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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 1998
Commission File number 1-10216:
CHIEFTAIN INTERNATIONAL, INC.
(Exact name of registrant as specified in its charter)
ALBERTA, CANADA NONE
- --------------------------------------------- ------------------------------------
(State or other jurisdiction of incorporation (I.R.S. Employer Identification No.)
or organization)
1201 TD TOWER, 10088 - 102 AVENUE,
EDMONTON, ALBERTA, CANADA T5J 2Z1
- ---------------------------------- -------------
(Address of Registrant's principal (Postal code)
executive offices)
Registrant's telephone number, including area code: (780) 425-1950
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which registered
Common Shares, no par value, of American Stock Exchange
Chieftain International, Inc.
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 (or for such shorter period that the registrant was
required to file such reports), and (2) has been subject to such filing
requirements for the past 90 days. YES [X] NO [ ]
The aggregate market value of the voting stock of Chieftain International, Inc.
held by non-affiliates of said registrant on March 10, 1999 was US$145,356,000.
The number of shares outstanding of the common stock of Chieftain International,
Inc. on March 10, 1999 was 13,355,891.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Chieftain International, Inc. Information Circular dated March
11, 1999 for its annual meeting of shareholders to be held on May 13, 1999, are
incorporated by reference into Part III hereof, to the extent indicated herein.
The Exhibits Index can be found on page 40 of this document.
This report contains forward-looking statements that are subject to risk factors
associated with the oil and gas business. The Company believes that the
expectations reflected in these statements are reasonable, but may be affected
by a variety of factors including, but not limited to: price fluctuations,
currency fluctuations, drilling and production results, imprecision of reserve
estimates, loss of market, industry competition, environmental risks, political
risks and capital restrictions.
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CHIEFTAIN INTERNATIONAL, INC.
1998 FORM 10-K ANNUAL REPORT
Table of Contents
PART I
Page
Item 1. Business ............................................................................... 3
Segment Information .................................................................. 3
Principal Properties ................................................................. 3
Acreage .............................................................................. 7
Gas and Oil Capital Expenditures ..................................................... 8
Drilling Activity .................................................................... 8
Wells ................................................................................ 9
Reserves ............................................................................. 9
Production Volumes, Prices and Costs ................................................. 9
Marketing ............................................................................ 10
Competition .......................................................................... 10
Environmental Regulation ............................................................. 10
Regulation and Political Risk ........................................................ 10
Concentration of Gas Production ...................................................... 10
Development of Additional Reserves ................................................... 11
Exploration and Production Risks ..................................................... 11
Price Uncertainty .................................................................... 11
Employees ............................................................................ 11
Glossary ............................................................................. 12
Item 2. Properties ............................................................................. 14
Item 3. Legal Proceedings ...................................................................... 14
Item 4. Submission of Matters to a Vote of Security Holders .................................... 14
Executive Officers of the Registrant ................................................. 14
PART II
Item 5. Market for the Registrant's Securities and Related Stockholder Matters ................. 15
Item 6. Selected Consolidated Financial Data ................................................... 15
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations .. 17
Item 8. Financial Statements and Supplementary Data ............................................ 19
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ... 39
PART III
Item 10. Directors and Executive Officers ...................................................... 39
Item 11. Executive Compensation ................................................................ 39
Item 12. Security Ownership of Certain Beneficial Owners and Management ........................ 39
Item 13. Certain Relationships and Related Transactions ........................................ 39
PART IV
Item 14. Exhibits and Reports on Form 8-K ...................................................... 39
Signatures ......................................................................................... 41
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PART I
ITEM 1. BUSINESS
Chieftain International, Inc., * incorporated under the Business Corporations
Act (Alberta), commenced operations on April 20, 1989 upon conclusion of its
initial public offering.
Chieftain is engaged in gas and oil exploration and production, primarily in the
United States and also in the UK sector of the North Sea. In addition, Chieftain
is participating in an exploration venture in the Sirte Basin of Libya.
The Company employs an experienced geological and geophysical staff which
generates exploration prospects utilizing advanced technology to process and
interpret 3-D seismic and other data. The Company also participates with various
industry partners who bring additional geoscientific expertise and exploration
prospects to joint venture activity.
In the United States, Chieftain's principal producing properties are located in
the federal waters of the Gulf of Mexico, onshore in Louisiana and in southeast
Utah. Chieftain's exploration acreage is located primarily in the federal waters
of the Gulf of Mexico. Minor interests are held onshore in other areas of the
United States.
In the Gulf of Mexico, Chieftain holds interests in 152 offshore blocks of which
99 are exploratory and 53 are productive.
SEGMENT INFORMATION
Reference is made to page 30 hereof for financial information with respect to
the geographic segments of Chieftain for the years ended December 31, 1998, 1997
and 1996.
PRINCIPAL PROPERTIES
Chieftain's principal gas producing properties are located in US federal waters
in the Gulf of Mexico and in the UK sector of the North Sea. Its principal oil
producing properties are located in the Four Corners area of southeast Utah.
UNITED STATES GULF OF MEXICO AREA - OFFSHORE
Chieftain concentrates its exploration and development activities in, and
devotes substantial managerial and financial resources to, the offshore Gulf of
Mexico area which accounted for most of Chieftain's gas production in 1998.
Activity in this area during 1998 was devoted to both exploration for and
development of reserves. Fourteen exploratory wells were drilled, of which six
were successful, and five development wells were drilled, all of which were
successful.
Additions were made to Chieftain's acreage position in the Gulf of Mexico during
1998. Interests in 11 federal blocks were acquired at competitive lease sales
and interests in two blocks were acquired through joint venture operations.
Holdings in the offshore Gulf of Mexico amounted to 727,113 gross (283,549 net)
acres at year-end compared to 701,764 gross (260,232 net) acres at December 31,
1997. Ongoing acquisition of three-dimensional seismic data supports the
Company's exploration efforts. Continued development activity is contributing to
production growth.
Described below are the principal areas of Chieftain's activity in the Gulf of
Mexico. Production volumes shown are net to Chieftain, before royalties.
* Unless the context otherwise requires, reference to "Chieftain" or the
"Company" or the "Corporation" are to Chieftain International, Inc. and its
subsidiaries. For definitions of certain terms used throughout this report, see
"Glossary".
The Company's accounts are maintained, and all dollar amounts herein are stated,
in United States dollars unless otherwise indicated.
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WESTERN GULF (OFFSHORE TEXAS)
MUSTANG ISLAND:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
7 32,619 15,950 46.8% 9.1 mmcfd
Successful recompletion of a well on Block 784 (Chieftain 50%) increased average
daily production from 4.6 mmcfd in 1997. An unsuccessful exploratory well (100%
Chieftain) was drilled on Block 758 which was allowed to expire. An unsuccessful
exploratory well was drilled on South Addition Block A-51 (Chieftain 25%).
MATAGORDA ISLAND:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
9 47,610 16,735 34.3% 14.1 mmcfd
On Block 634 (Chieftain 24%) three dimensional seismic data was used to identify
a deep prospect beneath the producing reservoir. A 13,000-foot exploratory gas
well encountered five new productive zones. The well was completed during the
second quarter in one zone and was producing 3.0 mmcfd net to Chieftain at
year-end.
HIGH ISLAND:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
33 145,572 66,652 41.5% 7.6 mmcfd and 94 bd
A platform was installed on Block 207 (Chieftain 50%) and production commenced
from a discovery well drilled in 1996. Further drilling is planned for this
block in 1999.
In the High Island South Addition area, Chieftain has interests in eight blocks
(50% in seven; 100% in one) with gas exploration potential. Exploratory drilling
is scheduled to test prospects at depths of 6,000 to 11,000 feet on Blocks
A-510, A-566 and A-530. Access to pipeline facilities is now available in the
area.
CENTRAL GULF (OFFSHORE LOUISIANA)
EAST CAMERON:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
14 61,479 18,160 31.1% 3.9 mmcfd and 507 bd
A discovery well was drilled on Block 34 (Chieftain 40%) early in 1998.
A platform was installed and production commenced in the fourth quarter. Further
drilling is planned in 1999. In the newly-developed Block 349/350 field
(Chieftain 25%) an additional oil and gas development well was drilled, also
early in the year. Production was shut-in for repairs to a third-party pipeline,
interrupting oil production until March. Production was further restricted by
mechanical well problems through the summer. After two wells were successfully
recompleted, production was restored during the fourth quarter. An unsuccessful
exploratory well (Chieftain 33%) was drilled on Block 329.
VERMILION:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
6 20,806 13,447 56.7% 1.6 mmcfd
On Block 23 (Chieftain 25%) production increased with the drilling of a
successful development well. Further development drilling is being considered
for 1999. Exploratory wells are planned for Blocks 16 (Chieftain 40%) and 267
(Chieftain 60%). An unsuccessful exploratory well (Chieftain 15%) was drilled on
Block 368.
SOUTH MARSH ISLAND:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
4 17,852 9,852 60% -
Two successful exploratory oil and gas wells were drilled on Block 39 (Chieftain
50%) during 1998 to followup and further evaluate two 1997 oil and gas
discoveries. Production facilities with initial capacity, net to Chieftain, of
2,500 bd of oil and 20 mmcfd of gas, were under construction at year-end and
production is expected to commence in late March, 1999. Several follow-up wells
are planned for 1999.
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EUGENE ISLAND:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
6 26,250 8,105 36.7% 2.7 mmcfd and 30 bd
On Block 83 (Chieftain 40%) production commenced from a 1997 gas discovery in
early 1998. On Block 189 (Chieftain 75%), where two oil and gas discoveries were
drilled on separate fault blocks in 1997, development work is planned,
contingent upon satisfactory prices. The plan contemplates the drilling of at
least one development well and use of processing facilities on an adjacent
block. An exploratory well drilled in December 1998 on another fault block
encountered non-commercial gas reserves.
SOUTH TIMBALIER:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
5 22,186 9,843 40% -
On Block 196, Chieftain will participate in the drilling of a 12,000-foot
gas-prospective exploratory well to earn a 50% interest.
EASTERN GULF
MISSISSIPPI CANYON:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
4 23,040 5,520 24.1% 0.1 mmcfd
An 8,000-foot well drilled in 2,500 feet of water on Block 29 (Chieftain 33%)
resulted in an oil discovery. Results are being evaluated but further drilling
is unlikely until oil prices recover.
MAIN PASS EAST ADDITION:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
11 46,984 7,864 15.3% 17.5 mmcfd and 260 bd
Field development and evaluation activity continued during 1998 on Blocks
222/223 and 225 where Chieftain has interests of from 7% to 10% in two natural
gas fields which were among the largest industry discoveries on the Shelf in
1995. Additional pipeline capacity for production from the area became available
in the second quarter of 1998. Production commenced from Block 217 (Chieftain
20%) in March and subsequently Chieftain participated with interests ranging
from 8% to 20% in three successful gas development wells on Blocks 223 and 250.
Production facilities are being installed on Block 250 (Chieftain 20%) to
connect an additional discovery and further drilling is planned for this block.
Production is expected to commence in the second quarter of 1999. During 1999,
production facilities are also expected to be installed on the west half of
Block 225 (Chieftain 10%) to connect two gas wells.
MOBILE BAY:
Blocks Gross Acres Net Acres Average Interest Average Production
- ------ ----------- --------- ---------------- ------------------
3 17,138 6,409 37.4% 7.4 mmcfd
An unsuccessful exploratory well was drilled to test a deep Norphlet sandstone
gas prospect on Block 914. The farmee did not earn and Chieftain retains
interests of 25% in Block 914 and 38% in the adjoining Block 913.
VERMILION PARISH, LOUISIANA
NORTHEAST WRIGHT:
Gross Acres Net Acres Average Interest Average Production
- ----------- --------- ---------------- ------------------
3,037 1,518 50.0% 0.2 mmcfd
During 1998, Chieftain acquired an interest in the Northeast Wright Field area,
which included the Simon #2 producing well and the D.W. Guidry #1 exploratory
well. Subsequent to the Chieftain acquisition, the operator reported that the
Guidry well had discovered 150 feet of net natural gas pay and stated: "The well
encountered hydrocarbons in the prolific Marg. Tex formation within a 600-foot
interval below 17,000 feet". The discovery confirms the presence of a large
structure underlying the Northeast Wright Field. The Guidry well was drilled as
a 3,000-foot offset to the Simon #2 well which commenced production in May 1996.
Chieftain's interest in the Guidry well, which commenced production in late
December, is subject to a penalty on a portion of the cost of the well. The
significance of the find to Chieftain will be determined by further drilling. An
offset exploration well is scheduled to commence drilling in the second quarter
of 1999.
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FOUR CORNERS (PARADOX BASIN) AREA, UTAH
Aneth Unit:
Gross Acres Net Acres Average Interest Average Production
- ----------- --------- ---------------- ------------------
18,070 3,066 13.4% 0.25 mmcfd and 646 bd
Ratherford Unit:
Gross Acres Net Acres Average Interest Average Production
- ----------- --------- ---------------- ------------------
12,910 2,560 21.4% 0.5 mmcfd and 1,546 bd
Chieftain has interests in two unitized light oil fields where horizontal
drilling has improved the effectiveness of the waterflood enhanced recovery
program, resulting in increased recoverable reserves and production. During the
year, 30 multi-lateral horizontal development wells were drilled in the Units.
A tertiary carbon dioxide recovery pilot project is underway in the Aneth Unit,
and a field-wide tertiary recovery project is planned for the Ratherford Unit.
Activity at Aneth and Ratherford may be limited by low oil prices during 1999.
NORTH SEA - UNITED KINGDOM SECTOR
Gross Acres Net Acres Average Interest Average Production
- ----------- --------- ---------------- ------------------
60,273 9,644 17.7% 8.5 mmcfd and 25 bd
Chieftain adjusts its gas sales from this area month by month in response to
prices. Accordingly, volumes averaged 15.3 mmcfd in the first quarter and 10.3
mmcfd in the fourth quarter, when prices were relatively high, and were reduced
to 1.8 mmcfd during the third quarter when prices were at a seasonal low. In
addition, production was shut-in for several weeks during July for maintenance
work. Chieftain's production, which is royalty-free, is sold under 30-day
contracts and in 1998 obtained an average price of $1.40 per mcf, net of
transportation costs.
SIRTE BASIN, LIBYA
Gross Acres Net Acres Average Interest Average Production
- ----------- --------- ---------------- ------------------
3,888,550 486,068 12.5% 284 bd
A long-term production test commenced in December 1997 on Block 5 of the Libya
concession NC-171. The first tanker load of this light gravity oil was shipped
to European refineries in July. The objective of the production test is to
determine if well performance supports full-scale commercial development
including development drilling and production facility upgrades. Testing will
continue from two wells into 1999. Reserves have not been booked pending
determination of commerciality. At that time, after recovery of certain costs,
Chieftain's interest in the production will be reduced. A well drilled in early
1999 on Block 5 found oil insufficient to warrant completion. One exploratory
well remains to be drilled under the terms of the concession.
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ACREAGE
The following table summarizes the developed and undeveloped acreage held by
Chieftain as at December 31, 1998. Where applicable, interests which are not
working interests (none of which is material) have been converted to working
interest equivalents.
Developed Acres Undeveloped Acres
Area Gross Net Gross Net
- ---------------------------------- ------ ------ --------- -------
United States
Offshore Gulf of Mexico
Louisiana .................. 21,672 6,620 329,880 111,342
Texas ...................... 12,835 3,664 355,394 160,073
Texas State ................ 300 22 7,032 1,828
------ ------ --------- -------
Total Offshore Gulf of Mexico.. 34,807 10,306 692,306 273,243
====== ====== ========= =======
Onshore
Louisiana .................. 1,936 754 1,674 836
Montana .................... -- -- 3,240 3,240
North Dakota ............... 997 227 1,280 188
Pennsylvania ............... 324 36 -- --
Texas ...................... 320 80 -- --
Utah ....................... 29,860 4,895 1,120 731
------ ------ --------- -------
Total Onshore ................. 33,437 5,992 7,314 4,995
====== ====== ========= =======
Total United States .............. 68,244 16,298 699,620 278,238
====== ====== ========= =======
United Kingdom
North Sea ..................... 7,584 1,348 52,689 8,296
====== ====== ========= =======
Libya
Sirte Basin ................... -- -- 3,888,550 486,068
====== ====== ========= =======
Total, all areas ................. 75,828 17,646 4,640,859 772,602
====== ====== ========= =======
Chieftain's developed and undeveloped acreage in all areas covered 4,716,687
gross (790,248 net) acres at December 31, 1998.
The undeveloped acreage has not been independently evaluated. The cost to
Chieftain thereof is approximately $48 million.
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GAS AND OIL CAPITAL EXPENDITURES
The following table summarizes Chieftain's net capital expenditures for the
years ended December 31, 1998 and 1997.
Year ended December 31, 1998 1997
- --------------------------------- ------- -------
(in thousands)
Property acquisition costs:
United States ................ $ 7,903 $ 9,164
United Kingdom ............... 115 137
------- -------
8,018 9,301
------- -------
Purchase of producing properties:
United States ................ 883 --
------- -------
Exploration costs:
United States ................ 43,317 35,540
United Kingdom ............... 72 115
Other foreign ................ 606 1,207
------- -------
43,995 36,862
------- -------
Development costs:
United States ................ 39,606 23,260
United Kingdom ............... 71 30
------- -------
39,677 23,290
------- -------
$92,573 $69,453
======= =======
DRILLING ACTIVITY
The following table summarizes the results of Chieftain's drilling activities
during the years ended December 31, 1998 and 1997.
Exploratory Wells - Year ended December 31,
- -------------------------------------------
1998 1997
Gross Net Gross Net
----- --- ----- ---
Gas ..................... 6 1.91 7 2.82
Oil ..................... 1 0.33 -- --
Oil/Gas ................. -- -- 1 0.50
Evaluating .............. -- -- -- --
Drilling at end of year.. -- -- 3 0.94
Abandoned ............... 8 3.45 9 2.99
---- ---- -- ----
15 5.69 20 7.25
==== ==== == ====
Development Wells - Year ended December 31,
- -------------------------------------------
1998 1997
Gross Net Gross Net
----- --- ----- ---
Gas ..................... 4 0.32 9 1.77
Oil ..................... 30 6.01 34 6.15
Oil/Gas ................. 1 0.25 -- --
Evaluating .............. -- -- -- --
Drilling at end of year.. -- -- 4 0.81
Abandoned ............... -- -- 1 0.50
---- ---- -- ----
35 6.58 48 9.23
==== ==== == ====
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WELLS
Chieftain's productive gas and oil wells as at December 31, 1998 are listed in
the following table. Any interests which are not working interests (none of
which is material) have been converted to working interest equivalents.
Gas Wells Oil Wells
Gross Net Gross Net
----- --- ----- ---
North Dakota ........ -- -- 2 0.47
Pennsylvania ........ 5 0.93 -- --
Utah ................ -- -- 269 44.69
Louisiana ........... 3 1.13 -- --
US Gulf of Mexico.... 89 17.97 16 4.70
United Kingdom ...... 3 0.41 -- --
--- ----- --- -----
100 20.44 287 49.86
=== ===== === =====
In addition, Chieftain has interests in three (0.37 net) oil wells in Libya two
of which are currently undergoing production testing to evaluate the feasibility
of development.
RESERVES
Chieftain's gas and oil reserves have been evaluated by Netherland, Sewell
& Associates, Inc. ("NS&A") as to the US reserves and by the Company as to the
UK reserves.
For estimates of the Company's proved and proved developed reserves see
"Supplementary Financial Information".
PRODUCTION VOLUMES, PRICES AND COSTS
Chieftain's net production of gas and oil (computed after royalty deductions but
before production taxes) for the years ended December 31, 1998 and 1997 is
listed below. Also listed are average sales prices and average production costs
during such periods.
Year ended December 31, 1998 1997
- ----------------------- ---- ----
Total Net Production:
Gas (mmcf) ............... 24,504 23,431
Oil and liquids (mb) ..... 1,100 825
Gas equivalent (mmcf) .... 31,102 28,383
Average Daily Net Production:
Gas (mmcf) ............... 67.1 64.2
Oil and liquids (b) (*) .. 3,012 2,261
Gas equivalent (mmcf) .... 85.2 77.8
Average Sales Price:
Gas (per mcf) ............ $ 1.99 $ 2.33
Oil and liquids (per b) .. $ 11.74 $ 18.94
Average Production Cost:
Gas (per mcf) ............ $ 0.30 $ 0.27
Oil and liquids (per b) .. $ 5.78 $ 5.81
(*) Oil comprised approximately 82% of the oil and liquids production
over the periods shown.
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MARKETING
Most of Chieftain's gas reserves are located in the Gulf of Mexico area of the
United States, where ready deliverability of gas through numerous large capacity
pipelines and auxiliary feeder pipelines provides flexibility in marketing
Chieftain's gas production in the US spot market. Gas prices in the US and in
the UK North Sea are largely determined by competitive market forces.
Most of the gas produced by Chieftain has been marketed since 1989 by Highland
Energy Company, an aggregator for several US gas producers, at prices based on
spot market prices. Highland Energy Company has also represented Chieftain in
relation to the marketing of Chieftain's UK gas production.
Chieftain's oil production from the Aneth and Ratherford Units in the Four
Corners area of Utah has been sold under successive term contracts to a regional
refiner since 1989. The quantity and quality of this oil has obtained for
Chieftain premiums over locally posted prices. Most of Chieftain's Gulf of
Mexico oil and ngls production is marketed by Highland Energy Company.
Chieftain believes that alternative marketing arrangements would be readily
available for its gas, oil and liquids although no assurance can be given that
any alternative would not be less advantageous to Chieftain.
COMPETITION
There is competition in all aspects of the gas and oil industry, particularly
with respect to the marketing and sale of natural gas and oil production. There
is also competition for desirable exploratory, development and acquisition
prospects and for investment capital. Chieftain's competitors include the major
integrated oil companies as well as numerous independent gas and oil companies,
integrated gas production and transmission companies and other producers and
marketers of energy sources and fuels.
ENVIRONMENTAL REGULATION
Various laws and regulations covering the discharge of materials into the
environment, or otherwise relating to the protection of the environment, may
affect Chieftain's operations and costs. At present, Chieftain believes that its
properties are being operated in compliance with applicable environmental laws
and regulations. Chieftain does not anticipate that it will be required in the
foreseeable future to expend amounts that are unusual, in relation to customary
industry experience, by reason of environmental laws and regulations, but it is
unable to quantify the ultimate cost of compliance.
US offshore oil and gas operations are subject to regulations of the United
States Department of the Interior which currently imposes absolute liability
upon the lessee under a federal lease for the cost of pollution clean-up
resulting from the lessee's operations, and could subject the lessee to possible
liability for pollution damages. In the event of a serious incident of
pollution, a lessee under a federal lease may be required to suspend or cease
operations in the affected area.
In the UK, deposits of substances or articles at sea from offshore oil and gas
operations are subject to the licensing control of the Ministry of Agriculture,
Fisheries and Food. The breach of a license will result in criminal liability
and possible civil liability for the cost of any resulting pollution clean-up.
In the event of a serious incident of pollution, the Ministry may vary or revoke
a license.
REGULATION AND POLITICAL RISK
The gas and oil business is regulated by certain federal, state and local laws
and regulations relating to the development, marketing and transmission of gas
and oil, as well as taxation, environmental and safety matters. International
gas and oil operations, such as Chieftain's operations in the United Kingdom and
Libya, may also be subject to various regulatory, political and economic
factors. Political developments (especially in the Middle East) and the
decisions of OPEC (the Organization of Petroleum Exporting Countries) can
particularly affect world oil supply and oil prices. There is no assurance that
laws and regulations enacted in the future will not adversely affect Chieftain's
exploration for, or its production and marketing of, gas and oil.
CONCENTRATION OF GAS PRODUCTION
Most of Chieftain's gas reserves and production are located offshore in the US
Gulf of Mexico and could be adversely affected by natural disasters or market
conditions affecting this area.
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DEVELOPMENT OF ADDITIONAL RESERVES
Chieftain's future success, as is generally the case in the industry, depends on
its ability to find or acquire additional gas and oil reserves that are
economically recoverable. Except to the extent that Chieftain conducts
successful exploration or development activities or acquires properties
containing proved reserves, Chieftain's proved reserves will generally decline
as reserves are produced. There can be no assurance that Chieftain will be able
to discover additional commercial quantities of gas and oil or continue to
acquire additional proved properties.
EXPLORATION AND PRODUCTION RISKS
Gas and oil exploration involves a high degree of risk, which even a combination
of experience, knowledge and careful evaluation may not be able to overcome.
Chieftain's operations are subject to all of the risks normally incident to the
operation and development of gas and oil properties and the drilling of gas and
oil wells, including blowouts, cratering and fires and encountering unexpected
formations or pressures, which could result in personal injury, loss of life and
damage to property of Chieftain and others. Offshore operations are subject to a
variety of special operating risks, such as hurricanes or other adverse weather
conditions, more extensive governmental regulation, including certain
regulations that may, in certain circumstances, impose absolute liability for
pollution damage, and interruption or termination by government authorities
based upon environmental or other considerations. In accordance with customary
industry practice, Chieftain may not be fully insured against these risks, nor
may all such risks be insurable.
PRICE UNCERTAINTY
There is uncertainty as to the prices at which gas and oil produced by Chieftain
may be sold, and it is possible that under some market conditions the production
of gas and oil from some of Chieftain's properties may not be commercially
feasible. The availability of a ready market for gas and oil as produced and the
price obtained for such gas and oil depend upon numerous factors beyond the
control of Chieftain, including market considerations, the proximity and
capacity of gas and oil pipelines and processing equipment and governmental
regulation. In recent years, markets for gas in the United States have been
characterized by periods of oversupply relative to demand. There have been
significant fluctuations in prices for both gas and oil in recent years and
there can be no assurance that prices for gas or oil would not decrease in the
future.
EMPLOYEES
At December 31, 1998, Chieftain had 40 full-time equivalent employees. In
addition, Chieftain engages the services of consultants as required.
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GLOSSARY
The following are defined terms used herein:
BARREL (b) means 34.972 Imperial gallons or 42 US gallons.
BCF means 1,000,000,000 cubic feet.
BCFE means 1,000,000,000 cubic feet of gas equivalent.
BD means barrels per day.
BLOCK refers to an offshore Gulf Of Mexico gas and oil lease.
DEVELOPED ACREAGE refers to the number of acres assignable to productive wells.
DEVELOPMENT WELLS are wells drilled within the proved area of a gas or oil
reservoir to the depth of a stratigraphic horizon known to be productive.
DRY WELLS means wells found to be incapable of producing either gas or oil in
sufficient quantities to justify completion as gas or oil wells.
EXPLORATORY WELLS are wells drilled to find and produce gas or oil in an
unproved area, to find a new reservoir in a field previously found to be
productive of gas or oil in another reservoir, or to extend a known reservoir.
GAS means natural gas. Natural gas reserves are reported at a base pressure of
14.65 psia and a base temperature of 60 degrees Fahrenheit.
GAS EQUIVALENT is determined by using the approximate energy equivalent ratio of
6 mcf of gas to 1 b of oil and liquids.
GROSS ACRES means the total number of acres in which an interest is owned by
Chieftain.
GROSS WELLS means the total number of wells in which an interest is owned by
Chieftain.
LIQUIDS means natural gas liquids.
MB means 1,000 barrels.
MCF means 1,000 cubic feet.
MCFD means 1,000 cubic feet per day.
MMCF means 1,000,000 cubic feet.
MMCFD means 1,000,000 cubic feet per day.
MMCFE means 1,000,000 cubic feet of gas equivalent.
NET ACRES refers to the sum of the fractional interests owned in gross acres.
NET WELLS refers to the sum of the fractional interests owned in gross wells.
NGLS means natural gas liquids.
OIL OR OIL AND LIQUIDS means crude oil and natural gas liquids.
PRODUCTIVE WELLS are producing wells and wells capable of producing.
PROVED DEVELOPED PRODUCING RESERVES are those reserves which are expected to be
produced from existing completion intervals now open for production in existing
wells.
PROVED DEVELOPED NON-PRODUCING RESERVES are (1) those reserves expected to be
produced from existing completion intervals in existing wells, but due to
pending pipeline connections or other mechanical or contractual requirements
hydrocarbon sales have not yet commenced, and (2) other non-producing reserves
which exist behind the casing of existing wells, or at minor depths below the
present bottom of such wells, which are expected to be produced through these
wells in the predictable future, where the cost of making such oil and gas
available for production should be relatively small compared to the cost of a
new well.
12
13
PROVED RESERVES are the estimated quantities of natural gas, crude oil and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved reserves are limited to
those quantities of gas and oil which can be expected, with little doubt, to be
recoverable commercially at current prices and costs under existing regulatory
practices and with existing conventional equipment and operating methods.
PROVED UNDEVELOPED RESERVES are those reserves which 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 reserves on
undrilled acreage are limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled.
UNDEVELOPED ACREAGE is acreage on which wells have not been drilled or completed
to a point that would permit the production of commercial quantities of gas and
oil regardless of whether or not such acreage contains proved reserves.
WORKING INTEREST refers to the net interest held by Chieftain in an oil or gas
lease or other disposition which interest bears its proportionate share of the
costs of exploration, development and operations and any royalties or other
production burdens.
13
14
ITEM 2. PROPERTIES
Reference is made to Item 1, "Business", for information concerning the
materially important physical properties of Chieftain. In addition, Chieftain
leases office space.
ITEM 3. LEGAL PROCEEDINGS
The Company and its subsidiaries are not party to, and none of its properties is
the subject of, any material legal proceding.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders of the Company during
the fourth quarter of 1998.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table lists the name and age of each Executive Officer and all
positions and offices with the Company held by each such person. The officers
are appointed each year at the directors' meeting immediately following the
annual meeting of the shareholders. The next such meeting will be held on May
13, 1999.
NAME AGE POSITION/OFFICE
- ---- --- ---------------
S.A.Milner 70 Director, President and Chief Executive Officer
S.C.Hurley 49 Director, Senior Vice President and Chief Operating Officer
E.L.Hahn 61 Senior Vice President, Finance and Treasurer
E.S.Ondrack 58 Director, Senior Vice President and Secretary
S.J.Milner 41 Vice President, Drilling and Production
R.J.Stefure 51 Vice President and Controller
With the following exceptions all of the officers have held positions as
officers of the Company since its incorporation in 1988, such position being his
or her principal occupation. S.C. Hurley joined Chieftain in September, 1995
prior to which time he was the Vice President Exploration of a US based
integrated oil company. S.J. Milner and R.J. Stefure were appointed officers of
the Company in June, 1995 and prior thereto held management positions with the
Company.
There are no family relationships among the executive officers and directors
except between S.A. Milner and D.E. Mitchell who are first cousins and between
S.A. Milner and S.J. Milner who are father and son.
14
15
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND RELATED STOCKHOLDER MATTERS
The principal United States market in which the Common Shares of the Company are
traded is the American Stock Exchange. The Common Shares are also traded on The
Toronto Stock Exchange. The high and low prices of the Chieftain International,
Inc. Common Shares (the "Common Shares") during each quarter since December 31,
1996 are shown below.
Price History of Chieftain International, Inc.Common Shares
American Stock Exchange The Toronto Stock Exchange
(US dollars) (Cdn. dollars)
High Low High Low
---- --- ---- ---
1997
First quarter $ 25.88 $ 18.63 $ 35.40 $ 26.00
Second quarter 23.13 18.00 32.00 25.00
Third quarter 27.37 20.50 37.65 28.35
Fourth quarter 28.13 20.13 38.50 29.00
1998
First quarter 24.75 17.94 30.35 25.60
Second quarter 24.75 20.25 35.35 30.10
Third quarter 23.75 13.94 34.45 21.60
Fourth quarter 20.25 14.38 30.70 22.75
1999
January 15.50 11.88 23.00 17.00
February 12.88 9.56 19.50 14.50
March 1 to March 10 10.87 9.87 17.10 15.10
The Common Shares were held by 107 shareholders of record on December 31, 1998.
The Company estimates that investment dealers and other nominees hold Common
Shares for approximately 2,571 beneficial holders.
At the present time it is not the Company's policy to declare regular dividends
on the Common Shares. This policy is under periodic review by the Board of
Directors and is subject to change at any time depending on the earnings of the
Company and its financial requirements. Dividends may be paid on the Common
Shares provided that all dividends on the preferred shares of Chieftain
International Funding Corp. have been paid.
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The selected consolidated financial and operating data for each of the five
years ended December 31, 1998 has been derived from the consolidated financial
statements of the Company included herein and should be read in conjunction with
such consolidated financial statements and the related notes.
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SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
CHIEFTAIN INTERNATIONAL,INC. AND SUBSIDIARIES
Year ended December 31, 1998 1997 1996 1995 1994
- ----------------------- ----------- ----------- ----------- ----------- -----------
(in thousands except shares, per share amounts and operating data)
INCOME STATEMENT DATA:
Revenue ............................................... $ 64,391 $ 72,055 $ 63,099 $ 31,071 $ 34,876
Production costs ...................................... 16,355 13,325 12,220 9,563 8,839
General and administrative expenses ................... 4,796 4,308 3,972 3,346 3,402
Interest .............................................. 437 -- -- -- --
Depletion and amortization(1) ......................... 42,081 36,951 30,920 18,779 21,527
Additional depletion(2) ............................... 6,244 -- -- -- 15,434
Income (loss) from operations, before dividends
on preferred shares of a subsidiary ................ (4,113) 10,160 9,784 (775) (9,528)
Dividends on preferred shares of a subsidiary ......... 4,942 4,942 4,942 4,942 4,942
Net income (loss) applicable to common shares(1) ...... (9,055) 5,218 4,842 (5,717) (14,470)
Net income (loss) per common share(1).................. (0.67) 0.38 0.37 (0.54) (1.32)
Weighted average number of common shares outstanding... 13,480,067 13,620,728 13,065,414 10,633,142 10,986,116
OTHER DATA:
Cash flow from operations ............................. $ 37,847 $ 49,473 $ 41,841 $ 13,186 $ 17,647
Net gas and oil capital expenditures .................. $ 92,573 $ 69,453 $ 57,673 $ 100,502 $ 28,059
BALANCE SHEET DATA (at end of period):
Working capital ....................................... $ 2,383 $ 22,676 $ 42,854 $ 11,216 $ 103,225
Total assets(1) ....................................... $ 318,584 $ 285,125 $ 267,442 $ 204,555 $ 211,032
Long-term debt ........................................ $ 40,000 $ -- $ -- $ -- $ --
Shareholders' equity(1) ............................... $ 234,946 $ 249,466 $ 244,122 $ 190,534 $ 200,754
OPERATING DATA:
Average Daily Net Production:
Gas (mmcf) ......................................... 67.1 64.2 59.8 29.5 28.4
Oil and liquids (b) ................................ 3,012 2,261 2,005 1,643 1,631
Gas equivalent (mmcf) .............................. 85.2 77.8 71.8 39.3 38.2
Average Sales Price:
Gas (per mcf) ...................................... $ 1.99 $ 2.33 $ 2.09 $ 1.54 $ 1.97
Oil and liquids (per b) ............................ 11.74 18.94 20.99 16.94 15.86
Average Production Cost:
Gas (per mcf) ...................................... $ 0.30 $ 0.27 $ 0.25 $ 0.35 $ 0.34
Oil and liquids (per b) ............................ 5.78 5.81 6.57 7.31 6.79
Notes:
(1) Reference is made to Note 11 of the Notes to Consolidated
Financial Statements which describes the impact of United States
accounting principles.
(2) This amount reflects write-downs in the carrying value of UK and
Libyan gas and oil properties in 1998 and US and Peruvian gas
and oil properties in 1994 in accordance with full cost
accounting rules under Canadian GAAP.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
To be read in conjunction with the 1998 audited consolidated financial
statements.
(Comparisons are with 1997 amounts unless otherwise stated)
The Company produces and sells natural gas and oil acquired through exploration
and development or through the purchase of producing properties. Producing
properties are held in the United States in the Gulf of Mexico, Utah and
Louisiana and also in the British sector of the North Sea and in Libya.
Chieftain continues to explore in these areas.
The Company dedicates the majority of its attention and resources to the US Gulf
of Mexico area where it holds interests in 152 offshore lease blocks. Highly
skilled technical staff and leading-edge technology are employed in the
Company's Dallas and New Orleans exploration offices to identify and delineate
gas and oil prospects.
The Company's reporting currency is the US dollar.
ANALYSIS OF OPERATING RESULTS
Average daily production in 1998 increased to 103 mmcfe from 93 mmcfe and 86
mmcfe in 1997 and 1996, respectively. Natural gas production increased to 30 bcf
in 1998 from 28 bcf in 1997 and 26 bcf in 1996. Oil production increased to
1,271,000 b in 1998 from 962,000 b in 1997 and 857,000 b in 1996. In 1998,
positive growth in production volumes was more than offset by decreases in
natural gas and oil prices with the result that production revenues decreased
11% to $74.8 million. This compares to an increase in 1997 production revenues
of 16% to $84.2 million, which resulted from positive growth in production
volumes and a significant increase in average natural gas prices during 1997.
Natural gas prices in 1998 averaged $1.99 per mcf compared to $2.33 in 1997 and
$2.09 in 1996. Oil prices in 1998 averaged $11.74 per b compared to $18.94 in
1997 and $20.99 in 1996.
Higher rates of production are anticipated during 1999 as newly developed
fields, particularly South Marsh Island 39, are brought on stream; a full year's
production is yielded by fields and wells that first contributed during 1998,
such as East Cameron 34, Eugene Island 83, Main Pass 217, High Island 207 B-1
and Northeast Wright; and a full year's production is contributed by areas that
were subject to pipeline constraints during 1998, such as East Cameron 349, Main
Pass 222/223, and South Pass 37.
A $0.10 per mcf change in the average natural gas price received would have
resulted in a change in revenue, cash flow and pre-tax income of $2.5 million
(1997 - $2.3 million; 1996 - $2.3 million). A $1.00 per barrel change in the
average oil price would have resulted in a change in revenue of $1.1 million and
a change in cash flow and pre-tax income of a slightly lesser amount (1997 -
$0.8 million; 1996 - $0.7 million).
In Libya, a long-term production test which commenced in December 1997 will
require a longer test period to produce a reservoir model which will assess
reserve quantities and economics of additional drilling. An impairment provision
of $5.1 million was recorded in respect of one of the Libyan concessions upon
which no further exploration has currently been planned. Two additional wells
will be drilled in 1999 to fulfil the Company's commitment in this area.
PRODUCTION AND PRICING
During 1998, Chieftain's production averaged 103.2 mmcfe per day, an increase of
11% from 1997. The daily production rate at the end of 1998 was 120.0 mmcfe, an
increase of 25% over the 1997 year-end production rate. The year's production
mix, on an energy equivalent basis, was 80% natural gas and 20% oil and ngls. On
a geographic basis, 90% of energy equivalent production came from United States
properties which are expected to account for 93% of 1999 production.
Ninety per cent of 1998 natural gas production came from Chieftain's interests
in 105 wells in the Gulf of Mexico. Gas production was up by 6%, with increases
from the Main Pass, Mustang Island, Eugene Island, East Cameron, High Island and
Vermilion areas. Recently developed facilities at High Island 207, several Main
Pass blocks, Matagorda 634 and South Marsh Island 39, and production from the
onshore Northeast Wright Field in Louisiana, are expected to increase gas
production in 1999. In the North Sea, three wells, one of which has two
laterals, produce natural gas and ngls.
Production of oil and ngls increased by 32% with the largest increases
contributed by holdings in the East Cameron and Main Pass areas in the Gulf of
Mexico, and the Aneth and Ratherford Units in southeast Utah. During 1998, 63%
of the Company's oil production was from interests in 269 wells in the Aneth and
Ratherford Units and 28% was from the Gulf of Mexico. Oil production growth
during 1999 is expected from South Marsh Island 39, East Cameron 349 and the
Utah Units.
17
18
At year-end, Chieftain was producing, before royalties, 95.5 mmcfd of gas,
comprising 85.2 mmcfd in the US and 10.3 mmcfd in the North Sea. Year-end oil
production, before royalties, was 4,030 bd, 2,170 bd from the Aneth and
Ratherford Units in Utah and 1,550 bd from the Gulf of Mexico. An additional 220
bd was contributed by interests in two wells in Libya's Sirte Basin where a
long-term production test is continuing.
The combination of serious economic problems in Asia, the warmest North American
winter in the last century and aggressive international competition for market
share caused crude oil prices to fall sharply during 1998, bringing the average
price received by Chieftain for oil and ngls down by 38% to $11.74.
The extremely mild North American winter of 1997-98 had a significant downward
effect on natural gas prices in the Gulf of Mexico. Prices during the fourth
quarter were down by 33% from the comparative quarter of 1997. The average price
received for all of Chieftain's 1998 US gas production declined by 17% to an
average of $2.06 per mcf. Gas production contributed 78% of revenue.
Chieftain sells most of its gas under short term contractual arrangements and
does not engage in speculative forward selling of volumes that cannot be
physically delivered.
Interest and other revenue in 1998 includes a non-recurring court award of $1.6
million pursuant to a successful claim for recovery of excess transportation
charges incurred from 1990 through 1997.
In 1998, production expenses increased 23%, primarily reflecting a succession of
weather induced evacuations of manned facilities in the Gulf of Mexico during
the third quarter, the commencement of production at East Cameron 349 and
significant pipeline repair costs in the South Pass area. Production expenses
increased to $0.43 per gas equivalent unit, up 11% from the 1997 and 1996 rate
of $0.39 per gas equivalent unit. Higher lifting costs are associated with oil
production which comprised 20% of the Company's gas equivalent production in
1998 as compared to 17% in 1997 and 16% in 1996.
For 1998, the 11% increase in general and administrative expense reflects
increased performance based compensation payments made during the first quarter.
General and administrative expenses were $0.13 per gas equivalent unit in 1998,
1997 and 1996.
Depletion and amortization expense increased 14% compared to 1997, the result of
an 11% increase in units of production and a 4% increase in average depletion
rate to $1.12 per gas equivalent unit.
Capital Resources and Liquidity
The table on this page summarizes cash provided from or (used in) operating,
financing and investing activities for each of the past three years.
Cash generated from operating activities decreased 30%, primarily as a result of
lower revenues in 1998.
Financing activities in 1998 provided $ 34.5 million of cash, the net result of:
the drawdown of $ 40 million of the Company's revolving credit facility, the
purchase for cancellation of 294,700 common shares at the cost of $5.9 million
under a normal course issuer bid and the exercise of employee stock options for
$0.4 million. In 1997, financing activities provided $0.1 million of cash, the
net result of the exercise of employee stock options for $1.0 million and the
purchase for cancellation of 36,300 common shares at the cost of $0.9 million.
Source and Use of Cash (US$ in thousands)
Year ended December 31, 1998 1997 1996
-------- -------- --------
Cash provided from (used in):
Operating activities $ 35,167 $ 50,489 $ 36,967
Financing activities 34,535 126 47,657
Investing activities (86,014) (66,139) (52,750)
-------- -------- --------
Increase (decrease) in cash $(16,312) $(15,524) $ 31,874
======== ======== ========
Cash used in investing activities increased 30% to $86.0 million in 1998. The
Company participated in 50 wells in 1998, compared to 68 wells in 1997. All 1998
and 1997 drilling was in the US.
The December 31, 1998 cash balance of $10.6 million was down $16.3 million from
a year earlier. $40 million of the Company's $100 million revolving credit
facility was utilized at December 31, 1998. The weighted average interest rate
at December 31, 1998 was 5.65%.
OUTLOOK
The Company's 1999 production target range is 115 to 125 mmcfe per day as
compared to average production of 103 mmcfe per day in 1998. Low oil and gas
prices, if prolonged, may more than offset any increase in cash flow
contribution from increased production volumes.
18
19
The abnormally temperate 1998-1999 heating season associated with El Nino has
resulted in robust US gas storage levels in the primary markets for the
Company's US gas production. It is difficult to predict the extent to which
industry declines in production will be offset by new production in the near
term. The Company expects that the resulting uncertainty about US gas supply,
coupled with abnormally low US consumption, will result in continued US gas
price volatility.
In the North Sea, the direction of flow in the Interconnector pipeline has been
reversed as a consequence of spot prices on the continent falling below United
Kingdom prices, a result of surplus natural gas from the former Soviet Union
reaching the continental market. The Company expects continued low prices for
North Sea production in the near term.
The Board of Directors authorized a $75 million capital expenditure program for
1999. Such capital expenditures can be varied significantly with respect to
timing and priority dependent upon exploration success, availability of
equipment and services and current opportunities. The Company continuously
monitors capital spending with a view to oil and gas prices so as to adjust
investment levels in relation to cash flow projections.
Many of the Company's competitors and partners are reviewing and reducing their
capital expenditure programs in view of the low oil and gas prices expected in
the near term. The uncertainty underlying these spending reductions is expected
to result in delays in the timing of projects, cancellation of projects, reduced
costs of projects and the possibility of purchasing reserves at values
reflecting low current prices.
YEAR 2000 DISCLOSURE
The Company has completed the assessment of its internal Year 2000 issues, has
made changes and employed testing procedures as deemed necessary and at this
time is confident that no issues relating to its internal systems remain which
could have a material effect on its financial condition or results of
operations. The Company's assessment of the readiness of third parties is in
process and should be completed by the end of the second quarter of 1999. Costs
incurred to date and expected to be incurred in the future are not material to
the Company.
The Company has interests in a substantial number of offshore oil and gas
production facilities which are operated by others and is required to rely on
assessments by such third parties as to Year 2000 readiness of such facilities.
Production volumes are transported through pipelines and processed through
facilities which are also operated by third parties. There is extensive use of
computers to control and operate such pipelines and facilities in the oil and
gas industry and it is reasonably likely that one or more of such facilities
will experience a computer related event which could result in shut down of
production, transportation or processing facilities for such time as is required
to effect alternative controls. The Company can not reasonably quantify the
estimated lost revenue, if any, which would result from such an interruption. To
mitigate the effect of any interruptions, the Company intends to continue its
review of contingency plans prepared by its various operating partners.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following consolidated financial statements of Chieftain International, Inc.
and the management's and auditors' reports thereon are included herein. The
financial statements are in US dollars.
Management's Report
Auditors' Report
Consolidated Balance Sheet as at December 31, 1998 and 1997
Consolidated Statement of Income and Deficit for the years ended
December 31, 1998, 1997 and 1996
Consolidated Statement of Changes in Financial Position for the years
ended December 31, 1998, 1997 and 1996
Notes to Consolidated Financial Statements
Supplementary Financial Information (Unaudited)
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MANAGEMENT'S REPORT
The accompanying consolidated financial statements and all information in this
annual report are the responsibility of management. The financial statements
have been prepared by management in accordance with Canadian generally accepted
accounting principles. The financial information contained elsewhere in this
annual report is consistent with the consolidated financial statements in all
material respects.
The Company maintains accounting systems and internal controls to
provide reasonable assurance that its financial information is reliable and
accurate, and that its assets are adequately safeguarded. Where necessary,
management has made informed judgments and estimates in the preparation of the
financial statements.
Independent auditors, appointed by the shareholders, have examined the
consolidated financial statements. The Audit Committee of the Board of Directors
meets periodically with management and the independent auditors to review audit,
internal control, accounting policy and financial reporting matters.
The annual consolidated financial statements are approved by the Board
of Directors on the recommendation of the Audit Committee.
/s/ S.A. Milner
- ---------------------------------------
S.A. Milner
President and Chief Executive Officer
/s/ E.L. Hahn
- ---------------------------------------
E.L. Hahn
Senior Vice President,
Finance and Treasurer
February 4, 1999
AUDITOR'S REPORT
We have audited the consolidated balance sheets of Chieftain International, Inc.
as at December 31, 1998 and 1997 and the consolidated statements of income
(loss) and deficit and changes in financial position for each of the years in
the three-year period ended December 31, 1998. 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 generally accepted auditing
standards. Those standards require that we plan and perform an audit to obtain
reasonable assurance 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.
In our opinion, these consolidated financial statements present fairly,
in all material respects, the financial position of the Company as at December
31, 1998 and 1997 and the results of its operations and the changes in its
financial position for each of the years in the three-year period ended December
31, 1998 in accordance with generally accepted accounting principles in Canada.
/s/ PricewaterhouseCoopers LLP
- ---------------------------------------
Chartered Accountants
Edmonton, Alberta
February 4, 1999
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CONSOLIDATED BALANCE SHEET
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
(Full Cost Method of Accounting) as at December 31, 1998 1997
--------- ---------
(US$ in thousands)
Assets
Current assets:
Cash and short-term deposits $ 10,613 $ 26,925
Accounts receivable 14,030 10,862
Other 282 606
--------- ---------
24,925 38,393
--------- ---------
Capital assets, at cost:
Natural resource properties including exploration and
development thereon (Note 1(e)) 552,380 459,807
Other capital assets 2,119 2,047
--------- ---------
554,499 461,854
Less: Accumulated depletion and amortization 266,022 218,564
--------- ---------
288,477 243,290
--------- ---------
Deferred income taxes 5,182 3,442
--------- ---------
$ 318,584 $ 285,125
========= =========
Liabilities and Shareholders' Equity
Current liabilities:
Accounts payable and accrued $ 22,533 $ 15,717
Long-term debt (Note 2) 40,000 --
Abandonment cost accrual 7,421 6,575
Deferred income taxes 13,684 13,367
Shareholders' equity:
Preferred shares of a subsidiary (Note 3) 63,403 63,403
Share capital (Note 4) -
Authorized - an unlimited number of -
First preferred shares
Second preferred shares
Common shares
Issued -
13,355,891 common shares (1997 - 13,622,375) 189,108 192,845
Contributed surplus -- 307
Deficit (17,565) (7,089)
--------- ---------
234,946 249,466
--------- ---------
$ 318,584 $ 285,125
========= =========
Approved by the Board:
/s/ S.A. Milner /s/ L.G. Munin
- --------------------- --------------------
S.A. Milner, Director L.G. Munin, Director
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CONSOLIDATED STATEMENT OF INCOME (LOSS) AND DEFICIT
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
Year ended December 31, 1998 1997 1996
------------ ------------ ------------
(US$ in thousands except shares and per share amounts)
Production revenue $ 74,861 $ 84,219 $ 72,838
Less: Royalties 13,246 14,592 12,226
------------ ------------ ------------
Production revenue, net of royalties 61,615 69,627 60,612
Interest and other revenue (Note 5) 2,776 2,428 2,487
------------ ------------ ------------
64,391 72,055 63,099
------------ ------------ ------------
Production costs 16,355 13,325 12,220
General and administrative expenses 4,796 4,308 3,972
Interest 437 -- --
Depletion and amortization 42,081 36,951 30,920
Additional depletion: Libyan properties 5,144 -- --
UK properties 1,100 -- --
------------ ------------ ------------
69,913 54,584 47,112
------------ ------------ ------------
Income (loss) before income taxes and dividends on
preferred shares of a subsidiary (5,522) 17,471 15,987
Income taxes (Note 6):
Current 14 7 124
Deferred (1,423) 7,304 6,079
------------ ------------ ------------
(1,409) 7,311 6,203
------------ ------------ ------------
Income (loss) before dividends on preferred shares
of a subsidiary (4,113) 10,160 9,784
Dividends paid on preferred shares of a subsidiary 4,942 4,942 4,942
------------ ------------ ------------
Net income (loss) applicable to common shares (9,055) 5,218 4,842
Deficit, beginning of year (7,089) (12,307) (17,149)
Cost of purchase of common shares in excess
of stated capital (Note 4) (1,421) -- --
------------ ------------ ------------
Deficit, end of year $ (17,565) $ (7,089) $ (12,307)
============ ============ ============
Net income (loss) per common share (Note 7) $ (0.67) $ 0.38 $ 0.37
============ ============ ============
Weighted average number of common shares outstanding 13,480,067 13,620,728 13,065,414
============ ============ ============
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CONSOLIDATED STATEMENT OF CHANGES IN FINANCIAL POSITION
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
Year ended December 31, 1998 1997 1996
- ----------------------- -------- -------- --------
(US$ in thousands)
Operating activities:
Net income (loss) applicable to common shares $ (9,055) $ 5,218 $ 4,842
Items not requiring a current cash outlay:
Depletion and amortization 48,325 36,951 30,920
Deferred income taxes (1,423) 7,304 6,079
-------- -------- --------
Cash flow from operations 37,847 49,473 41,841
Change in non-cash operating working capital
Accounts receivable (3,168) 337 (2,936)
Other current assets 324 (313) 199
Accounts payable and accrued 164 992 (901)
Dividend payable -- -- (1,236)
-------- -------- --------
35,167 50,489 36,967
-------- -------- --------
Financing activities:
Issue of common shares 437 975 50,097
Purchase of common shares for cancellation (5,902) (849) --
Increase in long-term debt 40,000 -- --
Financing costs -- -- (2,440)
-------- -------- --------
34,535 126 47,657
-------- -------- --------
Investing activities:
Lease acquisition, exploration and development costs (91,690) (69,453) (56,636)
Purchase of producing gas and oil properties (883) -- (2,077)
Sale of producing properties -- -- 1,040
-------- -------- --------
(92,573) (69,453) (57,673)
Purchase of other capital assets (93) (324) (187)
Change in investing accounts payable and accrued 6,652 3,638 5,110
-------- -------- --------
(86,014) (66,139) (52,750)
-------- -------- --------
Change in cash and short-term deposits (16,312) (15,524) 31,874
Cash and short-term deposits, beginning of year 26,925 42,449 10,575
-------- -------- --------
Cash and short-term deposits, end of year $ 10,613 $ 26,925 $ 42,449
======== ======== ========
23
24
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (December 31, 1998, 1997 and 1996)
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
The Company is engaged in gas and oil exploration, development and production
primarily in the United States and also in the UK sector of the North Sea and in
Libya. The Consolidated Financial Statements are expressed in United States
currency as most of the Company's assets and operations are denominated in US
dollars.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) ACCOUNTING PRINCIPLES
The Company's financial statements are prepared in conformity with
Canadian generally accepted accounting principles. The preparation of
financial statements in conformity with generally accepted accounting
principles requires management to make informed judgements and
estimates. Actual results may differ from those estimates. Material
differences between Canadian and US accounting principles that affect
the Company are referred to in Note 11, which provides the effects of
the differences on earnings and balance sheet accounts.
(b) PRINCIPLES OF CONSOLIDATION
The Consolidated Financial Statements include the accounts of the
Company and its subsidiary companies, all of which are wholly-owned
except for Chieftain International Funding Corp., a US subsidiary which
in 1992 issued 2,726,700 preferred shares to the public. These preferred
shares are convertible into common shares of Chieftain International,
Inc. See Note 3.
Acquisitions of subsidiaries and businesses have been accounted
for by the purchase method and accordingly only income or losses since
date of acquisition are included in the Consolidated Statement of
Income.
(c) FOREIGN CURRENCY TRANSLATION
Canadian and other foreign currency amounts have been translated into US
currency on the following bases: monetary assets and liabilities at the
year-end rates of exchange; non-monetary assets and liabilities at
historical exchange rates; and revenue and expenses at monthly average
exchange rates during the year. Translation gains or losses are
reflected in the Consolidated Statement of Income.
(d) FINANCIAL ASSETS AND LIABILITIES
The Company's financial instruments that are included in the
Consolidated Balance Sheet are comprised of cash and short-term
deposits, accounts receivable, all current liabilities and long-term
debt, the fair values of which approximate their carrying amounts due to
their short-term or current rate nature. Cash and short-term deposits
include minimum risk certificates guaranteed by a major Canadian bank
and are purchased three months or less from maturity. Accounts
receivable are subject to normal oil and gas industry credit risks.
Long-term debt is subject to normal floating interest rate risk.
(e) NATURAL RESOURCE PROPERTIES
The Company accounts for gas and oil properties in accordance with
Canadian guidelines on full cost accounting.
Under this method, all costs associated with the acquisition,
exploration and development of gas and oil properties are capitalized in
cost centers on a country-by-country basis. Depletion is calculated
using the unit-of-production method based on gross proved reserves
before royalties and combining oil and natural gas on an energy
equivalent basis. Future well abandonment and site restoration costs are
included in the calculation of depletion expense and are based on
current engineering estimates in
24
25
accordance with current regulations and industry practices. Actual
costs, when incurred are charged against the abandonment cost accrual.
A ceiling test is applied to ensure that capitalized costs do
not exceed estimated future net revenues less certain applicable costs.
There is uncertainty as to the prices at which gas and oil produced by
the Company may be sold. The application of such ceiling test to US
property carrying costs at December 31, 1998, using the $12.27 average
oil and natural gas liquids ("ngls") price received by the Company
during the year and the $2.15 December 31, 1998 natural gas price,
required no write-down. A write-down of $10,614,000, after providing for
tax recoveries of $5,842,000, would have been required had December 31,
1998 prices, $2.15 for natural gas and $9.72 for oil and ngls, been
used. An impairment provision of $2,849,000, after providing for tax
recoveries of $2,295,000, was recorded in respect of one of the Libyan
concessions; and a write-down of $609,000, after providing for tax
recoveries of $491,000, was recorded in respect of the UK properties.
The following weighted average field prices were used in the
determination of the Company's US future net revenues for purposes of
the ceiling test:
As at December 31, 1998 1997 1996
------------------ --------- --------- ---------
Oil - per barrel $ 12.35 $ 16.92 $ 24.29
========= ========= =========
Ngls - per barrel $ 10.19 $ 15.14 $ 21.66
========= ========= =========
Oil & ngls - per barrel $ 12.27 $ 16.69 $ 24.03
========= ========= =========
Natural gas - per thousand cubic feet ("mcf") $ 2.15 $ 2.74 $ 3.43
========= ========= =========
A field price of $1.74 (1997 - $1.76; 1996 - $2.04) per thousand
cubic feet was used in the determination of the Company's UK future net
revenues for purposes of the ceiling test.
Depletion rates per physical unit of US production are as
follows:
Natural Gas Crude Oil & Ngls
(per mcf) (per barrel)
----------- ----------------
Year ended December 31, 1996 $ 1.03 $ 6.16
======== ========
Year ended December 31, 1997 $ 1.11 $ 6.68
======== ========
YEAR ENDED DECEMBER 31, 1998 $ 1.16 $ 6.97
======== ========
The depletion rate per physical unit of UK natural gas
production was $0.81 per mcf for the year ended December 31, 1998
(1997-$0.81; 1996-$0.56).
General and administrative costs relating directly to lease
acquisition, exploration and development activities have been
capitalized as follows:
Year ended December 31, 1998 1997 1996
----------------------- ------ ------ ------
(in thousands)
Lease acquisition $ 857 $ 694 $ 837
Exploration 1,740 1,470 1,547
Development 1,715 1,387 1,254
------ ------ ------
$4,312 $3,551 $3,638
====== ====== ======
At December 31, 1998, Libyan property carrying costs of $9.9
million (1997 - $14.6 million) were excluded from depletion calculations
pending evaluation.
25
26
(f) LAND, BUILDINGS AND OTHER EQUIPMENT
Amortization is provided as follows:
Rate per
annum Method
----- ------
Buildings 5% Straight-line
Furniture, office equipment and leasehold improvements 10 - 20% Straight-line
Expenditures for renewals and betterments which materially
increase the estimated useful life of buildings and equipment are
capitalized; expenditures for repairs and maintenance are charged to
income. Costs and accumulated amortization of assets retired or sold are
removed from the asset and related accumulated amortization accounts;
losses and gains thereon are included in the Consolidated Statement of
Income as depletion and amortization.
(g) INCOME TAXES
The Company follows the tax allocation method of accounting for the tax
effect of all timing differences between taxable income and accounting
income. Thus, provision is made currently for taxes deferred as a result
of claiming for tax purposes deductions in excess of amounts charged to
income in the books, principally natural resource lease acquisition
costs, intangible exploration, development and drilling costs and costs
of tangible capital assets.
(h) COMPARATIVE FIGURES
Certain 1997 information has been reclassified to conform to the 1998
presentation.
2. REVOLVING CREDIT AND TERM LOAN AGREEMENTS
In 1997 the Company arranged an unsecured revolving credit facility with a
syndicate of banks. The facility, in the amount of $100 million or the
Canadian dollar equivalent, is fully revolving for 364 day periods with
extensions at the option of the lenders upon notice from the Company. If not
extended, the facility converts to term loans repayable over a period not
exceeding four years. Advances under the facility bear interest at Canadian
prime or US base rate, or at Bankers' Acceptance rates or LIBOR plus
applicable margins. Certain financial tests are required to be met quarterly.
Under this facility, $40 million was utilized at December 31, 1998, carrying
a weighted average interest rate of 5.65%.
3. PREFERRED SHARES OF A SUBSIDIARY
Chieftain International Funding Corp. ("Funding"), a subsidiary of Chieftain
International (U.S.) Inc., sold 2,726,700 shares of $1.8125 cumulative
convertible redeemable preferred shares at $25.00 per share in a 1992 public
offering in the United States. The preferred shares are redeemable, at the
option of Funding, at $25.6042 per share during 1999, declining to $25.00 per
share after December 31, 2001, plus accumulated and unpaid dividends. Each
preferred share has a liquidation preference of $25.00 and is convertible at
any time into 1.25 Common Shares of Chieftain International, Inc. at the
option of the holder.
26
27
4. Share Capital
(a) COMMON SHARES
Year ended December 31, 1998 1997 1996
----------------------- -------------------------- -------------------------- -------------------------
NUMBER SHARE Number Share Number Share
OF CAPITAL of Capital of Capital
SHARES ACCOUNT shares Account shares Account
---------- ----------- ---------- ----------- ---------- -----------
(dollars in thousands)
Balance, beginning of year 13,622,375 $ 192,845 13,591,763 $ 192,381 10,546,100 $ 143,635
Share options exercised 28,216 437 66,912 975 75,663 1,092
Shares purchased and
cancelled(*) (294,700) (4,174) (36,300) (511) -- --
Shares issued for cash(**) -- -- -- -- 2,970,000 47,654
---------- ----------- ---------- ----------- ---------- -----------
Balance, end of year 13,355,891 $ 189,108 13,622,375 $ 192,845 13,591,763 $ 192,381
========== =========== ========== =========== ========== ===========
* Pursuant to normal course issuer bid.
** Reduced by costs of issue of $2,440, less related deferred taxes of
$1,089.
In the first quarter of 1996, the Company sold 2,970,000 common shares,
by way of a public offering in the United States and Canada, at $16.50
per share (C$22.75).
(b) COMMON SHARES RESERVED
At December 31, 1998, 1,130,875 (1997 - 1,159,091; 1996 - 1,226,003) of
the authorized but unissued common shares of the Company were reserved
for issuance under the Share Option Plan. See Note 4(d).
The Company has reserved 3,408,375 common shares for issuance
pursuant to the conversion provisions of the preferred shares of a
subsidiary. See Note 3.
(c) CONTRIBUTED SURPLUS
Contributed surplus represented the excess of original net issue price
over purchase price of shares purchased and cancelled pursuant to issuer
bids in 1995, 1997 and 1998.
(d) SHARE OPTION PLAN (THE "PLAN")
The Plan provides for the granting of options to employees, directors
and consultants to purchase common shares of the Company. Each option
expires not later than ten years from the date it was granted. Options
are exercisable as to one-third of the granted amount on or after each
of the first three anniversaries of the date of grant or over such
longer period as may be determined by the directors. The option price
for shares in respect of which an option is granted under the Plan is
not less than the market price on the date of grant. At December 31,
1998 options were outstanding to 47 participants in the Plan.
27
28
The following is a summary of activity related to the Plan for the years
ended December 31, 1998, 1997 and 1996.
Year ended December 31, 1998 1997 1996
- ----------------------- -------------------- -------------------- --------------------
WEIGHTED Weighted Weighted
NUMBER AVERAGE Number Average Number Average
OF OPTION of Option of Option
SHARES PRICE Shares Price Shares Price
--------- -------- ------ -------- ------ -----
Outstanding at beginning of year 1,057,673 $16.47 909,253 $15.10 980,250 $14.90
Granted 65,000 21.08 228,000 21.35 15,000 23.75
Exercised (28,216) 15.49 (66,912) 14.47 (75,663) 14.22
Forfeited (10,600) 20.07 (12,668) 16.06 (10,334) 15.39
--------- --------- -------
Outstanding at end of year 1,083,857 16.74 1,057,673 16.47 909,253 15.10
========= ========= =======
Options exercisable at year end 869,858 707,738 558,319
========= ========= =======
The following table summarizes information about options outstanding at
December 31, 1998.
Options Outstanding Options Exercisable
-------------------------------------- -------------------
Range Weighted Weighted Weighted
of Number Average Average Number Average
Option of Remaining Option of Option
Prices Shares Contractual Life Price Shares Price
------ ------ ---------------- ----- ------ -----
$13.50 to 15.63 694,523 4.9 years $ 14.37 694,523 $ 14.37
18.00 to 20.87 118,334 4.6 years 19.16 93,334 19.47
21.23 to 23.75 271,000 8.5 years 21.75 82,001 21.67
--------- -------
1,083,857 869,858
========= =======
5. INTEREST AND OTHER INCOME
Interest and other revenue for the first quarter of 1998 included $1.6
million awarded by the courts pursuant to a successful claim for
recovery of excess transportation charges incurred from 1990 through
1997. The award comprises transportation charges, legal fees and
judgement interest in the amounts of $1,129,000, $282,000 and $189,000,
respectively.
6. INCOME TAXES
Income tax expense is made up of the following components:
Year ended December 31, 1998 1997 1996
- ----------------------- ------------------- ------------------ ------------------
CANADA US Canada US Canada US
------- ------- ------- ------- ------- -------
(in thousands)
Income (loss) before income taxes and
dividends on preferred shares of a
subsidiary $(6,829) $ 1,307 $ 2,072 $15,399 $ 1,461 $14,526
======= ======= ======= ======= ======= =======
Income taxes (recovery)
Current 14 -- 7 -- 124 --
Deferred (1,740) 317 2,007 5,297 912 5,167
------- ------- ------- ------- ------- -------
$(1,726) $ 317 $ 2,014 $ 5,297 $ 1,036 $ 5,167
======= ======= ======= ======= ======= =======
28
29
Deferred income tax expense results from timing differences
between the recognition of expenses for tax and financial statement
purposes as explained in Note 1(g). The sources of these differences are
as follows:
Year ended December 31, 1998 1997 1996
- ----------------------- ------------------- ------------------- -------------------
CANADA US Canada US Canada US
------- ------- ------- ------- ------- -------
(in thousands)
Amortization of buildings and equipment $ (27) $ 18 $ (112) $ (275) $ 3 $ 340
Depletion of natural resource properties (2,073) 6,104 (68) 6,011 805 5,898
Financing costs 243 -- 338 -- 348 --
Tax loss carry forward 154 (5,839) 1,846 (430) (230) (1,143)
Other (37) 34 3 (9) (14) 72
------- ------- ------- ------- ------- -------
$(1,740) $ 317 $ 2,007 $ 5,297 $ 912 $ 5,167
======= ======= ======= ======= ======= =======
The actual tax rate differs from the expected tax rate for the
following reasons:
Year ended December 31, 1998 1997 1996
- ----------------------- ------- ------- -------
(in thousands)
Tax at statutory rate of 44.62%
(Combined Canadian federal and provincial rate) $(2,465) $ 7,796 $ 7,133
Add (deduct) the effect of:
Lower income tax rate on earnings of US subsidiaries (81) (1,373) (1,263)
Canadian income tax on exchange loss (gain) which is
eliminated upon consolidation 511 362 (56)
Other 626 526 389
------- ------- -------
Tax at effective rate $(1,409) $ 7,311 $ 6,203
======= ======= =======
Effective tax rate 25.5% 41.8% 38.8
======= ======= =======
7. PER SHARE AMOUNTS
Net income (loss) per common share is computed by dividing net income (loss)
applicable to common shares by the weighted average number of common shares
outstanding during the year.
In the calculation of fully diluted earnings per share, shares
outstanding are adjusted for share options and shares issuable on conversion of
preferred shares. Earnings are adjusted by the amount of imputed interest on
share option proceeds and preferred share dividends. Earnings were not diluted
during the periods shown.
8. PERSON COSTS AND OBLIGATIONS
The Company contributed $145,300, $144,254 and $103,455 for 1998, 1997 and 1996,
respectively, to defined contribution plans. Under a supplementary defined
contribution plan established in 1991, costs of $198,294, $162,384 and $127,358
for 1998, 1997 and 1996, respectively, and the related liability are recorded in
the accounts.
The Company has established no other retirement benefit plans.
29
30
9. DISAGGREGATED INFORMATION
The Company has only a single reportable segment with activities as explained in
the preamble to the Notes. Production revenue, net of royalties, all of which
arises from external customers, is attributed to the country in which the
underlying production occurred. Most of the US gas, oil and ngls produced by the
Company are marketed by a single aggregator. Production revenues, net of
royalties, associated with the aggregator were $46,340,000 (1997 - $50,250,000;
1996 - $43,611,000). The Company's oil production from the Aneth and Ratherford
Units in the Four Corners area of Utah is sold under successive term contracts
to a regional refiner. Production revenues, net of royalties, associated with
sales to the regional refiner were $8,207,000 (1997 - $10,880,000; 1996 -
$10,641,000). The Company believes that alternative marketing arrangements would
be readily available for its gas, oil and liquids.
1998 1997 1996
-------- -------- --------
(in thousands)
Production revenue, net of royalties
United States $ 56,199 $ 63,227 $ 56,457
United Kingdom 4,411 6,231 4,155
Libya 1,005 169 -
-------- -------- --------
Total production revenues, net of royalties 61,615 69,627 60,612
Interest and other revenue 2,776 2,428 2,487
-------- -------- --------
$ 64,391 $ 72,055 $ 63,099
======== ======== ========
Net capital assets
United States $267,020 $213,856 $176,672
United Kingdom 11,337 14,733 17,778
Libya 9,835 14,373 13,297
Canada and other 285 328 305
-------- -------- --------
$288,477 $243,290 $208,052
======== ======== ========
10. UNCERTAINTY DUE TO THE YEAR 2000
During the past three years the Company has made changes to its computer systems
in order that date related information can be processed correctly after December
31, 1999 and the Company believes that such capability will be attained with
respect to its internal systems.
Despite these efforts, it is not possible to be certain that all aspects
of the year 2000 issue affecting the Company, including those related to the
provision of goods and services by third parties, will be fully resolved before
the year 2000.
30
31
11. UNITED STATES ACCOUNTING PRINCIPLES
(a) FULL COST ACCOUNTING
US full cost accounting rules differ materially from the Canadian full
cost accounting guidelines followed by the Company. In determining the
limitation on carrying values, US rules require the discounting of
future net revenues at 10%, and Canadian guidelines require the use of
undiscounted future net revenues and the deduction of estimated future
administrative and financing costs. During 1998 an impairment adjustment
would have been required under US accounting rules. The quarterly test
required by US accounting rules, using December 31 US gas and oil prices
of $2.15 per mcf and $9.72 per barrel, and June 30 US gas and oil prices
of $2.09 per mcf and $12.40 per barrel to determine future net revenues,
would have resulted in a write-down of US property carrying costs of
$42.6 million, after providing for tax recoveries of $22.9 million, at
December 31; and $16.1 million, after providing for tax recoveries of
$8.6 million, at June 30. Under Canadian guidelines the test resulted in
a write-down of UK property carrying costs of $0.6 million, after
providing for tax recoveries of $0.5 million; no corresponding
write-down was required under US accounting rules. Such write-downs will
result in reduced depletion expense, under US rules, for subsequent
periods.
(b) INCOME TAXES
US accounting principles require corporations to account for deferred
income taxes by the liability method. The effect on the Company of the
application of such method is not material.
(c) EARNINGS PER SHARE
US accounting principles require share options to be included in fully
diluted earnings (loss) per common share, where dilutive, assuming that
the share options are exercised using the treasury stock method.
(d) EFFECT ON EARNINGS
The effect on consolidated earnings of the differences between Canadian
and US accounting principles is summarized as follows:
Year ended December 31, 1998 1997 1996
----------------------- ------------ ------------ ------------
(in thousands except shares and per share amounts)
Net income (loss) applicable to common shares, as reported $ (9,055) $ 5,218 $ 4,842
Additional depletion (89,153) -- --
------------ ------------ ------------
(98,208) 5,218 4,842
Reduction in depletion expense 4,235 3,177 2,381
Reduction (increase) in deferred tax provision 30,010 (885) (1,021)
------------ ------------ ------------
Net income (loss) applicable to common shares under US
accounting principles $ (63,963) $ 7,510 $ 6,202
============ ============ ============
Net income (loss) per common share under US accounting principles:
Basic $ (4.75) $ 0.55 $ 0.47
============ ============ ============
Fully diluted $ (4.75) $ 0.54 $ 0.46
============ ============ ============
Fully diluted number of common shares outstanding 13,480,067 13,858,593 13,446,684
============ ============ ============
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32
(e) EFFECT ON BALANCE SHEET
The effect on the Consolidated Balance Sheet of the differences between
Canadian and US accounting principles is as follows:
As at December 31, 1998 1997
------------------ ---- ----
UNDER US Under US
AS ACCOUNTING As Accounting
REPORTED PRINCIPLES Reported Principles
--------- --------- --------- ---------
(in thousands)
Net capital assets $ 288,477 $ 185,517 $ 243,290 $ 225,248
Deferred tax - asset $ 5,182 $ 28,233 $ 3,442 $ 5,537
Deferred tax - liability $ 13,684 $ -- $ 13,367 $ 8,737
Deficit $ (17,565) $ (83,790) $ (7,089) $ (18,406)
Additionally for US reporting purposes, the preferred shares shown as
shareholders' equity in these consolidated financial statements would be
shown outside the equity section.
(f) INCOME TAX DISCLOSURES
Deferred tax assets (liabilities) are comprised of the following:
As at December 31, 1998 1997
------------------ -------- --------
(in thousands)
Deferred tax assets
Depletion and amortization $ 6,971 $ 3,413
Financing costs 390 633
Loss carryforwards 20,593 14,908
Other 382 346
-------- --------
28,336 19,300
Deferred tax liabilities
Depletion and amortization -- (22,431)
Other (103) (69)
-------- --------
(103) (22,500)
-------- --------
Net deferred tax assets (liabilities) $ 28,233 $ (3,200)
======== ========
At December 31, 1998 the Company's US net operating tax losses carried
forward amounted to $55,218,000 of which $6,119,000, $2,835,000,
$6,139,000, $18,007,000, $3,773,000, $2,090,000 and $16,255,000 expire in
the years 2005, 2007, 2009, 2010, 2011, 2012 and 2018, respectively.
Canadian net operating tax losses carried forward amounted to $2,231,000 of
which $1,998,000 and $233,000 expire in the years 2003 and 2005,
respectively. The Company is of the opinion that the tax benefit of these
tax losses will be realized.
32
33
Provisions for deferred income taxes are as follows:
Year ended December 31, 1998 1997 1996
----------------------- ---------------------- --------------------- ---------------------
CANADA US Canada US Canada US
-------- -------- -------- -------- -------- --------
(in thousands)
Income (loss) before income taxes and
dividends on preferred shares of
a subsidiary $ (5,002) $(85,440) $ 3,019 $ 17,629 $ 1,962 $ 16,406
======== ======== ======== ======== ======== ========
Provision for deferred income taxes $ (921) $(30,512) $ 2,122 $ 6,067 $ 1,239 $ 5,861
======== ======== ======== ======== ======== ========
The provision for income taxes differs from the amount of income
tax determined by applying the Canadian statutory rate to pre-tax income
before dividends paid on preferred shares of a subsidiary, as a result
of the following:
Year ended December 31, 1998 1997 1996
----------------------- -------- -------- --------
(in thousands)
Tax at statutory Canadian rate of 44.6% $(40,355) $ 9,213 $ 8,196
Lower income tax rate on earnings of US subsidiaries 7,830 (1,617) (1,428)
Canadian income tax on exchange loss (gain) which is
eliminated upon consolidation 511 362 (56)
Other 595 238 512
-------- -------- --------
Tax at effective rate $(31,419) $ 8,196 $ 7,224
======== ======== ========
Effective tax rate 34.7% 39.7% 39.3%
======== ======== ========
(g) STOCK-BASED COMPENSATION
The Company applies the intrinsic value method prescribed by APB Opinion
25 and related interpretations in accounting for share option
transactions. Accordingly, no compensation cost is recognized in the
accounts. US accounting principles require disclosure of the impact on
earnings and earnings per share of the value of options granted after
1994, calculated in accordance with FAS 123. Such impact, calculated
using the Black-Scholes option pricing model and resulting in option
fair values of $10.61, $11.49 and $12.54, applying risk-free interest
rates of 5.64%, 6.85% and 6.51% for options granted in 1998, 1997 and
1996, respectively, and assuming ten year expected option lives, no
dividend yields and expected volatilities of 25%, 24% and 24% on a
weighted average basis, would amount to a net of tax charge to income
(loss) of $1,502,000 (1997 - $1,348,000; 1996 - $872,000). After
reflecting this charge, pro forma net income (loss) applicable to common
shares under US accounting principles would be $(65,465,000), (1997 -
$6,162,000; 1996 - $5,330,000); pro forma net income (loss) per common
share under US accounting principles would be $(4.86) (1997 - $0.45;
1996 - $0.41); and pro forma fully diluted earnings (loss) per common
share under US accounting principles would be $(4.86) (1997 - $0.45;
1996 - $0.40). These effects are not necessarily indicative of those to
be expected in future years.
(h) SUPPLEMENTAL CASH FLOW INFORMATION
Net cash outflows for income taxes for the years 1998, 1997 and 1996
were $14,000, $141,000 and $26,000, respectively. Cash outflows for
long-term debt interest were $628,000 in 1998.
33
34
SUPPLEMENTARY FINANCIAL INFORMATION
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
DECEMBER 31, 1998
(Unaudited)
RESERVE INFORMATION
Reports prepared by Netherland, Sewell & Associates, Inc. as to the Company's US
reserves and by the Company as to the UK reserves, estimate the total proved and
proved developed producing reserves owned by the Company, before and after
royalty deductions, as follows:
TOTAL PROVED RESERVES BEFORE ROYALTY DEDUCTIONS:
Crude Oil &
Natural Gas - mmcf Ngls - barrels(*)
------------------------------------ -----------------
United North United
States Sea Total States
------- ------ ------- ----------
December 31, 1996 127,250 23,364 150,614 10,518,800
Purchase of producing properties -- -- -- --
Revision of previous estimates 7,029 (1,037) 5,992 1,317,800
Extensions, discoveries and other additions 21,153 -- 21,153 2,046,400
Sale of proved properties -- -- -- --
Production (24,306) (4,010) (28,316) (936,300)
------- ------ ------- ----------
December 31, 1997 131,126 18,317 149,443 12,946,700
PURCHASE OF PRODUCING PROPERTIES 4,745 -- 4,745 18,600
REVISION OF PREVIOUS ESTIMATES 10,683 (5,119) 5,564 (1,478,900)
EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS 29,360 -- 29,360 4,871,800
SALE OF PROVED PROPERTIES -- -- -- --
PRODUCTION (26,960) (3,088) (30,048) (1,158,100)
------- ------ ------- ----------
DECEMBER 31, 1998 148,954 10,110 159,064 15,200,100
======= ====== ======= ==========
TOTAL PROVED RESERVES AFTER ROYALTY DEDUCTIONS:
Crude Oil &
Natural Gas - mmcf Ngls - barrels(*)
------------------------------------ -----------------
United North United
States Sea Total States
------- ------ ------- ----------
December 31, 1996 103,437 23,364 126,801 9,252,900
Purchase of producing properties -- -- -- --
Revision of previous estimates 5,136 (1,037) 4,099 1,102,800
Extensions, discoveries and other additions 17,628 -- 17,628 1,697,600
Sale of proved properties -- -- -- --
Production (19,421) (4,010) (23,431) (799,500)
------- ------ ------- ----------
December 31, 1997 106,780 18,317 125,097 11,253,800
PURCHASE OF PRODUCING PROPERTIES 3,512 -- 3,512 13,800
REVISION OF PREVIOUS ESTIMATES 7,819 (5,119) 2,700 (1,316,000)
EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS 22,268 -- 22,268 4,142,300
SALE OF PROVED PROPERTIES -- -- -- --
PRODUCTION (21,416) (3,088) (24,504) (986,800)
------- ------ ------- ----------
DECEMBER 31, 1998 118,963 10,110 129,073 13,107,100
======= ====== ======= ==========
(*) 26,800 (1997 - 58,900) barrels of natural gas liquids, before and after
royalty deductions, associated with the UK gas reserves are not included in this
table.
34
35
(Unaudited)
PROVED DEVELOPED PRODUCING RESERVES BEFORE ROYALTY DEDUCTIONS:
Crude Oil &
Natural Gas - mmcf Ngls - barrels(*)
------------------------------------ -----------------
United United United
States Kingdom Total States
------ ------- ----- ---------
December 31, 1996 53,400 23,364 76,764 9,175,900
====== ====== ====== =========
December 31, 1997 55,013 18,317 73,330 8,209,000
====== ====== ====== =========
DECEMBER 31, 1998 70,082 10,108 80,190 5,430,000
====== ====== ====== =========
PROVED DEVELOPED PRODUCING RESERVES AFTER ROYALTY DEDUCTIONS:
Crude Oil &
Natural Gas - mmcf Ngls - barrels(*)
------------------------------------ -----------------
United United United
States Kingdom Total States
------ ------- ----- ------
December 31, 1996 43,000 23,364 66,364 8,138,000
====== ====== ====== =========
December 31, 1997 43,979 18,317 62,296 7,241,300
====== ====== ====== =========
DECEMBER 31, 1998 55,418 10,108 65,526 4,739,000
====== ====== ====== =========
RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES
Year ended December 31, 1998 1997 1996
- ----------------------- -------- -------- --------
(in thousands)
United States
Revenue - net of royalties $ 56,199 $ 63,227 $ 56,457
Production costs (15,675) (14,901) (13,291)
Depletion and amortization (39,460) (33,414) (28,976)
-------- -------- --------
Results of operations from producing activities before income taxes 1,064 14,912 14,190
Income tax expense (333) (5,223) (5,146)
-------- -------- --------
Results of operations from producing activities after income taxes $ 731 $ 9,689 $ 9,044
======== ======== ========
United Kingdom
Revenue - net of royalties $ 4,411 $ 6,231 $ 4,155
Production costs (964) (1,064) (904)
Depletion and amortization (3,646) (3,319) (1,861)
-------- -------- --------
Results of operations from producing activities before income taxes (199) 1,848 1,390
Income tax expense 117 (787) (600)
-------- -------- --------
Results of operations from producing activities after income taxes $ (82) $ 1,061 $ 790
======== ======== ========
Libya
Revenue - net of royalties $ 1,005 $ 169 $ --
Production costs (1,041) (38) --
Depletion and amortization (5,144) (131) --
-------- -------- --------
Results of operations from producing activities before income taxes (5,180) -- --
Income tax expense 2,312 -- --
-------- -------- --------
Results of operations from producing activities after income taxes $ (2,868) $ -- $ --
======== ======== ========
Total
Revenue - net of royalties $ 61,615 $ 69,627 $ 60,612
Production costs (17,680) (16,003) (14,195)
Depletion and amortization (48,250) (36,864) (30,837)
-------- -------- --------
Results of operations from producing activities before income taxes (4,315) 16,760 15,580
Income tax expense 2,096 (6,010) (5,746)
-------- -------- --------
Results of operations from producing activities after income taxes $ (2,219) $ 10,750 $ 9,834
======== ======== ========
35
36
(Unaudited)
CAPITALIZED COSTS RELATING TO GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES
December 31, 1998 1997 1996
- ------------ -------- -------- --------
(in thousands)
Proved gas and oil properties $475,902 $402,885 $337,538
Unproved gas and oil properties 76,478 56,922 52,816
-------- -------- --------
552,380 459,807 390,354
Accumulated depletion 266,066 224,154 187,403
-------- -------- --------
Net capitalized costs $286,314 $235,653 $202,951
======== ======== ========
COSTS INCURRED IN GAS AND OIL PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
Year ended December 31, 1998 1997 1996
- ----------------------- -------- -------- --------
(in thousands)
Property acquisition costs:
United States $ 7,903 $ 9,164 $ 13,954
United Kingdom 115 137 722
Other Foreign -- -- 68
-------- -------- --------
8,018 9,301 14,744
-------- -------- --------
Purchase of producing properties:
United States 883 -- 2,077
-------- -------- --------
Sale of producing properties:
United States -- -- (1,040)
-------- -------- --------
Exploration costs:
United States 43,317 35,540 17,453
United Kingdom 72 115 --
Other Foreign 606 1,207 434
-------- -------- --------
43,995 36,862 17,887
-------- -------- --------
Development costs:
United States 39,606 23,260 22,131
United Kingdom 71 30 1,874
-------- -------- --------
39,677 23,290 24,005
-------- -------- --------
$ 92,573 $ 69,453 $ 57,673
======== ======== ========
36
37
(Unaudited)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THEREIN
RELATING TO PROVED OIL, NATURAL GAS LIQUIDS AND NATURAL GAS RESERVES
The following standardized measure of discounted future net cash flow was
computed in accordance with Financial Accounting Standards Board Statement #69
using year-end prices and costs, and year-end statutory tax rates. Royalty
deductions were based on laws, regulations and contracts existing at the end of
each period. No values are given to unproved properties or to probable reserves
that may be recovered from proved properties.
The inexactness associated with estimating reserve quantities, future production
streams and future development and production expenditures, together with the
assumptions applied in valuing future production, substantially diminish the
reliability of this data. The values so derived are not considered to be
estimates of fair market value. THE COMPANY THEREFORE CAUTIONS AGAINST
SIMPLISTIC USE OF THIS INFORMATION.
December 31 1998 1997 1996
- ----------- --------- --------- ---------
(in thousands)
United States
Future cash inflows $ 382,771 $ 480,669 $ 577,313
Future production costs (116,976) (121,380) (148,061)
Future development costs (60,203) (57,208) (39,375)
Future income tax expense -- (46,742) (85,464)
--------- --------- ---------
Future net cash flows 205,592 255,339 304,413
Ten percent annual discount for estimated timing of cash flows (62,089) (70,844) (89,292)
--------- --------- ---------
Standardized measure of discounted future net cash flows 143,503 184,495 215,121
--------- --------- ---------
United Kingdom
Future cash inflows 19,349 32,774 48,392
Future production costs (7,483) (5,734) (8,045)
Future development costs (1,457) (1,338) (1,603)
Future income tax expense -- (6,340) (6,601)
--------- --------- ---------
Future net cash flows 10,409 19,250 32,143
Ten percent annual discount for estimated timing of cash flows (1,404) (4,172) (8,241)
--------- --------- ---------
Standardized measure of discounted future net cash flows 9,005 15,078 23,902
--------- --------- ---------
Total
Future cash inflows 402,120 513,443 625,705
Future production costs (124,459) (127,114) (156,106)
Future development costs (61,660) (58,658) (40,978)
Future income tax expense -- (53,082) (92,065)
--------- --------- ---------
Future net cash flows 216,001 274,589 336,556
Ten percent annual discount for estimated timing of cash flows (63,493) (54,856) (97,533)
--------- --------- ---------
Standardized measure of discounted future net cash flows $ 152,508 $ 199,573 $ 239,023
========= ========= =========
37
38
(Unaudited)
The following table sets out principal sources of change in the standardized
measure of discounted future net cash flows during the respective periods.
Year ended December 31, 1998 1997 1996
- ----------------------- --------- --------- ---------
(in thousands)
Sales of oil, ngls and natural gas produced,
net of production costs $ (45,231) $ (56,061) $ (48,233)
Net change in prices and production costs (79,471) (73,047) 120,858
Extensions and discoveries, less related costs 30,159 28,219 50,995
Purchase of producing properties 2,793 -- 10,638
Sales of producing properties -- -- (436)
Development costs incurred during the period 23,131 10,096 15,026
Revisions of previous quantity estimates (17,191) 22,388 (4,462)
Accretion of discount 19,958 23,902 15,457
Net change in income taxes 38,739 26,534 (51,064)
Changes in estimated future development costs (16,421) (12,551) (13,950)
Other (3,531) (8,930) 6,700
--------- --------- ---------
Net increase (decrease) (47,065) (39,450) 101,529
Beginning of year 199,573 239,023 137,494
--------- --------- ---------
End of year $ 152,508 $ 199,573 $ 239,023
========= ========= =========
QUARTERLY FINANCIAL INFORMATION
Per
Gross Income Common
Quarter Ended Revenue Profit (loss) Share
- ------------- ------- ------- ------- --------
(in thousands except per share amounts)
MARCH 31,1998 $18,718 $ 2,884 $ 556 $ 0.04
JUNE 30,1998 14,804 (342) (1,735) (0.13)
SEPTEMBER 30,1998 13,943 (1,345) (2,472) (0.18)
DECEMBER 31,1998 16,926 (6,719) (5,404) (0.40)
March 31, 1997 $22,563 $ 8,444 $ 3,924 $ 0.29
June 30, 1997 14,807 1,271 (470) (0.04)
September 30, 1997 14,891 1,949 36 0.01
December 31, 1997 19,794 5,807 1,728 0.12
38
39
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There have been no disagreements between Chieftain and Chieftain's auditors on
accounting or financial disclosure matters.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
Additional information relating to directors of the Company is incorporated
herein by reference from page 4 of the Company's Information Circular dated
March 11, 1999 for the annual meeting of shareholders on May 13, 1999.
ITEM 11. EXECUTIVE COMPENSATION
"Executive Compensation" on pages 5 to 9 of the Company's Information Circular
dated March 11, 1999 for the annual meeting of shareholders on May 13, 1999 is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
"Voting Shares" and "Share Ownership" on pages 2 and 3 of the Company's
Information Circular dated March 11, 1999 for the annual meeting of shareholders
on May 13, 1999 is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K
The following is a listing of the financial statements and financial statement
schedules which are included in this Form 10-K report.
FINANCIAL STATEMENTS
Reference is made to the list of financial statements on page 19 of this report.
EXHIBITS
Reference is made to the Index to Exhibits on page 40 of this report.
39
40
Exhibits
Exhibit
Number Exhibit
------ -------
* 3 (a) Articles of Incorporation of the Company.
* 3 (b) Articles of Amendment of the Company.
* 3 (c) Articles of Amalgamation of the Company.
* 3 (d) By-laws number 1 and number 2 of the Company.
** 4 (a) Form of Subordinated Guarantee Agreement of the Company.
*** 4 (b) Shareholder Rights Plan adopted April 23, 1994.
**** 10 (a)(i) Chieftain International, Inc. Retirement Plan as amended May 15, 1997.
**** 10 (a)(ii) Chieftain International, Inc. Supplementary Retirement Plan as amended March 20, 1997.
**** 10 (b) Chieftain International, Inc. Share Option Plan as amended March 15, 1996.
* 10 (c) Chieftain International, Inc. Savings Plan.
* 10 (d) Form of indemnification agreement between the Company and each of the officers and directors
of the Company.
***** 21 Information Circular dated March 11, 1999 relating to the Company's annual meeting of shareholders
to be held on May 13, 1999.
****** 22 Subsidiaries of the Company.
***** 24 (a) Consent of Netherland, Sewell & Associates, Inc.
***** 24 (b) Consent of PricewaterhouseCoopers LLP.
* Previously filed as an exhibit to the Registration Statement on Form S-1, File No. 33-27254.
** Previously filed as an exhibit to the Registration Statement on Form S-1/S-3, File No. 33-51630.
*** Previously filed as an exhibit to Form 8-K dated March 1, 1994.
**** Previously filed as an exhibit to Form 10-K dated March 20, 1998.
***** Filed herewith.
****** Previously filed as an exhibit to Form 10-K dated March 17, 1994.
40
41
SIGNATURES
Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CHIEFTAIN INTERNATIONAL,INC.
By: /s/ STANLEY A. MILNER By: /s/ EDWARD L. HAHN
Stanley A. Milner, A.O.E., LL.D. Edward L. Hahn
President and Senior Vice President, Finance
Chief Executive Officer and Treasurer and Chief
Financial Officer
Dated: March 11,1999
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 and
in the capacities and on the date indicated.
/s/ D. E. MITCHELL Director March 11, 1999
- ---------------------------------
D. E. Mitchell O.C.
/s/ S. A. MILNER President, Chief Executive Officer and March 11, 1999
- ------------ -------------------- Director
S. A. Milner, A.O.E., LL.D.
/s/ S. C. HURLEY Director March 11, 1999
- ---------------------------------
S. C. Hurley
/s/ H. J. KELLY Director March 11, 1999
- ---------------------------------
H. J. Kelly
/s/ J. E. MAYBIN Director March 11, 1999
- ---------------------------------
J. E. Maybin
/s/ L. G. MUNIN Director March 11, 1999
- ---------------------------------
L. G. Munin
/s/ E. S. ONDRACK Director March 11, 1999
- ---------------------------------
E. S. Ondrack
/s/ S. T. PEELER Director March 11, 1999
- ---------------------------------
S. T. Peeler
/s/ E. L. HAHN Senior Vice President, Finance and March 11, 1999
- --------------------------------- Treasurer and Chief Financial Officer
E. L. Hahn
/s/ R. J. STEFURE Vice President, Controller and March 11, 1999
- --------------------------------- Chief Accounting Officer
R. J. Stefure
41
42
Index to Exhibits
Exhibit
Number Exhibit
------ -------
* 3 (a) Articles of Incorporation of the Company.
* 3 (b) Articles of Amendment of the Company.
* 3 (c) Articles of Amalgamation of the Company.
* 3 (d) By-laws number 1 and number 2 of the Company.
** 4 (a) Form of Subordinated Guarantee Agreement of the Company.
*** 4 (b) Shareholder Rights Plan adopted April 23, 1994.
**** 10 (a)(i) Chieftain International, Inc. Retirement Plan as amended May 15, 1997.
**** 10 (a)(ii) Chieftain International, Inc. Supplementary Retirement Plan as amended March 20, 1997.
**** 10 (b) Chieftain International, Inc. Share Option Plan as amended March 15, 1996.
* 10 (c) Chieftain International, Inc. Savings Plan.
* 10 (d) Form of indemnification agreement between the Company and each of the officers and directors
of the Company.
***** 21 Information Circular dated March 11, 1999 relating to the Company's annual meeting of shareholders
to be held on May 13, 1999.
****** 22 Subsidiaries of the Company.
***** 24 (a) Consent of Netherland, Sewell & Associates, Inc.
***** 24 (b) Consent of PricewaterhouseCoopers LLP.
* Previously filed as an exhibit to the Registration Statement on Form S-1, File No. 33-27254.
** Previously filed as an exhibit to the Registration Statement on Form S-1/S-3, File No. 33-51630.
*** Previously filed as an exhibit to Form 8-K dated March 1, 1994.
**** Previously filed as an exhibit to Form 10-K dated March 20, 1998.
***** Filed herewith.
****** Previously filed as an exhibit to Form 10-K dated March 17, 1994.
43
EXHIBIT 21
[LOGO] CHIEFTAIN
INTERNATIONAL, INC.
1201 TD Tower
10088 - 102 Avenue
Edmonton, Alberta, Canada
T5J 2Z1
Telephone (780) 425-1950
Facsimile (780) 429-4681
Notice of Annual Meeting of Shareholders
to be held on Thursday, May 13, 1999
The annual meeting of the shareholders of Chieftain International, Inc. ("the
Company") will be held in the Marlboro Room of The Westin Hotel, 10135 - 100
Street, Edmonton, Alberta, Canada on Thursday, May 13, 1999 at 10:30 a.m.
(Edmonton time) to receive and consider the annual report for the year ended
December 31, 1998, the financial statements as at and for the year ended
December 31, 1998, and the report of the auditors on the financial statements,
and in addition for the following purposes:
1. to elect three directors;
2. to appoint auditors of the Company until the close of the next annual
meeting;
3. to reconfirm the Shareholder Rights Plan; and
4. to transact all such other business as may properly come before the
meeting or any adjournment thereof.
The Board of Directors has fixed the close of business on the 24th day of March,
1999 as the record date for the determination of shareholders who are entitled
to notice of and to vote at the annual meeting. The share transfer books will
not be closed.
If you are unable to attend the meeting in person, please complete, date and
sign the enclosed form of proxy and mail it promptly in the enclosed
postage-paid envelope.
By order of the Board of Directors
/s/ Esther S. Ondrack
---------------------------------
Esther S. Ondrack
Senior Vice President and
March 11, 1999 Secretary
2
44
[LOGO] CHIEFTAIN
INTERNATIONAL, INC.
1201 TD Tower
10088 - 102 Avenue
Edmonton, Alberta, Canada
T5J 2Z1
Telephone (780) 425-1950
Facsimile (780) 429-4681
INFORMATION CIRCULAR
SOLICITATION OF PROXIES
This Information Circular and the accompanying Notice of Meeting and form of
proxy are being mailed to shareholders on or about March 29, 1999 in connection
with the solicitation of proxies by the management of Chieftain International,
Inc. (hereinafter called the "Company") to be voted at the annual meeting of
shareholders (the "meeting") to be held at 10:30 a.m., Edmonton time, in the
Marlboro Room of The Westin Hotel, 10135 - 100 Street, Edmonton, Alberta, Canada
on Thursday, May 13, 1999. The Directors have fixed the close of business on
March 24, 1999 as the record date for the determination of shareholders who are
entitled to notice of and to vote at the meeting.
The solicitation will be primarily by mail and electronic means and the cost
will be borne by the Company. In addition, the Company will reimburse banks,
brokerage houses and other custodians, nominees or fiduciaries for reasonable
expenses incurred by them in forwarding proxy material to their principals to
obtain authorization for the execution of proxies.
All shares represented by proxy will be voted, provided that instruments of
proxy are received by CIBC Mellon Trust Company, registrar and transfer agent,
at its office at 600, 333 - 7th Avenue S.W., Calgary, Alberta, Canada, T2P 2Z1,
or by the Company at its principal office at 1201 TD Tower, 10088 - 102 Avenue,
Edmonton, Alberta, Canada, T5J 2Z1, no later than 10:30 a.m., May 12, 1999.
The Company's accounts are maintained, and all dollar amounts herein are stated,
in United States dollars. The average rates of exchange for Canadian dollars per
US$1.00 during 1997, 1998 and during the period January 1 to February 26, 1999,
were $1.384, $1.4831 and $1.5083, respectively. The rates on December 31, 1997,
December 31, 1998, and February 26, 1999 were $1.4291, $1.5305 and $1.5074,
respectively.
APPOINTMENT AND REVOCATION OF PROXIES
THE ENCLOSED PROXY IS SOLICITED BY AND ON BEHALF OF THE MANAGEMENT OF THE
COMPANY. THE PERSONS DESIGNATED IN THE ACCOMPANYING FORM OF PROXY ARE DIRECTORS
AND OFFICERS OF THE COMPANY. A SHAREHOLDER HAS THE RIGHT TO APPOINT SOME OTHER
PERSON, WHO NEED NOT BE A SHAREHOLDER, TO REPRESENT HIM OR HER AT THE MEETING
AND HE OR SHE MAY EXERCISE THIS RIGHT BY INSERTING SUCH OTHER PERSON'S NAME IN
THE BLANK SPACE PROVIDED IN THE FORM OF PROXY.
The instrument appointing a proxy shall be in writing and signed by the
shareholder or the shareholder's attorney authorized in writing. If the
shareholder is a corporation, the document must carry the signature of a duly
authorized officer or attorney thereof.
1
45
A registered shareholder who has deposited a proxy has the power to revoke it. A
proxy may be revoked by instrument in writing executed by the shareholder or by
his or her attorney authorized in writing or, if the shareholder is a
corporation, by a duly authorized officer or attorney thereof, and deposited
either at the head office of the Company at any time up to and including the
last business day preceding the day of the meeting, or any adjournment thereof,
at which the proxy is to be used, or with the chairman of such meeting on the
day of the meeting or adjournment thereof, and upon either of such deposits the
proxy is revoked. In addition, a proxy may be revoked in any other manner
permitted by law.
EXERCISE OF DISCRETION BY PROXY
The person named in the enclosed proxy will vote the shares in respect of which
he or she is appointed in accordance with the direction of the shareholder
appointing him or her. In the absence of specific direction, such shares will be
voted in favor of the election of the directors and the appointment of the
auditors named in this information circular and in favor of the resolution to
reconfirm the Shareholder Rights Plan. If any amendments or variations in the
matters identified in the notice of meeting or if any other matters properly
come before the meeting or any adjournment or adjournments thereof, the proxy
confers discretionary authority upon the shareholder's nominee to vote on such
amendments or variations or such other matters in accordance with his or her
best judgment. Proxies will not be voted with respect to any material amendment
or any material variation of the matters which come before the meeting. At the
date of the notice of meeting, management knows of no such amendment or
variation or other matter to come before the meeting.
VOTING SHARES
The registered holders of the outstanding common shares of the Company of record
at the close of business on March 24, 1999 are entitled to notice of and to vote
at the meeting. The number of common shares outstanding on December 31, 1998 and
on February 26, 1999 was 13,355,891. Each common share entitles the registered
holder thereof to one vote, which may be given in person or by proxy. Approval
of each matter to come before the meeting requires an affirmative vote by the
holders of a majority of the shares voted at the meeting, whether in person or
by proxy. The quorum for the meeting is two persons present and holding or
representing by proxy at least one-third of the issued shares of the Company for
the time being having voting rights.
SHARE OWNERSHIP
The following table describes those shareholders which, to the knowledge of the
Company, own beneficially, as at February 26, 1999, more than 5 percent of the
outstanding common shares of the Company:
Amount and Nature of
Beneficial
Name and Address Ownership of Common
Of Beneficial Owner Shares Percent of Class
------------------- ------ ----------------
Warburg Pincus Asset Management, Inc.
466 Lexington Avenue 985,500(1) 7.3
New York, N.Y. 10017
OppenheimerFunds Inc.
Two World Trade Center, Suite 3400 919,600(2) 6.9
New York, New York 10048-0203
Stanley A. Milner
President and Chief Executive Officer of the Company 739,618(3) 5.5
1201 TD Tower, 10088 - 102 Avenue
Edmonton, Alberta, Canada T5J 2Z1
Strong Capital Management, Inc.
100 Heritage Reserve 681,900(4) 5.1
Menomonee Falls, Wisconsin 53051
(1) The information is based on filings with the Securities and Exchange
Commission on Schedule 13-G according to which the beneficial owner has
sole dispositive power with respect to 985,500 common shares, sole voting
power with respect to 584,000 shares and shared voting power with respect
to 370,400 shares.
(2) The information is based on filings with the Securities and Exchange
Commission on Schedule 13-G according to which the beneficial owner has
shared dispositive power with respect to 919,600 shares.
2
46
(3) Includes 143,333 shares issuable upon exercise of options exercisable
within 60 days and 48,750 shares issuable upon conversion of Chieftain
International Funding Corp. $1.8125 Convertible Redeemable Preferred
shares.
(4) The information is based on filings with the Securities and Exchange
Commission on Schedule 13-G according to which the beneficial owner has
sole dispositive power with respect to 681,900 common shares and sole
voting power with respect to 212,100 shares.
The table below indicates the number of the Company's common shares and the
Chieftain International Funding Corp. $1.8125 Convertible Redeemable Preferred
Shares (the "preferred shares") owned by (i) the directors (including those
nominated for election); (ii) the Named Executive Officers as defined on page 5;
and (iii) all directors and officers as a group. The common shares shown as
issuable upon exercise of options are issuable within 60 days. Each preferred
share is convertible into 1.25 common shares of the Company.
SHARES BENEFICIALLY OWNED AS AT FEBRUARY 26, 1999
Percent of Class
Common Shares (1) Preferred Shares Percent of Class
------------- ---------------- ---------------- ----------------
Stephen C. Hurley 86,323(2) - - -
Hugh J. Kelly 32,666(3) - 10,000 -
John E. Maybin 32,666(4) - - -
Stanley A. Milner 690,868(5) 5.1 39,000 1.4
David E. Mitchell 41,666(3) - - -
Louis G. Munin 35,666(3) - 2,000 -
Esther S. Ondrack 109,703(6) - - -
Stuart T. Peeler 14,466(7) - 30,000 1.1
Edward L. Hahn(8) 39,263(9) - - -
Ronald J. Stefure(10) 37,647(11) - - -
All directors and officers as a group 1,197,806(12) 8.4 81,000 3.0
(1) Percentages of less than one are omitted. (8) E.L. Hahn is Senior Vice President, Finance and
Treasurer of the Company.
(2) Includes 83,333 shares issuable upon exercise of options.
(9) Includes 30,833 shares issuable upon exercise of
(3) Includes 31,666 shares issuable upon exercise of options. options.
(4) Includes 31,166 shares issuable upon exercise of options. (10) R. J. Stefure is Vice President and Controller of the
Company.
(5) Includes 143,333 shares issuable upon exercise of options.
(11) Includes 36,666 shares issuable upon exercise of
(6) Includes 87,500 shares issuable upon exercise of options. options.
(7) Shares issuable upon exercise of options. (12) Includes 558,961 shares issuable upon exercise of
options.
COMMITTEES AND MEETINGS OF THE BOARD OF DIRECTORS
The Board of Directors held four regularly scheduled meetings during the year
ended December 31, 1998. Each member of the Board of Directors including those
nominated for election attended all of the meetings of the Board of Directors
and of the committees on which he or she served during 1998. The Company has
standing Audit, Nominating and Corporate Governance, Compensation and Pension
Committees of the Board of Directors. The members of the committees are
appointed by the full Board upon recommendation of the Nominating and Corporate
Governance Committee.
AUDIT COMMITTEE
The Audit Committee, which during 1998 consisted of L.G. Munin as Chairman and
J.E. Maybin, D.E. Mitchell and S.T. Peeler, all non-employee directors, held
four meetings during 1998. The primary function of the Audit Committee is to
assist the Board of Directors in providing corporate oversight in the areas of
financial reporting, internal control and the audit process. In connection with
these reviews it meets alone with Company personnel and with the independent
auditors who have access to the Committee at any time. The Committee recommends
to the Board for its approval the annual appointment of external auditors.
NOMINATING AND CORPORATE GOVERNANCE COMMITTEE
The Nominating and Corporate Governance Committee is comprised of J.E. Maybin as
Chairman and D.E. Mitchell, L.G. Munin and S.T. Peeler. This Committee assists
the Board by reviewing corporate governance and Board nomination matters and
making recommendations to the Board as appropriate. The Committee met once
during 1998
3
47
to consider the size and composition of the Board of Directors, nominees for
the election of directors at the 1998 annual meeting and corporate governance
practices.
COMPENSATION COMMITTEE
The Compensation Committee is comprised of S.T. Peeler as Chairman and H.J.
Kelly, J.E. Maybin and D.E. Mitchell, none of whom are officers of the Company,
with the exception of D. E. Mitchell, who is the non-executive Chairman of the
Board. The primary function of the Compensation Committee is to assist the Board
of Directors by reviewing compensation matters and making recommendations to the
Board with respect to compensation arrangements and benefit plans for officers
of the Company and with respect to the Company's Share Option Plan and by
reviewing and approving compensation budgets, benefits plans and policies,
salaries of certain non-officer employees and succession planning. The
Compensation Committee met twice in 1998.
PENSION COMMITTEE
The Pension Committee is comprised of H.J. Kelly as Chairman, E.L. Hahn, J.E.
Maybin, D.E. Mitchell and S.T. Peeler. This Committee reviews generally and
makes recommendations to the Board of Directors with regard to the Company's
retirement plans, related agreements and the appointment and performance of
retirement fund investment managers. This committee met twice during 1998.
ELECTION OF DIRECTORS
The Articles of the Company provide that directors are elected and retire in
rotation. Directors are elected to hold office until the close of the third
ensuing annual meeting and at each annual meeting approximately one-third of the
board is elected. Effective upon the termination of the forthcoming annual
meeting, the terms of Hugh J. Kelly, Louis G. Munin and Stuart T. Peeler will
expire. It is proposed that three directors be elected for the ensuing three
years. Management will place before the annual meeting as nominees Hugh J.
Kelly, Louis G. Munin and Stuart T. Peeler and PROXIES GIVEN PURSUANT TO THIS
SOLICITATION BY MANAGEMENT WILL BE VOTED FOR THE ELECTION OF SAID NOMINEES
UNLESS INDICATED OTHERWISE. While management knows of no reason why the said
nominees will be unable or unwilling to serve as directors, if for any reason
they shall be unable or unwilling to serve, it is intended that proxies given
pursuant to this solicitation by management will be voted for substitute
nominees selected by management.
Information is given below with respect to the nominees and the directors whose
terms of office as directors will continue after the meeting.
SERVED AS TERM
NAME AND PRINCIPAL OCCUPATION DIRECTOR SINCE EXPIRES
----------------------------- -------------- -------
STEPHEN C. HURLEY, Dallas, Texas
Senior Vice President and Chief Operating Officer of the 1997 2000
Company(1)
HUGH J. KELLY, Mandeville, Louisiana
Corporate Director and Consultant(2) 1989 2002(3)
JOHN E. MAYBIN, Calgary, Alberta
Corporate Director 1991 2000
STANLEY A. MILNER, A.O.E., LL.D., Edmonton, Alberta
President and Chief Executive Officer of the Company(4) 1988 2001
DAVID E. MITCHELL, O.C., Calgary, Alberta
Chairman of Alberta Energy Company Ltd.(5) 1989 2001
LOUIS G. MUNIN, Dallas, Texas
Corporate Director and Financial Consultant(6) 1989 2002(3)
ESTHER S. ONDRACK, Spruce Grove, Alberta
Senior Vice President and Secretary of the Company(7) 1988 2000
STUART T. PEELER, Tucson, Arizona
Corporate Director and Petroleum Industry Consultant(8) 1989 2002(3)
(1) S.C. Hurley joined the Company as Senior Vice President and Chief
Operating Officer in September, 1995. From 1987 until 1991 he was Vice
President, Exploration of Ocean Drilling & Exploration Company and from
1991 to 1995 he was Vice President, Exploration of Murphy Exploration and
Production Company.
(2) H.J. Kelly is a director of Gulf Island Fabrication Inc. and Tidewater
Inc.
(3) Date when proposed term of office will expire.
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48
(4) S. A. Milner is a director of Alberta Energy Company Ltd. and Canadian
Pacific Limited.
(5) D. E. Mitchell is a director of Alberta Energy Company Ltd. and Air Canada.
(6) L. G. Munin is a director of Lafarge Canada Inc. and Walden Residential
Properties, Inc.
(7) E. S. Ondrack was Vice President and Secretary of the Company until June,
1995.
(8) S. T. Peeler is a director of Homestake Mining Company.
EXECUTIVE COMPENSATION
The following table sets forth certain information regarding the compensation
paid, during each of the Company's three most recently completed fiscal years,
to the Chief Executive Officer and the Company's next four most highly
compensated executive officers (collectively "Named Executive Officers").
SUMMARY COMPENSATION TABLE
(U.S. $)
- ------------------------------------------------------------------------------------------------------------------------------
Annual Compensation Long - Term Compensation
--------------------------------- ------------------------------
Awards Payouts
---------------------- -------
Securities Restricted
Under Shares
Other Options or
Name and Annual and SARs Restricted LTIP All Other
Principal Salary Bonus Compensation Granted Share Units Payouts Compensation
Position Year ($) ($) ($) (#) ($) ($) (1)($)
-------- ---- ------- ------- ------------ --------- ------------ ------- ---------------
Stanley A. Milner 1998 355,000 100,000 (2) 5,000 - - 88,561
President and 1997 320,273 250,000 (2) 25,000 - - 83,568
Chief Executive Officer 1996 293,592 150,000 (2) - - - 76,475
Stephen C. Hurley 1998 283,875 70,000 (2) 30,000 - - 64,085
Senior Vice President and 1997 245,946 185,000 (2) 25,000 - - 52,317
Chief Operating Officer 1996 226,689 100,000 (2) - - - 45,414
Edward L. Hahn 1998 142,655 21,500 (2) - - - 44,258
Senior Vice President, 1997 136,176 40,000 (2) 10,000 - - 34,755
Finance and Treasurer 1996 130,078 35,000 (2) - - - 33,102
Esther S. Ondrack 1998 129,231 19,500 (2) 5,000 - - 40,142
Senior Vice President 1997 122,157 40,000 (2) 15,000 - - 30,517
and Secretary 1996 116,246 35,000 (2) - - - 28,979
Ronald J. Stefure 1998 95,790 14,500 (2) - - - 25,364
Vice President 1997 95,570 35,000 (2) 9,000(3) - - 21,063
and Controller 1996 78,293 20,000 (2) - - - 13,619
(1) The amounts in this column represent Company contributions to the defined
contribution retirement plans, the savings plan and the life insurance plan
in which plans the Named Executive Officers participate on the same basis as
all other employees. Such amounts do not include directors fees paid to S.A.
Milner ($30,000 in 1996, $24,000 in 1997 and $25,000 in 1998), E.S. Ondrack
($30,000 in 1996, $24,000 in 1997, and $25,000 in 1998), and S.C. Hurley
($9,423 in 1997 and $25,000 in 1998) or a relocation allowance of $358,100
paid to S.C. Hurley in 1996.
(2) The value of perquisites and benefits for each of the Named Executive
Officers is not greater than the lesser of Cdn. $50,000 and 10% of total
annual salary and bonus.
(3) Includes 4,000 Share Appreciation Rights ("SARs") and 5,000 share options.
The following table sets forth information regarding grants of share options to
the Named Executive Officers during the financial year ended December 31, 1998.
OPTION GRANTS DURING 1998
----------------------------------------------------------------------------------------
Potential Realizable Value at Assumed
Annual Rates of Stock Price
Number of Shares % of Total Options Appreciation for Option Term
Under Options Granted Exercise ------------------------------------- Expiration
Name Granted in 1998 Price(1) 5% 10% Date
---- ---------------- ------------------- --------- ----------- -------- -----------
Stanley A. Milner 5,000 7.7 $23.00 $72,325 $183,280 May 13, 2008
Stephen C. Hurley 5,000 7.7 23.00 72,325 183,280 May 13, 2008
25,000 38.5 18.00 283,000 717,175 Sept. 21, 2008
Esther S. Ondrack 5,000 7.7 23.00 72,325 183,280 May 13, 2008
(1) Market value of shares underlying options on the date of grant.
5
49
The options are exercisable as to one-third of the granted amount on and after
each of the first three anniversaries of the date of grant. Exercisability of
options accelerates in certain events, including death, disability, retirement
and a change in control of the Company. The exercisability of options is
contingent upon continued service except that options exercisable on the date of
termination of employment may be exercised thereafter under certain conditions.
No options were exercised by the Named Executive Officers in 1998. The following
table shows the value, on December 31, 1998, of the unexercised options held by
the Named Executive Officers.
SHARE OPTION EXERCISES IN 1998 AND YEAR-END 1998 SHARE OPTION VALUES
Unexercised Options held on Value of Unexercised in-the-Money
Securities December 31, 1998 Options on December 31, 1998
Acquired Aggregate Value ----------------------------- ---------------------------------
Name on Exercise Realized ($) Exercisable Unexercisable Exercisable Unexercisable
---- ----------- ------------ ----------- ------------- ----------- -------------
Stanley A. Milner - - 143,333 21,667 $80,200 -
Stephen C. Hurley - - 83,333 46,667 - -
Edward L. Hahn - - 30,833 6,667 9,700 -
Esther S. Ondrack - - 87,500 15,000 39,200 -
Ronald J. Stefure - - 36,666 3,334 7,500 -
CHANGE IN CONTROL AGREEMENTS
The Company has agreements with certain employees, including the Named Executive
Officers, that require that if, under certain circumstances, following a change
in control of the Company, employment is terminated, the employee will receive a
severance payment equal to two times the employee's average annual base salary
during the previous three years and certain benefits for a two year period
following termination of employment.
COMPENSATION COMMITTEE REPORT
The Compensation Committee of the Board of Directors is responsible for
reviewing compensation policies and practices of the Company, both generally and
in specific relation to the appointment and compensation of the officers and
certain members of senior management. The Compensation Committee makes
recommendations to the Board of Directors with respect thereto and with respect
to benefit plans including the Share Option Plan and grants thereunder.
Compensation of the Company's employees, including officers and senior
management, is comprised of salary, periodic bonuses for outstanding effort and
results, various benefit plans, including a retirement plan and a savings plan
and stock options. Compensation plans are designed to provide competitive levels
of compensation which will attract and retain competent, motivated personnel who
will perform to their potential to increase the value of the Company for the
benefit of the shareholders.
Salaries are reviewed annually in relation to the achievement of both corporate
and individual performance objectives and with a view to achieving and
maintaining external competitiveness and internal equity. Grants are made under
the Share Option Plan in the discretion of the Board of Directors on the advice
of the Compensation Committee and vary as to timing and amount with the
responsibilities and performance of the individual.
The compensation of the President and Chief Executive Officer of the Company,
Mr. Stanley A. Milner, is comprised of the same components and is determined in
the same manner as that of the other executive officers.
Submitted on behalf of the Compensation Committee: Stuart T. Peeler, Chairman John E. Maybin
Hugh J. Kelly David E. Mitchell
The Board of Directors has accepted all recommendations of the Compensation
Committee.
6
50
PERFORMANCE GRAPHS(1)
The graphs which follow assume that C$100 was invested on April 30, 1989, when
the Company commenced operations, in the Company's common shares and in The
Toronto Stock Exchange (TSE) Oil and Gas Producers Index; and on December 31,
1993 in the Company's common shares, the TSE Oil and Gas Producers Index and the
TSE 300 Composite Index.
Cumulative Value of C$100 Invested on April 30, 1989
[GRAPH]
Apr. 30 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31
1989 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998
------- ------- ------- ------- ------- ------- ------- ------- ------- ------- -------
CII Cdn.$ 100 144 137 101 137 135 91 149 224 189 143
TSE O&GP 100 113 102 87 93 129 117 136 187 167 117
Cumulative Value of C$100 Invested on December 31, 1993
[GRAPH]
Dec. 31, 1993 Dec. 31, 1994 Dec. 31, 1995 Dec. 31, 1996 Dec. 31, 1997 Dec 31, 1998
------------- ------------- ------------- ------------- ------------- ------------
CII Cdn. $ 100 67 110 166 140 106
TSE O&GP 100 91 105 145 130 90
TSE 300 100 100 114 147 169 166
(1) Reinvestment of dividends is assumed in all cases. The graphs were plotted
using the data shown below each graph.
7
51
The following graphs assume that US$100 was invested on April 30, 1989, when the
Company commenced operations, in the Company's common shares and in the American
Stock Exchange ("AMEX") Natural Resources Index and on December 31, 1993 in the
Company's common shares, the AMEX Natural Resources Index and the AMEX Market
Value Index. The AMEX Natural Resources Index was reconfigured effective
December 31, 1995.
Cumulative Value of US$100 Invested on April 30, 1989
[GRAPH]
Apr. 30 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31 Dec. 31
1989 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998
------- ------- ------- ------- ------- ------- ------- ------- ------- ------- -------
CII US$ 100 150 140 105 129 122 75 131 193 157 106
AMEX Nat. Res 100 115 96 84 73 91 90 100 123 132 86
Cumulative Value of US$100 Invested on December 31, 1993
[GRAPH]
Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec 31,
1993 1994 1995 1996 1997 1998
-------- -------- -------- -------- -------- -------
CIIUS$ 00 61 108 158 129 87
AMEX Nat. Res. 100 99 100 123 132 86
Market Value Index 100 91 115 120 143 144
8
52
COMPENSATION OF DIRECTORS
With effect from January 1, 1998, each Director receives an annual retainer of
$25,000, which is paid in quarterly installments. Each non-executive Director is
also paid at the rate of $1,000 for each Board meeting and committee meeting
attended. In addition, the Chairman of the Board and the Chairman of each
committee receives a chairman's retainer in the amount of $4,000 per year, paid
in quarterly installments. Directors receive no compensation for the time
required to prepare for or travel to or from Board or committee meetings. The
Company reimburses reasonable out-of-pocket expenses incurred by Directors. On
May 14, 1998, each of the Directors was granted an option on 5,000 common shares
at the exercise price of $23.00 per share and on March 11, 1999, each of the
Directors was granted an option on 5,000 common shares at the exercise price of
$11.43 per share.
STATEMENT OF CORPORATE GOVERNANCE PRACTICES
The Company supports and complies with the corporate governance guidelines of
The Toronto Stock Exchange. The Company's Board of Directors participates
actively in strategic planning and in the identification and management of
business risks confronting the Company. Corporate objectives, budgets and
corporate authorities are reviewed and approved regularly. The Company's Board
and Board Committees have ongoing involvement in succession planning,
shareholder communications, internal control matters and management information
systems. The Board has a non-executive Chairman and is comprised of eight
members, five of whom are unrelated directors as defined by The Toronto Stock
Exchange.
APPOINTMENT OF AUDITORS
As set forth in the notice, action will be taken at the meeting to provide for
the appointment of auditors until the close of the next annual meeting. THE
PROXIES HEREBY SOLICITED WILL BE EXERCISED IN FAVOR OF THE APPOINTMENT OF
PRICEWATERHOUSECOOPERS LLP which firm and its predecessor, Price Waterhouse,
have been the Company's auditors since the Company's inception. A representative
of PricewaterhouseCoopers LLP is expected to be present at the meeting.
SHAREHOLDER RIGHTS PLAN
Shareholders are being asked to reconfirm the Shareholder Rights Plan (the
"Rights Plan") which was adopted by the Board of Directors and became effective
on February 23, 1994 and was confirmed by the shareholders on May 26, 1994.
Reconfirmation by the shareholders requires that a majority of the votes cast be
in favor thereof. THE PROXIES HEREBY SOLICITED WILL BE EXERCISED IN FAVOR OF THE
RECONFIRMATION OF THE SHAREHOLDER RIGHTS PLAN. The full text of the Rights Plan
is on the public record and, in addition, any shareholder may obtain a copy by
contacting the Secretary of the Company at its Edmonton office.
The following is a general summary of the terms of the Rights Plan. The summary
is qualified in its entirety by reference to the text of the Rights Plan.
The Rights Plan is designed to ensure that any individual or group seeking to
acquire control of Chieftain will do so in a manner which will allow the
shareholders and the Board of Directors sufficient time to assess the offer. THE
RIGHTS PLAN REQUIRES THAT ALL SHAREHOLDERS BE TREATED EQUITABLY, I.E. THAT ALL
SHAREHOLDERS BE OFFERED THE SAME CONSIDERATION FOR THEIR SHARES.
To comply with the Rights Plan:
(a) a bid must be made in writing for all shares to all shareholders;
(b) a bid must be open for at least 90 days;
(c) the bidder must not own more than 10% of the shares when it starts the bid
process;
(d) at least 50% of the shares held by shareholders independent of the bidder
must be deposited with the bidder before the bidder can purchase any of
such shares; and
(e) if the minimum number of shares, as in (d) above, are deposited, the bidder
must announce this and then leave the bid open for at least 10 more days.
9
53
If an individual or group acquires 25% or more of the shares other than by
complying with the Rights Plan, it becomes an "acquiring person" and the
shareholder rights are triggered. The Rights Plan gives shareholders rights to
buy shares if a bid is made that does not comply with the required bidding
procedures. Rights held by an "acquiring person" are not exercisable. Shares
owned by an investment manager or trust company in the normal course of its
business would not trigger the Plan.
A competing bid submitted during the term of the first bid will be required to
be outstanding only for the remaining part of the original 90-day period
(subject to the current statutory minimum of 21 days).
Securities laws require that the Board of Directors deliver to shareholders
within 10 days of a bid a written assessment of the bid. The shareholders
determine if a bid is acceptable by deciding whether or not to tender their
shares.
The Plan ensures that holders of convertible preferred shares will receive
rights as though they had converted their preferred shares into common shares.
The Plan will expire on February 22, 2004, 10 years after its effective date.
OTHER MATTERS
To the knowledge of the directors and management of the Company, there is no
business to be presented for action by the shareholders at the meeting to which
this Information Circular relates other than that mentioned herein or in the
Notice of Meeting.
The date by which shareholder proposals must be received by the Company for
inclusion in the information circular and proxy form relating to the 2000 annual
meeting is December 1, 1999.
ADDITIONAL INFORMATION
Copies of the Company's latest Annual Information Form and any documents
incorporated therein by reference; the Company's latest Annual Report on Form
10-K and any documents incorporated therein by reference; the Company's audited
Consolidated Financial Statements for the year ended December 31, 1998 and any
interim financial statements issued subsequent thereto, and this Information
Circular may be obtained from the Secretary of the Company at 1201 TD Tower,
10088 - 102 Avenue, Edmonton, Alberta, Canada, T5J 2Z1.
CERTIFICATE
The foregoing contains no untrue statement of a material fact and does not omit
to state a material fact that is required to be stated or that is necessary to
make a statement not misleading in light of the circumstances in which it was
made.
/s/ S. A. Milner /s/ E. L. Hahn
- ---------------------------------- ------------------------------------
S.A. Milner, A.O.E., LL.D. E.L. Hahn
President and Senior Vice President, Finance and
Chief Executive Officer Treasurer, Chief Financial Officer
Edmonton, Alberta
March 11, 1999
10
54
EXHIBIT 24(a)
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS
AND GEOLOGISTS
We hereby consent to the references to our firm and our report and to the use of
our report in the Annual Report of Chieftain International, Inc. on Form 10-K
for the fiscal year ended December 31, 1998, filed with the Securities and
Exchange Commission in Washington, D.C. pursuant to the Securities Exchange Act
of 1934.
NETHERLAND, SEWELL AND ASSOCIATES
INC.
By: /s/ Frederic D. Sewell
---------------------------------
Frederic D. Sewell
President
Dallas, Texas
March 11, 1999
55
EXHIBIT 24 (b)
CONSENT OF INDEPENDENT CHARTERED ACCOUNTANTS
We hereby consent to the inclusion in the Annual Report on Form 10-K of our
report dated February 4, 1999 on the consolidated financial statements of
Chieftain International, Inc. for the year ended December 31, 1998.
/s/ PricewaterhouseCoopers LLP
- ------------------------------
Chartered Accountants
Edmonton, Alberta, Canada
March 11, 1999