he is not a
named defendant or respondent in the proceeding.
G. Notice to shareholders. Any indemnification of or
advancement of expenses to a director in accordance with this Section shall be
reported in writing to the shareholders of the corporation with or before the
notice or waiver of notice of the next shareholders' meeting or with or before
the next submission to shareholders of a consent to action without a meeting
pursuant to Section A of Article 9.10 of the TBCA and, in any case, within the
twelve-month period immediately following the date of the indemnification or
advance.
H. Directors' services to benefit plans. For purposes
of this Article IV, the corporation is deemed to have requested a director to
serve an employee benefit plan whenever the performance by him of his duties to
the corporation also imposes duties on or otherwise involves services by him
to the plan or participants or beneficiaries of the plan. Excise taxes assessed
on a director with respect to an employee benefit plan pursuant to applicable
law are deemed fines. Action taken or omitted by him with respect to an employee
benefit plan in the performance of his duties for a purpose reasonably believed
by him to be in the interest of the participants and beneficiaries of the plan
is deemed to be for a purpose which is not opposed to the best interests of the
corporation.
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2. INDEMNIFICATION OF OFFICERS
A. In general. The corporation shall indemnify and
advance expenses to an officer of the corporation in the same manner and to the
same extent as is provided by Section 1 of this Article for a director. An
officer is entitled to seek indemnification to the same extent as a director.
B. Additional rights to indemnification. The corporation
may, at the discretion of the board of directors in view of all the relevant
circumstances, indemnify and advance expenses to a person who is an officer,
employee or agent of the corporation and who is not a director of the
corporation to such further extent, consistent with law, as may be provided
by its articles of incorporation, by general or specific actions of its board
of directors, by contract, or as permitted or required by common law.
3. INDEMNIFICATION OF OTHER PERSONS. The corporation may, at the
discretion of the board of directors in view of the relevant circumstances,
indemnify and advance expenses to persons who are not or were not officers,
employees, or agents of the corporation but who are or were serving at the
request of the corporation as directors, officers, partners, venturers,
proprietors, trustees, employees, agents, or similar functionaries of another
foreign or domestic corporation, partnership, joint venture, sole
proprietorship, trust, employee benefit plan, or other enterprise, to the same
extent that it may indemnify and advance expenses to directors hereunder.
4. PROCEDURE FOR INDEMNIFICATION. To request indemnification
pursuant hereto, written notice describing the circumstances and proceedings
giving rise to such request shall be submitted to the corporation at its
principal office. Any indemnification of a director or officer of the
corporation, or another person entitled to indemnification pursuant to Section 3
hereof, or advance of costs, charges and expenses to a director or officer or
another person entitled to indemnification pursuant to Section 3 hereof, hall
be made promptly, and in any event within 30 days, upon the written notice
of such individual. If a determination by the corporation that the individual
is entitled to indemnification pursuant to this Article is required, and the
corporation fails to respond within 60 days to a written request for indemnity,
the corporation shall be deemed to have approved such request. If the
corporation denies a written request for indemnity or advancement of expenses,
in whole or in part, or if payment in full pursuant to such request is not made
within 30 days, the right to indemnification or advances as granted by this
Article shall be enforceable by such individual in any court of competent
jurisdiction in Harris County, Texas. It shall be a defense to any such action
(other than an action brought to enforce a claim for the advance of reasonable
expenses where the required undertaking, if any, has been received by the
corporation) that the claimant has not met the standard of conduct set forth in
subsection 1(C)(1) hereof, but the burden of proving such defense shall be on
the corporation. Neither the failure of the corporation to have made a
determination prior to the commencement of such action that indemnification of
the claimant is proper in the circumstances because he has met the applicable
standard of conduct set forth in subsection 1(C)(1) hereof, nor the fact
that there has been an actual determination by the corporation that the claimant
has not met such applicable standard of conduct, shall be a defense to the
action or create a presumption that the claimant has not met the applicable
standard of conduct.
5. SURVIVAL; PRESERVATION OF OTHER RIGHTS. The foregoing
indemnification provisions contained in this Article shall be deemed to be a
contract between the corporation and each director, officer, employee or
agent, or another person entitled to indemnification pursuant to Section 3
hereof, who serves in any such capacity at any time while these provisions, as
well as the relevant provisions of the TBCA are in effect, and any repeal or
modification thereof shall not affect any right or obligation then existing with
respect to any state of facts then or previously existing or any action, suit
or proceeding previously or thereafter brought or threatened based in whole
or in part upon any such state of facts. Such a "contract right" may not
be modified retroactively without the consent of such director or officer,
employee, agent or another person entitled to indemnification pursuant to
Section 3 hereof. Notwithstanding this provision, the corporation may enter
into additional contracts of indemnity with these persons, which contracts may
provide the same rights as provided by this Article, r may restrict or increase
the rights provided by this Article.
6. INSURANCE. The corporation may purchase and maintain insurance
on behalf of any person who is or was a director, officer, employee, or agent of
the corporation or who is or was serving at the request of the corporation as a
director, officer, partner, venturer, proprietor, trustee, employee, agent,
or similar functionary of another foreign or domestic corporation, partnership,
joint venture, sole proprietorship, trust, other enterprise, or
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employee benefit plan, against any liability asserted against him and incurred
by him in such a capacity or arising out of his status as such a person, whether
or not the corporation would have the power to indemnify him against that
liability hereunder. If the insurance or other arrangement is with a person or
entity that is not regularly engaged in the business of providing insurance
coverage, the insurance or arrangement may provide for payment of a liability
with respect to which the corporation would not have the power to indemnify the
person only if including coverage for the additional liability has been approved
by the shareholders of the corporation. Without limiting the power of the
corporation to procure or maintain any kind of insurance or other arrangement,
the corporation may, for the benefit of persons indemnified by the corporation,
(1) create a trust fund; (2) establish any form of self-insurance; (3) secure
its indemnity obligation by grant of a security interest or other lien on the
assets of the corporation; or (4) establish a letter of credit, guaranty, or
surety arrangement. The insurance or other arrangement may be procured,
maintained, or established within the corporation or with any insurer or other
person deemed appropriate by the board of directors regardless of whether all or
part of the stock or other securities of the insurer or other person are owned
in whole or part by the corporation. In the absence of fraud, the judgment of
the board of directors as to the terms and conditions of the insurance or other
arrangement and the identity of the insurer or other person participating in an
arrangement shall be conclusive and the insurance or arrangement shall not be
voidable and shall not subject the directors approving the insurance or
arrangement to liability, on any ground, regardless of whether directors
participating in the approval are beneficiaries of the insurance or arrangement.
7. SEVERABILITY. If this Article or any portion hereof shall
be invalidated on any ground by any court of competent jurisdiction, then the
corporation shall nevertheless indemnify each director or officer, employee
or agent, as to expenses, judgments, fines and amounts paid in settlement with
respect to any proceeding, to the fullest extent permitted by any applicable
portion of this Article that shall not have been invalidated and to the fullest
extent permitted by applicable law. If any provision hereof should be held, by a
court of competent jurisdiction, to be invalid, it shall be limited only to the
extent necessary to make such provision enforceable, it being the intent of
these Bylaws to indemnify each individual who serves or who has served as a
director, officer, employee or agent, to the maximum extent permitted by laws.
ARTICLE V
CAPITAL STOCK
1. CERTIFICATE OF SHARES. The certificates for shares of the
capital stock of the corporation shall be in such form as shall be approved by
the board of directors. The certificates shall be signed by the president or
a vice president, and also by the secretary or an assistant secretary or by the
treasurer or an assistant treasurer and may be sealed with the seal of this
corporation or a facsimile thereof. Where any such certificate is countersigned
by a transfer agent, or registered by a registrar, either of which is other than
the corporation itself or an employee of the corporation, the signatures of any
such president or vice president and secretary or assistant secretary m ay be
facsimiles. They shall be consecutively numbered and shall be entered in the
books of the corporation as they are issued and shall exhibit the holder's name
and the number of shares.
2. TRANSFER OF SHARES. The shares of stock of the corporation
shall be transferable only on the books of the corporation by the holders
thereof in person or by their duly authorized attorneys or legal
representatives, upon surrender to the corporation of a certificate for share
duly endorsed or accompanied by proper evidence of succession, assignment or
authority to transfer, and it shall be the duty of the corporation to issue a
new certificate to the person entitled thereto for a like number of shares to
cancel the old certificate, and to record the transaction upon its books.
3. CLOSING OF TRANSFER BOOKS. For the purpose of determining
shareholders entitled to notice of or to vote at any meeting of shareholders,
or any adjournment thereof, or entitled to receive payment of any dividend,
or in order to make a determination of shareholders for any other proper
purpose, the board of directors of the corporation may provide that the stock
transfer books shall be closed for a stated period but not to exceed, in any
case, sixty (60) days. If the stock transfer books shall be closed for the
purpose of determining shareholders entitled to notice of or to vote at a
meeting of shareholders, such books shall be closed for at least ten (10) days
immediately preceding such meeting. In lieu of closing the stock transfer
books, the board of directors may fix in advance a date as the record date for
any such determination of shareholders, such date in any case to be not more
than sixty (60) days and, in case of a meeting of shareholders, not less than
ten (10) days prior to the date on which the particular
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action requiring such determination of shareholders is to be taken. If the stock
transfer books are not closed and no record date is fixed for the determination
of shareholders entitled to notice of or to vote at a meeting of shareholders,
or shareholders entitled to receive payment of a dividend, the date on which the
notice of the meeting is mailed or the date on which the resolution of the board
of directors declaring such dividend is adopted, as the case may be, shall be
the record date for such determination of shareholders. When a determination of
shareholders entitled to vote at any meeting of shareholders has been made as
herein provided, such determination shall apply to any adjournment thereof
except where the determination has been made through the closing of stock
transfer books and the stated period of closing has expired.
4. REGISTERED SHAREHOLDERS. The corporation shall be entitled
to recognize the exclusive right of a person registered on its books as the
owner of the share to receive dividends, and to vote as such owner, and for all
other purposes as such owner; and the corporation shall not be bound to
recognize any equitable or other claim to or interest in such share or shares
on the part of any other person, whether or not it shall have express or other
notice thereof, except as otherwise provided by the laws of Texas.
5. LOST CERTIFICATE. The board of directors may direct a new
certificate or certificates to be issued in place of any certificate or
certificates theretofore issued by the corporation alleged to have been lost
or destroyed, upon the making of an affidavit of that fact by the person
claiming the certificate of stock to be lost or destroyed. When authorizing
such issue of a new certificate or certificates, the board of directors may,
in its discretion and as a condition precedent to the issuance thereof, require
the owner of such lost or destroyed certificate or certificates, or his legal
representative, to advertise the name in such manner as it shall require and/or
give the corporation a bond in such sum as it may direct as indemnity against
any claim that may be made against the corporation with respect to the
certificate alleged to have been lost or destroyed.
6. REGULATIONS. The board of directors shall have power and
authority to make all such rules and regulations as they may deem expedient
concerning the issue, transfer and registration or the replacement of
certificates for shares of the capital stock of the corporation not inconsistent
with these Bylaws.
ARTICLE VI
ACCOUNTS
1. DIVIDENDS. The board of directors may from time to time
declare, and the corporation may pay, dividends on its outstanding shares,
except when the declaration or payment thereof would be contrary to statute or
the Articles of Incorporation. Such dividends may be declared at any regular
or special meeting of the board, and the declaration and payment shall be
subject to all applicable provisions of laws, the Articles of Incorporation and
these Bylaws.
2. RESERVES. Before payment of any dividend, there may b e set
aside out of any funds of the corporation available for dividends such sum or
sums as the directors from time to time, in their absolute discretion, deem
proper as a reserve fund to meet contingencies, or for equalizing dividends, or
for repairing or maintaining any property of the corporation, or for such
other purpose as the directors shall think conducive to the interest of the
corporation, and the directors may modify or abolish any such reserve in the
manner in which it was created.
3. DIRECTORS' ANNUAL STATEMENT. The board of directors shall
present at each annual meeting a full and clear statement of the business and
condition of the corporation. The officers of the corporation shall mail to any
shareholder of record, upon his written request, the latest annual financial
statement and the most recent interim financial statements, if any, which have
been filed in a public record or otherwise published.
4. CHECKS. All checks or demands for money and notes of the
corporation shall be signed by such officer or officers or such other person or
persons as the board of directors may from time to time designate.
5. FISCAL YEAR. The fiscal year of the corporation shall be
such as established by resolution of the board of directors.
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ARTICLE VII
AMENDMENTS
These Bylaws may be altered, amended or repealed or new Bylaws may be
adopted at any annual meeting of the board of directors or at any special
meeting of the board of directors at which a quorum is present provided notice
of the proposed alteration, amendment, repeal or adoption be contained in the
notice of such meeting, by the affirmative vote of a majority of the Continuing
Directors (as that term is defined in Article I, Section 2); provided, however,
that no change of the time or place of the annual meeting of the board of
directors shall be made after the issuance of notice thereof. In accordance with
the Articles of Incorporation, the shareholders may amend or repeal any
provisions of these Bylaws adopted by the board of directors, but only by the
affirmative vote of the holders of sixty-six and two-thirds percent (66"%) or
more of the outstanding capital stock of the corporation.
ARTICLE VIII
MISCELLANEOUS PROVISIONS
1. OFFICES. Until the board of directors otherwise determines,
the registered office of the corporation required by the TBCA to be maintained
in the state of Texas shall be that registered office set forth in the Articles
of Incorporation, but such registered office may be changed from time to time
by the board of directors in the manner provided by law and need not be
identical to the principal place of business of the corporation.
2. SEAL. The seal of the corporation shall be such as from time
to time may be approved by the board of directors, but the use of a seal shall
not be essential to the validity of any agreement.
3. NOTICE AND WAIVER OF NOTICE. Whenever any notice whatever is
required to be given under the provisions of these Bylaws, said notice shall
be deemed to be sufficient if given by depositing the same in a post office
box in a sealed postpaid wrapper addressed to the person entitled thereto at his
post office address, as it appears on the b ooks of the corporation, and such
notice shall be deemed to have been given on the day of such mailing. A waiver
of notice, signed by the person or persons entitled to said notice, whether
before or after the time stated therein, shall be deemed equivalent thereto.
4. RESIGNATIONS. Any director or officer may resign at any time.
Such resignations shall be made in writing and shall take effect at the time
specified therein, or, if no time be specified, at the time of its receipt by
the president or secretary. The acceptance of a resignation shall not be
necessary to make it effective, unless expressly so provided in the resignation.
5. SECURITIES OF OTHER CORPORATIONS. The chairman of the board,
the president or any vice president of the corporation shall have power and
authority to transfer, endorse for transfer, vote, consent or take any other
action with respect to any securities of another issuer which may be held or
owned by the corporation and to make, execute and deliver any waiver, proxy or
consent with respect to any such securities.
/s/ John R. Alden
-----------------------------
John R. Alden
August 15, 1995 Secretary
81
Exhibit 10.1
82
INDEMNITY AGREEMENT
This Agreement is made as of the 8th day of July, 1988 by and between
Swift Energy Company, a Texas corporation (the "Corporation"), and A. Earl Swift
(the "Indemnitee"). For the purposes of this Agreement, all references to the
"Corporation" shall include all subsidiaries, affiliates, partnerships,
enterprises or other entities related to the Corporation on behalf of which the
Indemnitee serves as officer, director, employee, partner or agent or in a
related capacity, and shall include in addition to the resulting corporation,
any constituent corporation (including any constituent or subsidiary of a
constituent) absorbed in a consolidation or merger which, if its separate
existence had continued, would have had the power and authority to indemnify its
officers, directors, employees or agents, so that any such person who was
serving that constituent corporation will have the benefit of this Agreement
with respect to that constituent corporation as if its separate existence had
continued.
In addition to the indemnification to which the Indemnitee may be
entitled pursuant to the Bylaws of the Corporation and the terms of the director
and officer liability insurance policy maintained by the Corporation, the
Corporation may, at its discretion and expense, furnish an insurance trust to be
funded by the Corporation to insure the officers, directors, employees and
agents against primary liability, to protect the Indemnitee in connection with
his service.
In order to induce the Indemnitee to continue to serve the Corporation
in his current capacity, and in consideration of his continued service after the
date hereof, the parties hereby agree as follows:
1. The Corporation will promptly pay on behalf of the Indemnitee, and his
executors, administrators and heirs, any and all amounts which he is or
becomes legally obligated to pay as a result of any claim or claims
threatened or made against him as a result of any act or omission or
neglect or breach of duty, including any actual or alleged error or
misstatement or misleading statement, which he commits (or is alleged
to commit) or suffers while acting in his current capacity in the
service of the Corporation and solely because of his acting in such
capacity. The payments which the Corporation will be obligated to make
hereunder shall include, without limitation, any damages, judgments,
settlements and costs, costs of investigation and costs of defense of
legal actions, claims or proceedings and appeals therefrom, and costs
of attachment or similar bonds. It is the intent of the parties to
provide the most complete indemnification hereunder which is allowed by
applicable law.
2. Expenses incurred by the Indemnitee or his executors, administrators
and heirs (including attorney's fees) in defending any civil or
criminal action, suit, proceeding or investigation shall be paid by the
Corporation in advance of the final disposition of such action, suit,
proceeding or investigation upon written demand of the Indemnitee or
his executors, administrators and heirs and the tender by or on the
behalf of the Indemnitee or his executors, administrators and heirs of
a written undertaking to repay such amount if it shall ultimately be
determined that the Indemnitee is not entitled to be indemnified as
authorized by this Agreement.
3. If the Corporation does not respond to a written claim for payment
under this Agreement within thirty days of having received such a
claim, it shall be deemed to have waived any right to refuse to pay
such claim under this Agreement. In addition, if a claim under this
Agreement is not paid by the Corporation, or on its behalf, within
sixty days after a written claim has been received by the Corporation,
the claimant may at any time thereafter bring suit against the
Corporation to recover the unpaid amount of the claim and the
Corporation shall have the burden of proving that the Indemnitee is not
entitled to indemnification under this Agreement. If successful in
whole or in part, the claimant shall be entitled to also be paid all
expenses (including attorneys' fees) of prosecuting such claim.
4. In the event of payment under this Agreement, the Corporation shall be
subrogated to the extent of such payment to all of the rights of
recovery of the Indemnitee, who shall execute all documents and take
all actions reasonably requested by the Corporation to implement such
right of subrogation.
5. Notwithstanding any other provision in this Agreement, the Corporation
shall not be liable under this Agreement to make any payment in
connection with any claim made against the Indemnitee:
(a) for which payment is actually made to the Indemnitee under a
valid and collectible insurance policy maintained by the
Corporation or the Corporation's self-funded insurance trust, if
any, except in respect of any excess beyond the amount of
payment under such insurance;
83
(b) if the Indemnitee is found liable for willful or intentional
misconduct in the performance of his duty to the Corporation;
(c) if the Indemnitee is found liable to the Corporation or is found
liable on the basis that personal benefit was improperly
received by the Indemnitee, except that in both such instances,
the Indemnitee will be indemnified to the extent of reasonable
expenses actually incurred by the Indemnitee in connection with
the proceeding;
(d) for an accounting of profits made from the purchase or sale by
the Indemnitee of securities of the Corporation within the
meaning of Section 16(b) of the Securities Exchange Act of 1934
and amendments thereto or similar provisions of any state
statutory law or common law;
(e) for which indemnification under this Agreement is determined by
a final adjudication of a court of competent jurisdiction to be
unlawful and violative of public policy.
6. The Indemnitee shall give to the Corporation notice in writing as soon
as practicable of any claim made against him for which indemnity will
or could be sought under this Agreement. The Indemnitee will further
notify and cooperate with the Corporation in the selection of counsel
and in the incurrence of costs and expenses in defending or
investigating any claim for which indemnity may be sought hereunder.
The Indemnitee shall give the Corporation such information and
cooperation as it may reasonably require and as shall be within the
power of the Indemnitee. Notice to the Corporation shall be directed to
the Corporation at its corporate offices, 16825 Northchase Drive, Suite
400, Houston, Texas 77060, Attention: A. Earl Swift.
7. This Agreement is being entered into pursuant to Section 2.02-1.R of
the Texas Business Corporation Act and as such is intended to be
supplemental to any other rights to indemnification available to the
Indemnitee and is not intended to be restricted by the provisions of
other Sections of Article 2.02-1. Nothing herein shall be deemed to
diminish or otherwise restrict the Indemnitee's right to
indemnification under any provision of the Articles of Incorporation or
Bylaws of the Corporation, under Texas law or pursuant to any
self-funded corporate insurance trust fund, if any, or directors and
officers liability insurance maintained by the Corporation.
8. If this Agreement or any portion thereof becomes invalidated on any
ground by any court of competent jurisdiction, then the Corporation
shall nevertheless indemnify the Indemnitee to the fullest extent
permitted by any applicable portion of this Agreement that has not been
invalidated and to the fullest extent permitted by applicable law.
9. This Agreement shall be governed by and construed in accordance with
Texas law. Any legal proceeding pursuant to this Agreement shall take
place in Harris County, Texas.
IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly
executed and delivered as of the day and year first above written.
SWIFT ENERGY COMPANY
By: /s/ Virgil N. Swift
----------------------------------------
Virgil N. Swift
Executive Vice President
INDEMNITEE
By: /s/ A. Earl Swift
----------------------------------------
A. Earl Swift
84
OTHER INDEMNITY AGREEMENTS
INDEMNITEE DATE SIGNED
Leonard A. Aucoin July 8th, 1988
G. Robert Evans August 1st, 1994
Alton D. Heckaman, Jr. July 8th, 1988
James M. Kitterman July 8th, 1988
Raymond O. Loen July 8th, 1988
Henry C. Montgomery July 8th 1988
Adrian D. Shelley January 17th, 1990
Clyde W. Smith Jr. July 8th, 1988
Terry E. Swift July 8th, 1988
Virgil N. Swift July 8th, 1988
Bruce H. Vincent January 17th, 1990
Harold J. Withrow July 8th, 1988
85
Exhibit 12
86
SWIFT ENERGY COMPANY
RATIO OF EARNINGS TO FIXED CHARGES
Twelve Months Ended December 31,
2001 2000 1999
------------------- ----------------- ------------------
GROSS G&A 25,974,568 23,793,995 20,518,843
NET G&A 8,186,654 5,585,487 4,497,400
INTEREST EXPENSE 12,627,022 15,968,405 14,442,815
RENT EXPENSE 1,322,618 1,255,474 1,272,497
NET INCOME BEFORE TAXES 64,669,914 93,079,346 29,736,151
CAPITALIZED INTEREST 6,256,222 5,043,206 4,142,098
DEPLETED CAPITALIZED INTEREST 280,929 307,249 323,124
CALCULATED DATA
--------------------------------------------------------
UNALLOCATED G&A (%) 31.52% 23.47% 21.92%
NON-CAPITAL RENT EXPENSE 416,862 294,714 278,911
1/3 NON-CAPITAL RENT EXPENSE 138,954 98,238 92,970
FIXED CHARGES 19,022,198 21,109,849 18,677,883
EARNINGS 77,716,819 109,453,238 44,595,061
RATIO OF EARNINGS TO FIXED CHARGES 4.09 5.18 2.39
=================== ================= ==================
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 from continuing operations before fixed charges.
Due to the $98.9 million non-cash charge incurred in the fourth quarter of
2001 caused by a write-down in the carrying value of oil and gas
properties, 2001 earnings were insufficient by $40.2 million to cover fixed
charges in this period. If the $98.9 million non-cash charge is excluded,
the ratio of earnings to fixed charges would have been 4.09 for 2001.
87
EXHIBIT 23 (A)
88
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 therein, dated February 14,
2002, 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 20, 2002.
H.J. GRUY AND ASSOCIATES, INC.
by: ______________________________
Marilyn Wilson
President & Chief Operating Officer
March 20, 2001
Houston, Texas
89
EXHIBIT 23 (B)
90
CONSENT OF INDEPENDENT PUBLIC ACCOUNTANTS
As independent public accountants, we hereby consent to the incorporation of our
report dated February 18, 2002, included in the Annual Report of Swift Energy
Company on Form 10-K for the year ended December 31, 2000, into Swift Energy
Company's previously filed Registration Statement File Numbers 33-36310,
33-80240, 33-80288, 33-45354 and 333-67242 on Form S-8 and Number 333-64692 on
Form S-3, as amended
ARTHUR ANDERSEN LLP
Houston, Texas
March 20, 2002
91
EXHIBIT 23 (C)
92
March 20, 2002
Securites and Exchange Commission
Washington, DC 20549
Re: Letter responsive to Temporary Note 3T to Article 3 of Regulation S-X
Dear Sir or Madam:
In compliance with Temporary Note 3T to Article 3 of Regulation S-X, I am
writing to inform you that Arthur Andersen LLP ("Andersen") has represented to
Swift Energy Company that Andersen's audit of the consolidated balance sheets of
Swift Energy and its subsidiaries as of December 31, 2001 and December 31, 2000,
and the related consolidated statements of income, changes in shareholders'
equity and cash flows for each of the three fiscal years in the period ended
December 31, 2001, was subject to Andersen's quality control system for the U.S.
accounting and auditing practice to provide resonable assurance that the
engagement was conducted in compliance with professional standards and that
there was appropriate continuity of Andersen personnel working on the audit,
availability of national office consultation and availability of personnel at
foreign affiliates of Andersen to conduct the relevant portions of the audit.
Sincerely,
/s/ Alton D. Heckaman Jr.
- -------------------------
Sr. Vice-President-Finance
Principal Financial Officer
93
EXHIBIT 99
94
February 14, 2002
Swift Energy Company
16825 Northchase Drive, Suite 400
Houston, Texas 77060
Re: Year-End 2001
Reserves Audit
01-003-173A
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,
2001, 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, 2001.
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 23,759,574 181,651,578 $ 564,807,117 $ 344,478,834
Proved Undeveloped 29,723,062 143,260,547 $ 459,906,537 $ 258,507,354
------------- --------------- --------------------- ---------------------
Total Proved 53,482,636 324,912,125 $ 1,024,713,654 $ 602,986,188
95
Domestic
Proved Reserves
- --------------------------------------------------------------------------------
Estimated Estimated
Net Reserves Future Net Cash Flow
----------------------------------- ---------------------------------------------
Oil, NGL, & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
------------- --------------- --------------------- ---------------------
Proved Developed 20,393,142 167,401,736 $ 509,292,292 $ 306,095,381
Proved Undeveloped 22,171,591 121,087,764 $ 354,699,578 $ 186,012,413
------------- --------------- --------------------- ---------------------
Total Proved 42,564,733 288,489,500 $ 863,991,870 $ 492,107,794
New Zealand
Proved Reserves
- --------------------------------------------------------------------------------
Estimated Estimated
Net Reserves` Future Net Cash Flow
----------------------------------- ---------------------------------------------
Oil, NGL, & Discounted
Condensate Gas at 10%
(Barrels) (Mcf) Nondiscounted Per Year
------------- --------------- --------------------- ---------------------
Proved Developed 3,366,432 14,249,842 $ 55,514,825 $ 38,383,453
Proved Undeveloped 7,551,471 22,172,783 $ 105,206,959 $ 72,494,941
------------- --------------- --------------------- ---------------------
New Zealand Total 10,917,903 36,422,625 $ 160,721,784 $ 110,878,394
The discounted future net cash flows summarized in the above tables are computed
using a discount rate of 10 percent per annum. Proved reserves are estimated in
accordance with the definitions contained in Securities and Exchange Commission
Regulation S-X, Rule 4-10(a). The definitions are included, in part, as
Attachment I. The reserves discussed herein are estimates only and should not be
construed as exact quantities. Future economic or operating conditions may
affect recovery of estimated reserves and cash flows, and reserves of all
categories may be subject to revision as more performance data become available.
Swift represents that the future net cash flows discussed herein were computed
using prices received for oil and natural gas as of December 31, 2001. Domestic
oil and condensate prices are based on a year-end 2001 reference price of $16.75
per barrel. Natural gas price is based on a year-end 2001 reference price of
$2.735 per MMBtu. New Zealand oil and condensate prices are based on a year-end
2001 reference price of $19.05 per barrel. The New Zealand gas price is based on
a year-end 2001 contract price of $1.18 per Mcf. The sales price for natural gas
liquids is based on the oil reference price adjusted by the appropriate
differential. A differential is applied to the oil, condensate, and natural gas
reference prices to adjust for transportation, geographic property location, and
quality or energy content. Product prices, direct operating costs, and future
capital expenditures are not escalated and therefore remain constant for the
projected life of each property. Swift represents that the provided product
sales prices and operating costs are in accordance with Securities and Exchange
Commission guidelines.
96
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 believe necessary to provide a reasonable basis for 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 are often 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 abandoning the
facilities and wells, 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. 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.
In order to audit the reserves and future cash flows estimated by Swift, we have
relied in part on geological, engineering, and economic data furnished by our
client. Although we have made a best efforts attempt to acquire all pertinent
data and to analyze it carefully with methods accepted by the petroleum
industry, there is no guarantee that the volumes of hydrocarbons or the cash
flows projected will be realized. The reserve and cash flow projections
discussed in this report may require revision as additional data become
available.
If investments or business decisions are to be made in reliance on these
judgements by anyone other than our client, such person, with the approval of
our client, is invited to visit our offices at his expense so that he can
evaluate the assumptions made and the completeness and extent of the data
available on which our opinions are based. This report is for general guidance
only, and responsibility for subsequent decisions resides with the decision
maker.
Any distribution or publication of this work or any part thereof must include
this letter in its entirety.
Yours very truly,
H.J. GRUY AND ASSOCIATES, INC.
Texas Registration Number F-000637
by: /s/MarilynWilson
----------------------------------
Marilyn Wilson, PE
President and Chief Operating Officer
Attachment
97
ATTACHMENT I
98
DEFINITIONS OF PROVED OIL AND GAS RESERVES1
PROVED OIL AND GAS RESERVES
Proved oil and gas reserves are the estimated quantities of crude oil, natural
gas, and natural gas liquid which geological and engineering data demonstrate
with reasonable certainty to be recoverable in future years from known
reservoirs under existing economic and operating conditions, i.e., prices and
costs as of the date the estimate is made. Prices include consideration of
changes in existing prices provided only by contractual arrangements, but not on
escalations based upon future conditions.
Reservoirs are considered proved if economic producibility is supported by
either actual production or conclusive formation test. The area of a reservoir
considered proved includes (A) that portion delineated by drilling and defined
by gas-oil and/or oil-water contacts, if any, and (B) the immediately adjoining
portions not yet drilled, but which can be reasonably judged as economically
productive on the basis of available geological and engineering data. In the
absence of information on fluid contacts, the lowest known structural occurrence
of hydrocarbons controls the lower proved limit of the reservoir.
Reserves which can be produced economically through application of improved
recovery techniques (such as fluid injection) are included in the "proved"
classification when successful testing by a pilot project, or the operation of
an installed program in the reservoir, provides support for the engineering
analysis on which the project or program was based.
Estimates of proved reserves do not include the following: (A) oil that may
become available from known reservoirs but is classified separately as
"indicated additional reserves"; (B) crude oil, natural gas, and natural gas
liquids, the recovery of which is subject to reasonable doubt because of
uncertainty as to geology, reservoir characteristics, or economic factors; (C)
crude oil, natural gas, and natural gas liquids, that may occur in undrilled
prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be
recovered from oil shales, coal, gilsonite and other such sources.
PROVED DEVELOPED OIL AND GAS RESERVES
Proved developed oil and gas reserves are reserves that can be expected to be
recovered through existing wells with existing equipment and operating methods.
Additional oil and gas expected to be obtained through the application of fluid
injection or other improved recovery techniques for supplementing the natural
forces and mechanisms of primary recovery should be included as "proved
developed reserves" only after testing by a pilot project or after the operation
of an installed program has confirmed through production response that increased
recovery will be achieved.
PROVED UNDEVELOPED RESERVES
Proved undeveloped oil and gas reserves are reserves that are expected to be
recovered from new wells on undrilled acreage, or from existing wells where a
relatively major expenditure is required for recompletion. Reserves on undrilled
acreage shall be limited to those drilling units offsetting productive units
that are reasonably certain of production when drilled. Proved reserves for
other undrilled units can be claimed only where it can be demonstrated with
certainty that there is continuity of production from the existing productive
formation. Under no circumstances should estimates for proved undeveloped
reserves be attributable to any acreage for which an application of fluid
injection or other improved recovery technique is contemplated, unless such
techniques have been proved effective by actual tests in the area and in the
same reservoir.
- -------------------------------
1 Contained in Securities and Exchange Commission Regulation S-X, Rule 4-10 (a)
99