<PAGE>
FILED PURSUANT TO RULE 424(B)(2)
REGISTRATION NO. 333-88661
SUBJECT TO COMPLETION, DATED OCTOBER 21, 1999
PRELIMINARY PROSPECTUS SUPPLEMENT
TO PROSPECTUS DATED OCTOBER 20, 1999
THE INFORMATION CONTAINED IN THIS PROSPECTUS SUPPLEMENT IS NOT COMPLETE AND MAY
BE CHANGED. THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS ARE NOT
AN OFFER TO SELL THESE SECURITIES AND ARE NOT SOLICITING AN OFFER TO BUY THESE
SECURITIES IN ANY JURISDICTION WHERE THE OFFER OR SALE IS NOT PERMITTED.
2,500,000 SHARES
[LOGO]
CHIEFTAIN INTERNATIONAL, INC.
COMMON SHARES
$ PER SHARE
- --------------------------------------------------------------------------
Chieftain International, Inc. is offering 2,500,000 common shares. This is a
firm commitment underwriting.
Our common shares are listed on the American Stock Exchange and The Toronto
Stock Exchange under the symbol "CID." On October 20, 1999, the last reported
sales price of our common shares on the American Stock Exchange was U.S. $20.00
per share and on The Toronto Stock Exchange was Cdn. $29.50 per share.
INVESTING IN OUR COMMON SHARES INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE S-14
OF THIS PROSPECTUS SUPPLEMENT AND ON PAGE 6 OF THE ACCOMPANYING PROSPECTUS.
<TABLE>
<CAPTION>
PER SHARE TOTAL
-------------- --------------
<S> <C> <C>
Price to the public..................... $ $
Underwriting discount...................
Proceeds to Chieftain...................
</TABLE>
We have granted an over-allotment option to the underwriters. Under this option,
the underwriters may elect to purchase a maximum of 375,000 additional common
shares from us within 30 days following the date of this prospectus supplement
to cover over-allotments.
- --------------------------------------------------------------------------------
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS SUPPLEMENT OR THE ACCOMPANYING PROSPECTUS IS TRUTHFUL OR COMPLETE.
ANY REPRESENTATION TO THE CONTRARY IS A CRIMINAL OFFENSE.
CIBC WORLD MARKETS
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
A.G. EDWARDS & SONS, INC.
The date of this prospectus supplement is , 1999.
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
--------
<S> <C>
PROSPECTUS SUPPLEMENT
Prospectus Supplement Summary............................... S-5
Risk Factors................................................ S-14
Use of Proceeds............................................. S-16
Capitalization.............................................. S-17
Common Share Price Range and Dividend Policy................ S-18
Selected Consolidated Financial Data........................ S-19
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. S-21
Business and Properties..................................... S-27
Management.................................................. S-36
Certain Income Tax Considerations........................... S-39
Underwriting................................................ S-42
Legal Matters............................................... S-44
Experts..................................................... S-45
Transfer Agents and Registrars.............................. S-45
Index to Consolidated Financial Statements.................. F-1
</TABLE>
<TABLE>
<CAPTION>
PAGE
--------
<S> <C>
PROSPECTUS
About this Prospectus....................................... 3
Enforcement of Civil Liabilities............................ 3
Where You Can Find More Information......................... 3
Forward-Looking Statements.................................. 4
Chieftain................................................... 5
Risk Factors................................................ 6
Ratios of Earnings to Fixed Charges......................... 8
Use of Proceeds............................................. 9
Description of Share Capital................................ 9
Description of Debt Securities.............................. 14
Description of Warrants..................................... 19
Plan of Distribution........................................ 21
Legal Matters............................................... 22
Experts..................................................... 22
</TABLE>
S-3
<PAGE>
ABOUT THIS PROSPECTUS SUPPLEMENT
This document is in two parts. The first part is the prospectus supplement,
which describes our business and the specific terms of this offering. The second
part, the base prospectus, gives more general information, some of which may not
apply to this offering. Generally, when we refer only to the "prospectus," we
are referring to both parts combined.
IF THE DESCRIPTION OF THE OFFERING VARIES BETWEEN THE PROSPECTUS SUPPLEMENT AND
THE BASE PROSPECTUS, YOU SHOULD RELY ON THE INFORMATION IN THE PROSPECTUS
SUPPLEMENT.
----------------------------
CERTAIN DEFINITIONS AND OTHER INFORMATION
As used in this prospectus supplement and the accompanying prospectus, the terms
"Chieftain," "we," "us" and "our" refer to Chieftain International, Inc., a
company organized under the laws of the Province of Alberta, Canada, and its
subsidiaries (unless the context indicates a different meaning), and the term
"common shares" and "shares" means Chieftain's common shares, no par value.
Unless otherwise stated, all information contained in this prospectus supplement
and the accompanying prospectus assumes no exercise of the over-allotment option
granted to the underwriters.
As used in this prospectus supplement, "Bcf" means 1,000,000,000 cubic feet of
natural gas, "Bcfe" means 1,000,000,000 cubic feet of natural gas equivalent,
"MBbls" means 1,000 barrels of crude oil, condensate and natural gas liquids,
"Mcf" means 1,000 cubic feet of natural gas, "Mcfe" means 1,000 cubic feet of
natural gas equivalent using a ratio of 1 barrel = 6,000 cubic feet of natural
gas, "MMcf" means 1,000,000 cubic feet and "MMcfe" means 1,000,000 cubic feet of
natural gas equivalent.
All production numbers set forth in this prospectus supplement, whether amounts,
costs, revenues or otherwise, are reported net of royalties, unless otherwise
indicated.
Unless otherwise specified or the context otherwise requires, all dollar amounts
in this prospectus supplement and the prospectus are expressed in U.S. dollars.
Our principal executive offices are located at 1201 TD Tower, 10088-102 Avenue,
Edmonton, Alberta, Canada T5J 2Z1 and our telephone number is (780) 425-1950.
----------------------------
THE COMMON SHARES HAVE NOT BEEN AND WILL NOT BE QUALIFIED FOR PUBLIC
DISTRIBUTION UNDER THE SECURITIES LAWS OF CANADA OR ANY PROVINCE OR TERRITORY IN
CANADA. THE COMMON SHARES ARE NOT BEING AND MAY NOT BE, OFFERED OR SOLD,
DIRECTLY OR INDIRECTLY, IN CANADA IN VIOLATION OF THE SECURITIES LAWS OF CANADA
OR ANY PROVINCE OR TERRITORY OF CANADA.
S-4
<PAGE>
PROSPECTUS SUPPLEMENT SUMMARY
THIS PROSPECTUS SUPPLEMENT SUMMARY HIGHLIGHTS SELECTED INFORMATION FROM THIS
PROSPECTUS SUPPLEMENT BUT MAY NOT CONTAIN ALL OF THE INFORMATION THAT IS
IMPORTANT TO YOU. THIS PROSPECTUS SUPPLEMENT INCLUDES SPECIFIC TERMS OF THE
OFFERING OF OUR COMMON SHARES, INFORMATION ABOUT OUR BUSINESS AND FINANCIAL
DATA. WE ENCOURAGE YOU TO READ THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING
PROSPECTUS, INCLUDING THE "RISK FACTORS" SECTIONS IN BOTH OF THESE DOCUMENTS,
AND THE DOCUMENTS WE INCORPORATE BY REFERENCE, BEFORE MAKING AN INVESTMENT
DECISION.
THE COMPANY
Chieftain International, Inc. is an independent energy company engaged in the
exploration, development and production of natural gas and oil. Our producing
properties and exploration acreage are primarily located in the shallow waters
of the U.S. Gulf of Mexico. We also have properties located onshore in
Louisiana, in the Four Corners area of southeast Utah and in the U.K. sector of
the North Sea.
We have assembled a large natural gas and oil lease acreage position in the Gulf
of Mexico. Our lease interests in the Gulf of Mexico include a balanced
portfolio of exploration and development drilling prospects. These prospects
range from high-impact prospects with relatively greater risks, which we believe
have the potential to add substantially to our reserves, to relatively lower
risk development and exploitation projects with lower reserve potential. Our
exploration efforts are supported by an extensive 3-D seismic database covering
most of our leases. We believe that our seismic database and related
technological expertise have contributed to our successful exploration and
development track record. We believe our conservative capital structure provides
us with the financial flexibility to take advantage of our prospects and other
opportunities, including acquisitons of leasehold acreage and producing
properties.
We hold interests in 133 lease blocks located on the continental shelf of the
Gulf of Mexico. We also have interests in ten deep-water blocks. Of these lease
blocks, 94 are held as exploratory acreage and 49 are held by production. We
operate 38 of these blocks. Our average working interest in our Gulf of Mexico
leases is approximately 40%. In the third quarter of 1999, we had net production
of 75.9 MMcfe per day in the Gulf of Mexico, which represented approximately 77%
of our total production.
In addition to our Gulf of Mexico properties, we own various interests in two
large light oil producing units in the Four Corners area of southeast Utah where
we had net production of 1,774 barrels per day in the third quarter of 1999. We
own an interest in approximately 9,600 net acres in the U.K sector of the North
Sea where we had net production of 10.5 MMcfe per day in the third quarter of
1999. We are also active in exploratory activities onshore in Louisiana.
At December 31, 1998, we had estimated proved reserves of 207.9 Bcfe. These
reserves had a present value of net cash flows before income taxes, discounted
at 10%, of $152.5 million using constant natural gas and oil prices in effect on
December 31, 1998, which averaged $2.12 per Mcf for natural gas and $9.72 per
barrel for oil. If our realized natural gas and oil prices in effect at
September 30, 1999 were used in this determination, assuming no other changes,
our estimated proved reserves at December 31, 1998, would have increased to
222.7 Bcfe and the present value of net cash flows before income taxes,
discounted at 10%, would have increased to $279.0 million. Our average realized
prices for our production at September 30, 1999 were $2.58 per Mcf for natural
gas and $20.16 per barrel for oil. At December 31, 1998, approximately 62% of
our proved reserves were natural gas and approximately 70% of our proved
reserves were developed. Our total proved reserves at December 31, 1998 had a
reserves-to-production ratio of approximately 6.8 years.
S-5
<PAGE>
We have experienced substantial growth in proved reserves, production, revenue
and cash flow as demonstrated by the following:
- Since 1994, our overall drilling success rate has been 74% and our drilling
success rate for exploratory wells has been 40%. For the nine months ended
September 30, 1999, our overall drilling success rate was 73% and our
drilling success rate for exploratory wells was 62%.
- Since 1994, we have added proved reserves of 235 Bcfe, of which 127 Bcfe has
been from drilling, 72 Bcfe has been from acquisitions and 36 Bcfe has been
from upward revisions of previous estimates.
- Since 1994, we have replaced 208% of our production.
- We have increased our average daily production 157% to 98.3 MMcfe per day in
the third quarter of 1999 from 38.2 MMcfe per day in 1994.
- We have increased our net production revenue 18% to $53.0 million for the
first nine months of 1999 from $44.9 million for the first nine months of
1998.
- We have increased our EBITDA 24% to $39.2 million for the first nine months
of 1999 from $31.6 million for the first nine months of 1998.
OUR STRENGTHS
We believe that our historical success and future performance are directly
related to the following combination of strengths:
- SUBSTANTIAL INVENTORY OF DRILLING PROJECTS IN THE GULF OF MEXICO. In the
Gulf of Mexico, we have generated an inventory of over 45 drilling locations,
of which 36 are exploratory. Substantially all of these locations have been
evaluated and defined using 3-D seismic data. Our large inventory permits us
to be flexible in project selection and in the timing of drilling. By
identifying new exploration targets and acquiring additional acreage, we
continually add to our drilling inventory.
- PROVEN EXPLORATORY EXPERTISE. Our ability to define and participate in
successful exploratory prospects in the Gulf of Mexico is demonstrated by our
exploratory drilling success rate in the Gulf of Mexico of 88% over the nine
months ended September 30, 1999.
- EXPERIENCED TECHNICAL TEAM. Our technical team is comprised of highly
respected industry professionals with an average of 22 years of industry
experience. We believe our exploration success is a direct result of this
team's engineering and technical analyses.
- FINANCIAL FLEXIBILITY. With the net proceeds of this offering, we will have
the ability to repay all or substantially all of our outstanding
indebtedness, resulting in approximately $100 million of availability under
our revolving credit facility. We seek to maintain low levels of debt in
order to respond quickly to drilling or acquisition opportunities.
OUR STRATEGY
Our strategy is to increase our reserves, production, revenue and cash flow
through exploration and development drilling and through the acquisition of
leasehold acreage and producing properties. The elements of our strategy include
the following:
- FOCUS ON THE GULF OF MEXICO. We focus our operations on the Gulf of Mexico
where we have acquired a significant exploration acreage position and
assembled a substantial 3-D seismic database. We believe this region combines
significant geological potential, reservoir size, quality
S-6
<PAGE>
and deliverability with favorable commodity pricing and attractive finding,
development and operating costs.
- GROW THROUGH EXPLORATION. We are pursuing an active technology-driven
exploration program that is designed to balance projects with lower risk and
moderate potential with drilling prospects which have higher risk and
substantial potential. We generate exploration prospects through geological
and geophysical analysis of 3-D seismic and other data and also review
prospects generated by others. Currently, we have budgeted approximately
$18.6 million for exploration and development capital expenditures for the
fourth quarter of 1999 and we expect to use $14.9 million of this amount for
exploration activities. We are currently drilling or plan to drill
approximately 15 exploratory and development wells in the Gulf of Mexico and
in the Gulf Coast area during the fourth quarter of 1999. We have budgeted
approximately $86.2 million for exploration and development capital
expenditures for 2000, $50.0 million of which we expect to use for
exploration activities.
- MANAGE DRILLING RISKS THROUGH JOINT VENTURES AND THE USE OF ADVANCED
TECHNOLOGIES. We seek to limit our financial and operating risks in selected
projects by participating in drilling with industry partners and operators.
We believe this strategy limits our risk exposure in high potential
prospects. Additionally, we have increasingly relied on advanced
technologies, including 3-D seismic analysis, to define geologic risks,
thereby enhancing the results of our drilling efforts. We also seek to
operate our projects in order to better control drilling costs and the timing
of drilling.
- EVALUATE AND PURSUE STRATEGIC ACQUISITIONS. We continually review
opportunities to acquire leasehold acreage and producing properties. We seek
to acquire properties that we believe have significant exploration potential
and to increase our working interest in producing lease blocks when available
to us on economically favorable terms.
RECENT DRILLING ACTIVITIES
HIGH ISLAND. In August 1999, we announced that our exploratory well on High
Island Blocks A-510/A-531, located offshore Texas in the Gulf of Mexico,
resulted in an oil and natural gas discovery. This well was drilled to a total
depth of 11,107 feet and encountered more than 260 net feet of
hydrocarbon-bearing pay in multiple zones. We are now drilling an additional
well on Block A-510 and will then design and install production facilities. We
operate, and have a 50% working interest in, this project.
NORTHEAST WRIGHT FIELD. The Broussard No. 1 well located onshore in south
Louisiana in Vermilion Parish was drilled to a measured depth of 18,340 feet in
early October 1999 and production liner has been run to total depth. This well
encountered a significant accumulation of natural gas-bearing high quality
reservoir rock. It was drilled as a delineation well to confirm and extend
natural gas reserves discovered in the D. W. Guidry No. 1 well located
approximately one mile to the north. Completion procedures are in progress and
we expect production from the Broussard No. 1 well to commence during the fourth
quarter of 1999. Production facilities and flow lines in the field are being
expanded to accommodate increased production volumes and additional drilling is
planned to fully develop the field. We own a 50% interest in the Broussard
No. 1 well and 3,100 acres in the Northeast Wright Field.
VERMILION 267. We have a 60% working interest in the Vermilion 267 No. 1
natural gas discovery well located offshore Louisiana in the Gulf of Mexico.
This well reached a total depth of 13,370 feet in early October 1999 and
encountered 52 feet of high quality net effective hydrocarbon-bearing reservoir
rock. This well has been cased for production and the design of production
facilities is in progress. Additional exploratory and development drilling is
planned to fully develop the block.
S-7
<PAGE>
RECENT OPERATING RESULTS
Operating results for the three months ended September 30, 1999 reflect
increases in production volumes and prices for both natural gas and oil compared
with the third quarter of 1998. Our average daily production of natural gas and
oil increased 29% to 98 MMcfe (118 MMcfe before royalties) for the third quarter
of 1999 from 76 MMcfe (94 MMcfe before royalties) for the third quarter of 1998.
Average natural gas prices that we received increased 15% to $2.26 per Mcf for
the third quarter of 1999 from $1.96 per Mcf for the third quarter of 1998.
Average oil prices that we received increased 63% to $19.31 per barrel for the
third quarter of 1999 from $11.86 per barrel for the third quarter of 1998.
Total revenue increased 63% to $22.8 million for the third quarter of 1999 from
$13.9 million for the third quarter of 1998. Higher production, coupled with
higher natural gas and oil prices, resulted in cash flow from operations of
$16.3 million for the third quarter of 1999, compared to $7.3 million for the
third quarter of 1998, and net income of $1.3 million for the third quarter of
1999 compared to a loss of $2.5 million for the third quarter of 1998.
S-8
<PAGE>
THE OFFERING
<TABLE>
<S> <C>
Common shares offered........................ 2,500,000 shares
Common shares to be outstanding after the
offering................................... 15,849,059 shares
Use of proceeds.............................. To fund the development of our existing
reserves, to increase our exploration program
and possibly to acquire oil and natural gas
properties. Until funds are required for such
purposes, the proceeds may be used to repay
bank indebtedness or may be invested in
short-term money market instruments. See "Use
of Proceeds."
American Stock Exchange and The Toronto Stock
Exchange symbol............................ CID
</TABLE>
The number of outstanding shares shown above is based on 13,349,059 outstanding
shares at September 30, 1999 and excludes:
- up to 375,000 shares that may be sold to the underwriters upon exercise of
their over-allotment option;
- 1,123,189 shares that may be issued pursuant to share options outstanding as
of September 30, 1999; and
- up to 3,408,375 shares reserved for issuance upon conversion of our
subsidiary's $1.8125 cumulative redeemable preferred shares.
S-9
<PAGE>
SUMMARY CONSOLIDATED FINANCIAL INFORMATION
The summary consolidated financial information below has been derived from our
audited consolidated financial statements for annual and year-end data, and from
our unaudited consolidated condensed financial statements for interim-period
data. Our financial statements are prepared using Canadian generally accepted
accounting principles. Our reporting currency is U.S. dollars. For a discussion
of the effect of the differences between Canadian and U.S. generally accepted
accounting principles, see footnote 2 to the table below, Note 11 to the audited
consolidated financial statements and Note 7 to the unaudited consolidated
condensed financial statements which are included elsewhere in this prospectus
supplement. The results of operations for the nine months ended September 30,
1999 should not be regarded as indicative of results for the full year.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
------------------- --------------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- -------- --------
(UNAUDITED)
(U.S. $ IN THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Production revenue...................... $ 64,236 $ 54,489 $ 74,861 $ 84,219 $ 72,838 $ 31,733 $ 35,960
Less: royalties....................... 11,282 9,637 13,246 14,592 12,226 5,058 5,841
-------- -------- -------- -------- -------- -------- --------
Production revenue, net of royalties.... 52,954 44,852 61,615 69,627 60,612 26,675 30,119
Interest income and other............... 570 2,613(1) 2,776(1) 2,428 2,487 4,396 4,757
-------- -------- -------- -------- -------- -------- --------
Total................................. 53,524 47,465 64,391 72,055 63,099 31,071 34,876
Costs and expenses:
Production costs........................ 10,985 12,219 16,355 13,325 12,220 9,563 8,839
General and administrative expenses..... 3,354 3,668 4,796 4,308 3,972 3,346 3,402
Interest................................ 1,867 285 437 -- -- -- --
Depletion and amortization(2)........... 38,711 30,096 42,081 36,951 30,920 18,779 21,527
Additional depletion(2)(3).............. 11,393 -- 6,244 -- -- -- 15,434
-------- -------- -------- -------- -------- -------- --------
Total................................. 66,310 46,268 69,913 54,584 47,112 31,688 49,202
-------- -------- -------- -------- -------- -------- --------
Income (loss) before income taxes and
dividends on preferred shares of a
subsidiary(4)........................... (12,786) 1,197 (5,522) 17,471 15,987 (617) (14,326)
Provision (benefit) for income taxes
Current................................. 8 27 14 7 124 34 46
Deferred................................ (5,416) 1,114 (1,423) 7,304 6,079 124 (4,844)
-------- -------- -------- -------- -------- -------- --------
Total................................. (5,408) 1,141 (1,409) 7,311 6,203 158 (4,798)
-------- -------- -------- -------- -------- -------- --------
Income (loss) before dividends on
preferred shares of a subsidiary........ (7,378) 56 (4,113) 10,160 9,784 (775) (9,528)
Dividends on preferred shares of a
subsidiary(4)........................... 3,707 3,707 4,942 4,942 4,942 4,942 4,942
-------- -------- -------- -------- -------- -------- --------
Income (loss) applicable to common
shares(2)............................... $(11,085) $ (3,651) $ (9,055) $ 5,218 $ 4,842 $ (5,717) $(14,470)
======== ======== ======== ======== ======== ======== ========
Earnings (loss) per common share basic and
fully diluted(2)........................ $ (0.83) $ (0.27) $ (0.67) $ 0.38 $ 0.37 $ (0.54) $ (1.32)
======== ======== ======== ======== ======== ======== ========
Weighted average number of common shares
outstanding (000's)..................... 13,350 13,521 13,480 13,621 13,065 10,633 10,986
======== ======== ======== ======== ======== ======== ========
OTHER FINANCIAL DATA:
EBITDA(5)................................. $ 39,185 $ 31,578 $ 43,240 $ 54,422 $ 46,907 $ 18,162 $ 22,635
Cash flow from operations................. 33,603 27,559 37,847 49,473 41,841 13,186 17,647
Net natural gas and oil capital
expenditures............................ 36,187 66,198 92,573 69,453 57,673 100,502 28,059
BALANCE SHEET DATA (AT END OF PERIOD):
Working capital........................... $ 4,709 $ 4,032 $ 2,392 $ 22,676 $ 42,854 $ 11,216 $103,225
Total assets(2)........................... 307,863 300,281 318,584 285,125 267,442 204,555 211,032
Long-term debt............................ 45,000 25,000 40,000 -- -- -- --
Shareholders' equity(2)................... 223,789 240,898 234,946 249,466 244,122 190,534 200,754
</TABLE>
- ---------------------------
(1) Includes a $1.6 million court awarded claim for recovery of past years'
excess transportation charges.
S-10
<PAGE>
(2) The use of U.S. generally accepted accounting principles results in the
following:
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
------------------- ----------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- -------- --------
(UNAUDITED)
(U.S. $ IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
Depletion and amortization................. $ 25,589 $ 27,465 $ 37,846 $ 33,774 $ 28,539 $ 16,004 $ 17,691
Additional depletion*...................... 18,497 24,725 95,397 -- -- 6,740 18,245
Net income (loss) applicable to
common shares............................ (6,723) (18,296) (63,963) 7,510 6,202 (7,862) (13,710)
Net income (loss) per common share:
Basic.................................... (0.50) (1.35) (4.75) 0.55 0.47 (0.74) (1.25)
Fully diluted............................ (0.50) (1.35) (4.75) 0.54 0.46 (0.74) (1.25)
Total assets............................... 232,022 261,500 238,675 269,178 245,763 186,682 195,136
Shareholders' equity....................... 98,523 151,533 105,318 174,746 167,110 112,162 124,527
</TABLE>
- ---------------------------
* These amounts reflect non-cash write-downs in accordance with full cost
accounting rules under U.S. generally accepted accounting principles.
(3) These amounts reflect non-cash write-downs of the carrying value of natural
gas and oil properties in accordance with full cost accounting rules under
Canadian generally accepted accounting principles. A write-down of U.S.
property carrying costs, at December 31, 1998, of $16.5 million would have
been required had December 31, 1998 prices ($2.15 per Mcf and $9.72 per
barrel) been used. A write-down of U.S. property carrying costs at
December 31, 1994 of $16.8 million would have been required had
December 31, 1994 prices ($1.62 per Mcf for natural gas and $16.50 per
barrel for oil and natural gas liquids) been used.
(4) In 1992, our subsidiary, Chieftain International Funding Corp., sold
2,726,700 of its $1.8125 cumulative convertible redeemable preferred shares
at $25.00 per share. The preferred shares are redeemable, at the option of
the subsidiary, and are convertible at any time into 1.25 common shares of
Chieftain at the option of the holder.
(5) EBITDA represents income before interest expense, income taxes, depletion
and amortization (including all amounts for additional depletion) and
dividends paid on preferred shares of a subsidiary. We have reported EBITDA
because we believe EBITDA is a measure commonly reported and widely used by
investors as an indicator of a company's operating performance and ability
to incur and service debt. We believe EBITDA assists investors in comparing
a company's performance on a consistent basis without regard to depletion
and amortization, which can vary significantly depending upon accounting
methods or nonoperating factors such as historical cost. EBITDA is not a
calculation based on Canadian or U.S. generally accepted accounting
principles and should not be considered an alternative to net income in
measuring our performance or used as an exclusive measure of cash flow
because it does not consider the impact of working capital growth, capital
expenditures, debt principal reductions and other sources and uses of cash
which are disclosed in our Consolidated Statement of Changes in Financial
Position and Consolidated Condensed Statement of Cash Flows. Investors
should carefully consider the specific items included in our computation of
EBITDA. While EBITDA has been disclosed herein to permit a more complete
comparative analysis of our operating performance and debt servicing ability
relative to other companies, investors should be cautioned that EBITDA as
reported by us may not be comparable in all instances to EBITDA as reported
by other companies. EBITDA amounts may not be fully available for
management's discretionary use, due to certain requirements to conserve
funds for capital expenditures, debt service and other commitments.
S-11
<PAGE>
SUMMARY RESERVES AND PRODUCTION DATA
The following tables set forth certain summary information with respect to
estimates of our oil and natural gas reserves and data about production and
sales of oil and natural gas for the periods indicated. Our estimates of U.S.
oil and natural gas reserves, the future net revenues therefrom and their
discounted present value at a rate of 10%, or PV-10 Value, have been prepared by
Netherland, Sewell & Associates, Inc., independent petroleum engineers. Such
information regarding U.K. reserves has been prepared by our personnel. U.K.
reserves comprise 5% of our total reserves on a Bcfe basis. See "Risk Factors"
in this prospectus supplement and in the accompanying prospectus and "Business
and Properties."
<TABLE>
<CAPTION>
AS AT DECEMBER 31,
--------------------------------------------------------
<S> <C> <C> <C> <C> <C>
1998 1997 1996 1995 1994
-------- -------- -------- -------- -------
ESTIMATED PROVED OIL AND NATURAL GAS RESERVES(1):
Net natural gas reserves (MMcf):
Proved developed.................................... 99,432 89,139 86,997 85,705 33,581
Proved undeveloped.................................. 29,641 35,958 39,804 40,986 25,155
-------- -------- -------- -------- -------
Total............................................. 129,073 125,097 126,801 126,691 58,736
======== ======== ======== ======== =======
Net oil reserves (MBbls):
Proved developed.................................... 7,534 8,397 8,397 7,509 5,588
Proved undeveloped.................................. 5,600 2,916 907 943 797
-------- -------- -------- -------- -------
Total............................................. 13,134 11,313 9,304 8,452 6,385
======== ======== ======== ======== =======
Total proved oil and natural gas reserves
(MMcfe)(2).......................................... 207,877 192,975 182,625 177,403 97,046
======== ======== ======== ======== =======
ESTIMATED PRESENT VALUE OF PROVED RESERVES (U.S. $ IN
THOUSANDS):
Proved developed...................................... $135,867 $187,697 $218,961 $111,608 $43,595
Proved undeveloped.................................... 16,641 50,615 85,335 40,096 19,333
-------- -------- -------- -------- -------
Total PV-10 Value (before income taxes)............. $152,508(3) $238,312 $304,296 $151,704 $62,928
======== ======== ======== ======== =======
Standardized measure of discounted estimated future
net cash flows after income taxes(4).............. $152,508 $199,573 $239,023 $137,494 $60,374
======== ======== ======== ======== =======
PRICES USED IN CALCULATING END OF YEAR PROVED RESERVES:
U.S. natural gas reserves (per Mcf)................... $ 2.15 $ 2.74 $ 3.43 $ 2.06 $ 1.62
U.K. natural gas reserves (per Mcf)................... 1.74 1.76 2.04 0.86 2.25
Oil (per barrel)...................................... 9.72 16.69 24.03 18.48 16.50
OTHER RESERVE DATA(1):
Reserve replacement rate(5)........................... 136% 240% 278% 260% 83%
Natural gas as a percent of total proved
reserves(2)......................................... 62% 65% 69% 71% 61%
Proved developed reserves as a percent of total proved
reserves(2)......................................... 70% 72% 75% 74% 69%
</TABLE>
S-12
<PAGE>
<TABLE>
<CAPTION>
NINE
MONTHS
ENDED YEAR ENDED DECEMBER 31,
SEPTEMBER 30, ----------------------------------------------------
1999 1998 1997 1996 1995 1994
-------------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
NET AVERAGE DAILY SALES VOLUME:
Natural gas (MMcf per day).......................... 70.0 67.1 64.2 59.8 29.5 28.4
Oil and natural gas liquids (barrels per day)....... 3,995 3,012 2,261 2,005 1,643 1,631
Total production (MMcfe per day)(2)............... 93.9 85.2 77.8 71.8 39.3 38.2
WEIGHTED AVERAGE SALES PRICES:
Natural gas (per Mcf)............................... $ 1.89 $ 1.99 $ 2.33 $ 2.09 $ 1.54 $ 1.97
Oil and natural gas liquids (per barrel)............ 15.62 11.74 18.94 20.99 16.94 15.86
SELECTED DATA PER MCFE:
Production costs.................................... $ 0.43 $ 0.53 $ 0.47 $ 0.46 $ 0.67 $ 0.63
General and administrative expenses................. 0.13 0.15 0.15 0.15 0.23 0.24
</TABLE>
- ---------------------------
(1) All reserve quantities are shown net of royalties.
(2) Oil is converted into natural gas equivalents using a conversion ratio of 6
Mcf of natural gas to 1 barrel of oil.
(3) If our realized prices in effect at September 30, 1999, were used in this
determination, proved reserves would have increased to 222.7 Bcfe and PV-10
Value would have increased to $279.0 million.
(4) At December 31, 1998, no income taxes would be payable at these natural gas
and oil price levels.
(5) Calculated for a three-year period ending with the year presented by
dividing the increase in net reserves, including any revisions of those
reserves, by the production quantities for such period.
S-13
<PAGE>
RISK FACTORS
An investment in our common shares involves significant risks. You should
carefully consider the following risk factors and the information included under
"Risk Factors" in the accompanying prospectus before you decide to buy our
common shares. You should also carefully read and consider all of the
information we have included, or incorporated by reference, in this prospectus
supplement and the accompanying prospectus before you decide to buy our common
shares.
LOW OIL AND NATURAL GAS PRICES ADVERSELY AFFECT OUR FINANCIAL RESULTS AND
CONDITION.
Prices for oil and natural gas are volatile and declined significantly during
the second half of 1998 and early 1999. Natural gas prices affect us more than
oil prices as natural gas was 79% of our 1998 production and 74% of our
production in the first nine months of 1999. In 1998, natural gas prices we
received were 17% lower than in 1997 and oil prices were 38% lower. Primarily
because of lower prices, we recorded ceiling test write-downs in 1994 and in
1998. If prices declined from current levels, we would be negatively affected in
several ways:
- our cash flows would be reduced, decreasing funds available for capital
expenditures to replace reserves or increase production;
- certain reserves could no longer be economic to produce, which would lead to
lower reserves and cash flow;
- our lenders could elect not to extend our credit facility, limiting our
liquidity and possibly requiring mandatory loan repayments; and
- access to other sources of capital, such as equity or long-term debt markets,
could be severely limited or unavailable.
Consequently, our revenues and profitability would suffer. Most of the factors
which affect gas and oil prices are beyond our control, such as demand,
worldwide economic conditions, weather conditions, supply levels, import prices,
political conditions in major oil producing regions, especially the Middle East,
and actions taken by OPEC.
WE MAY INCUR ADDITIONAL WRITE-DOWNS OF THE CARRYING VALUES OF OUR PROPERTIES.
Accounting rules require that we review the carrying value of our oil and
natural gas properties on a periodic basis for possible write-down or
impairment. Under these rules, capitalized costs of proved reserves may not
exceed the value of estimated future net revenues from those proved reserves.
Primarily because of weak oil and natural gas prices, we recorded a
$1.1 million pre-tax ceiling limitation write-down for our U.K. properties in
1998 and we recorded a $9.8 million pre-tax ceiling limitation write-down for
our U.S. properties in 1994. Similarly, the failure to find economic reserves in
Libya and Peru led to a $5.1 million pre-tax impairment of our foreign
investments in Libya in 1998 and a further impairment of $11.4 million in 1999
and an impairment of $5.6 million in Peru in 1994. For a description of the
effect of the differences in ceiling limitation write-downs in the U.S. and
Canada, see Note 11 to the audited consolidated financial statements for the
year ended December 31, 1998 and Note 7 to the unaudited consolidated condensed
financial statements for the period ended September 30, 1999, included elsewhere
in this prospectus supplement.
We may be required to write-down the carrying value of our oil and natural gas
properties in the future if oil and natural gas prices are depressed for even a
short period of time, are unusually volatile or if we have substantial downward
revisions to our proved reserve quantities. Any such ceiling test write-down
would result in a charge to earnings and a reduction of shareholders' equity,
but would not
S-14
<PAGE>
impact our cash flow from operating activities. Once incurred, these write-downs
cannot be reversed at a later date.
Given that full cost accounting rules are applied on a country-by-country basis,
we are currently exposed to the risk of a possible write-down or impairment of
our properties in the U.K. At September 30, 1999, our investment in the U.K.
totaled $7.9 million. Natural gas prices in the U.K. have declined substantially
during the past two years and, barring substantial improvement in U.K. natural
gas prices, we could be required to make a further ceiling limitation write-down
in 1999.
WE RELY ON OUR SENIOR OFFICERS AND OTHER KEY EMPLOYEES.
We rely on key employees and their expertise. If we were to lose several of our
key technical employees or executive officers, our operations could suffer
during their successors' transition periods.
WE AND OUR SUPPLIERS OR PARTNERS MAY NOT BE YEAR 2000 COMPLIANT, WHICH COULD
RESULT IN DISRUPTION OF OUR OPERATIONS.
Actual effects of the Year 2000 issue are subject to uncertainties. Our Year
2000 program may not completely identify every potential problem that may arise.
Our inability to completely solve all potential problems or address all
potentially affected systems could materially hurt our business. Likewise, our
business suppliers and partners may experience unanticipated Year 2000 problems
which could in turn affect our operations. In addition, we have relied on
representations from third parties that our systems and the systems of third
parties with whom we conduct business are Year 2000 compliant. However, because
of the difficulty in anticipating all effects of the Year 2000 issue, these
representations are not guarantees. If there are Year 2000 related failures in
our critical systems or our business suppliers' and partners' critical systems
that create substantial or prolonged disruptions to our business, the adverse
impact on us could materially affect our financial condition or results of
operations. For a description of our Year 2000 program, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Year
2000 Disclosure."
INCREASED VOLATILITY OF OIL AND NATURAL GAS PRICES CAN CAUSE SUDDEN CHANGES IN
THE MARKET FOR OUR COMMON SHARES.
Our quarterly results of operations may fluctuate significantly as a result of
variations in oil and natural gas prices and production performance. In recent
years, oil and natural gas price volatility has become increasingly severe. You
can expect the market price of our common shares to decline when our quarterly
results decline or when announcements of adverse events regarding us or the
industry are made. Our common share price may decline to a price below the price
you paid to purchase your common shares in this offering.
S-15
<PAGE>
USE OF PROCEEDS
We estimate that the net proceeds from the sale of the common shares will be
approximately $ million, after deducting underwriting discounts and expenses,
or approximately $ million if the underwriters fully exercise their
over-allotment option.
The net proceeds will be used to fund the development of our existing reserves,
to increase our exploration program and may be used to acquire oil and natural
gas properties. Until funds are required for such purposes, the proceeds may be
used to repay bank indebtedness or may be invested in short-term money market
instruments. As of September 30, 1999, our revolving credit facility had an
outstanding balance of $45.0 million and its weighted average interest rate was
6.24%. Our credit facility matures June 29, 2000. If we apply the net proceeds
of this offering to reduce our bank debt, we will have repaid all or
substantially all of the outstanding balance under our credit facility,
resulting in a borrowing base of approximately $100.0 million.
S-16
<PAGE>
CAPITALIZATION
The following table sets forth as of September 30, 1999:
- our historical capitalization; and
- our capitalization as adjusted to show the receipt of the estimated net
proceeds from the sale of our common shares being sold in this offering and
the use of a portion of such proceeds to pay down bank borrowings.
This table should be read in conjunction with the consolidated financial
statements and the related notes thereto included elsewhere in this prospectus
supplement.
<TABLE>
<CAPTION>
AS OF SEPTEMBER 30, 1999
------------------------
AS ADJUSTED
FOR THIS
HISTORICAL OFFERING
---------- -----------
(U.S. $ IN THOUSANDS)
<S> <C> <C>
Cash and cash equivalents................................... $ 597 $
======== =========
Long term debt:
Bank borrowings........................................... $ 45,000 $
-------- ---------
Shareholders' equity:
Preferred shares of subsidiary, $1.00 par value,
10,000,000 shares authorized, 2,726,700
outstanding(1).......................................... 63,403 63,403
Common shares, no par value, unlimited shares authorized,
13,349,059 shares and 15,849,059 shares issued and
outstanding, respectively, as adjusted for the common
share offering.......................................... 189,010
Contributed surplus....................................... 26 26
Deficit................................................... (28,650) (28,650)
-------- ---------
Total shareholders' equity.............................. 223,789
-------- ---------
Total capitalization.................................... $268,789 $
======== =========
</TABLE>
- ---------------------
(1) In 1992, our subsidiary, Chieftain International Funding Corp., sold
2,726,700 of its $1.8125 cumulative convertible redeemable preferred shares
at $25.00 per share. The preferred shares are redeemable, at the option of
the subsidiary, and each preferred share is convertible at any time into
1.25 shares of our common shares at the option of the holder.
This table does not reflect:
- up to 375,000 shares that may be sold to the underwriters upon exercise of
their over-allotment option;
- 1,123,189 shares that may be issued pursuant to stock options outstanding as
of September 30, 1999; and
- up to 3,408,375 shares reserved for issuance upon conversion of the $1.8125
cumulative redeemable preferred shares issued by our subsidiary, Chieftain
International Funding Corp.
S-17
<PAGE>
COMMON SHARE PRICE RANGE AND DIVIDEND POLICY
Our common shares are traded on the American Stock Exchange and The Toronto
Stock Exchange under the symbol "CID." The following table sets forth the range
of high and low sale prices per share of our common shares as reported by the
American Stock Exchange and The Toronto Stock Exchange for the periods
indicated.
<TABLE>
<CAPTION>
AMERICAN STOCK EXCHANGE THE TORONTO STOCK EXCHANGE
------------------------------- -------------------------------
TRADING TRADING
HIGH LOW VOLUME HIGH LOW VOLUME
-------- -------- --------- -------- -------- ---------
(U.S.$) (CDN.$)
<S> <C> <C> <C> <C> <C> <C>
1997
First Quarter.................... $25.88 $18.63 3,286,000 $35.40 $26.00 581,442
Second Quarter................... 23.13 18.00 2,921,200 32.00 25.00 395,424
Third Quarter.................... 27.37 20.50 2,375,100 37.65 28.35 722,436
Fourth Quarter................... 28.13 20.13 2,492,900 38.50 29.00 302,748
1998
First Quarter.................... 24.75 17.94 2,383,200 30.35 25.60 524,607
Second Quarter................... 24.75 20.25 1,896,700 35.35 30.10 265,873
Third Quarter.................... 23.75 13.94 3,297,200 34.45 21.60 1,158,000
Fourth Quarter................... 20.25 14.38 2,212,500 30.70 22.75 1,065,825
1999
First Quarter.................... 15.50 9.56 3,702,800 23.00 14.50 911,056
Second Quarter................... 18.63 12.25 2,959,100 26.95 19.25 719,569
Third Quarter.................... 22.75 17.44 1,872,300 34.00 25.90 412,641
Fourth Quarter................... 20.06 17.00 817,300 29.50 24.80 143,325
(through October 20th)
</TABLE>
On October 20, 1999, the last sale price of our common shares was U.S. $20.00
per share as reported by the American Stock Exchange and Cdn. $29.50 per share
as reported by The Toronto Stock Exchange.
We have not paid cash dividends on our common shares in the past. Our current
policy, which is to pay no dividends on our common shares, is subject to
periodic review and may change depending on our earnings, financial condition
and capital requirements. Dividends may be paid on our common shares provided
that all dividends on the preferred shares of Chieftain International Funding
Corp. and on any preferred shares that we may issue have been paid. See
"Description of Share Capital" in the prospectus for more information.
S-18
<PAGE>
SELECTED CONSOLIDATED FINANCIAL DATA
The selected consolidated financial data as of and for each of the five years
ended December 31, 1998 has been derived from our audited consolidated financial
statements. The selected consolidated financial data as of and for each of the
nine month periods ended September 30, 1999 and 1998 has been derived from our
unaudited consolidated condensed financial statements. In the opinion of our
management, the selected consolidated financial data as of and for each of the
nine month periods ended September 30, 1999 and 1998 include all normal
recurring adjustments necessary to present this information fairly. Our
financial statements are prepared using Canadian generally accepted accounting
principles. Our reporting currency is U.S. dollars. For a discussion of the
effect of the differences between Canadian and U.S. generally accepted
accounting principles, see Note 11 to the audited consolidated financial
statements and Note 7 to the unaudited consolidated condensed financial
statements which are included elsewhere in this prospectus supplement, and
footnote 2 below. The results of operations for the nine month periods ended
September 30, 1999 should not be regarded as indicative of results for the full
year.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
--------------------- ---------------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- ---------- ---------- -------- --------- -------- --------
(UNAUDITED)
(U.S. $ IN THOUSANDS, EXCEPT SHARES AND PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenues:
Production revenue........... $ 64,236 $ 54,489 $ 74,861 $ 84,219 $ 72,838 $ 31,733 $ 35,960
Less: royalties............ 11,282 9,637 13,246 14,592 12,226 5,058 5,841
-------- ---------- ---------- -------- --------- -------- --------
Production revenue, net of
royalties.................. 52,954 44,852 61,615 69,627 60,612 26,675 30,119
Interest income and other.... 570 2,613 (1) 2,776 (1) 2,428 2,487 4,396 4,757
-------- ---------- ---------- -------- --------- -------- --------
Total...................... 53,524 47,465 64,391 72,055 63,099 31,071 34,876
Costs and expenses:
Production costs............. 10,985 12,219 16,355 13,325 12,220 9,563 8,839
General and administrative
expenses................... 3,354 3,668 4,796 4,308 3,972 3,346 3,402
Interest..................... 1,867 285 437 -- -- -- --
Depletion and
amortization(2)............ 38,711 30,096 42,081 36,951 30,920 18,779 21,527
Additional depletion(2)(3)... 11,393 -- 6,244 -- -- -- 15,434
-------- ---------- ---------- -------- --------- -------- --------
Total...................... 66,310 46,268 69,913 54,584 47,112 31,688 49,202
-------- ---------- ---------- -------- --------- -------- --------
Income (loss) before income
taxes and dividends on
preferred shares of a
subsidiary(4)................ (12,786) 1,197 (5,522) 17,471 15,987 (617) (14,326)
Provision (benefit) for income
taxes
Current...................... 8 27 14 7 124 34 46
Deferred..................... (5,416) 1,114 (1,423) 7,304 6,079 124 (4,844)
-------- ---------- ---------- -------- --------- -------- --------
Total...................... (5,408) 1,141 (1,409) 7,311 6,203 158 (4,798)
-------- ---------- ---------- -------- --------- -------- --------
Income (loss) before dividends
on preferred shares of a
subsidiary................... (7,378) 56 (4,113) 10,160 9,784 (775) (9,528)
Dividends on preferred shares
of a subsidiary(4)........... 3,707 3,707 4,942 4,942 4,942 4,942 4,942
-------- ---------- ---------- -------- --------- -------- --------
Income (loss) applicable to
common shares(2)............. $(11,085) $ (3,651) $ (9,055) $ 5,218 $ 4,842 $ (5,717) $(14,470)
======== ========== ========== ======== ========= ======== ========
Earnings (loss) per common
share:
Basic and fully diluted(2)... $ (0.83) $ (0.27) $ (0.67) $ 0.38 $ 0.37 $ (0.54) $ (1.32)
======== ========== ========== ======== ========= ======== ========
Weighted average number of
common shares
outstanding (000's).......... 13,350 13,521 13,480 13,621 13,065 10,633 10,986
======== ========== ========== ======== ========= ======== ========
</TABLE>
S-19
<PAGE>
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
--------------------- ---------------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- ---------- ---------- -------- --------- -------- --------
(UNAUDITED)
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C> <C>
OTHER FINANCIAL DATA:
EBITDA(5)...................... $ 39,185 $ 31,578 $ 43,240 $ 54,422 $ 46,907 $ 18,162 $ 22,635
Cash flow from operations...... 33,603 27,559 37,847 49,473 41,841 13,186 17,647
Net natural gas and oil
capital expenditures......... 36,187 66,198 92,573 69,453 57,673 100,502 28,059
BALANCE SHEET DATA (AT END OF
PERIOD):
Working capital................ $ 4,709 $ 4,032 $ 2,392 $ 22,676 $ 42,854 $ 11,216 $103,225
Total assets(2)................ 307,863 300,281 318,584 285,125 267,442 204,555 211,032
Long-term debt................. 45,000 25,000 40,000 -- -- -- --
Shareholders' equity(2)........ 223,789 240,898 234,946 249,466 244,122 190,534 200,754
</TABLE>
- ---------------------------
(1) Includes a $1.6 million court awarded claim for recovery of past years'
excess transportation charges.
(2) The use of U.S. generally accepted accounting principles results in the
following:
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
------------------- ----------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- -------- --------
(UNAUDITED)
(U.S. $ IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C> <C> <C> <C>
Depletion and amortization....... $ 25,589 $ 27,465 $ 37,846 $ 33,774 $ 28,539 $ 16,004 $ 17,691
Additional depletion*............ 18,497 24,725 95,397 -- -- 6,740 18,245
Net income (loss) applicable to
common shares.................. (6,723) (18,296) (63,963) 7,510 6,202 (7,862) (13,710)
Net income (loss) per common
share:
Basic.......................... (0.50) (1.35) (4.75) 0.55 0.47 (0.74) (1.25)
Fully diluted.................. (0.50) (1.35) (4.75) 0.54 0.46 (0.74) (1.25)
Total assets..................... 232,022 261,500 238,675 269,178 245,763 186,682 195,136
Shareholders' equity............. 98,523 151,533 105,318 174,746 167,110 112,162 124,527
</TABLE>
- ---------------------------
* These amounts reflect non-cash write-downs in accordance with full cost
accounting rules under U.S. generally accepted accounting principles.
(3) These amounts reflect non-cash write-downs of the carrying value of natural
gas and oil properties in accordance with full cost accounting rules under
Canadian generally accepted accounting principles. A write-down of U.S.
property carrying costs, at December 31, 1998, of $16.5 million would have
been required had December 31, 1998 prices, $2.15 per Mcf and $9.72 per
barrel, been used. A write-down of U.S. property carrying costs at
December 31, 1994, of $16.8 million would have been required had
December 31, 1994 prices, $1.62 per Mcf for natural gas and $16.50 per
barrel for oil and natural gas liquids, been used.
(4) In 1992, our subsidiary, Chieftain International Funding Corp., sold
2,726,700 of its $1.8125 cumulative convertible redeemable preferred shares
at $25.00 per share. The preferred shares are redeemable, at the option of
the subsidiary, and are convertible at any time into 1.25 common shares of
Chieftain at the option of the holder.
(5) EBITDA represents income before interest expense, income taxes, depletion
and amortization (including all amounts for additional depletion) and
dividends paid on preferred shares of a subsidiary. We have reported EBITDA
because we believe EBITDA is a measure commonly reported and widely used by
investors as an indicator of a company's operating performance and ability
to incur and service debt. We believe EBITDA assists investors in comparing
a company's performance on a consistent basis without regard to depletion
and amortization, which can vary significantly depending upon accounting
methods or nonoperating factors such as historical cost. EBITDA is not a
calculation based on Canadian or U.S. generally accepted accounting
principles and should not be considered an alternative to net income in
measuring our performance or used as an exclusive measure of cash flow
because it does not consider the impact of working capital growth, capital
expenditures, debt principal reductions and other sources and uses of cash
which are disclosed in our Consolidated Statement of Changes in Financial
Position and Consolidated Condensed Statement of Cash Flows. Investors
should carefully consider the specific items included in our computation of
EBITDA. While EBITDA has been disclosed herein to permit a more complete
comparative analysis of our operating performance and debt servicing ability
relative to other companies, investors should be cautioned that EBITDA as
reported by us may not be comparable in all instances to EBITDA as reported
by other companies. EBITDA amounts may not be fully available for
management's discretionary use, due to certain requirements to conserve
funds for capital expenditures, debt service and other commitments.
S-20
<PAGE>
MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL
CONDITION AND RESULTS OF OPERATIONS
You should read the following discussion and analysis in conjunction with our
audited consolidated financial statements and our unaudited consolidated
condensed financial statements included in this prospectus supplement. The
following information contains forward-looking statements. See "Forward-Looking
Statements" in the accompanying prospectus.
We produce and sell natural gas and oil acquired through exploration and
development or through the purchase of producing properties. Our properties are
located offshore in the United States Gulf of Mexico, onshore in Utah and
Louisiana and also in the U.K. sector of the North Sea. The majority of our
attention and resources is focused on the U.S. Gulf of Mexico area where we hold
interests in 143 offshore lease blocks.
Our financial statements and information are reported in U.S. dollars.
Substantially all of our revenues and a significant portion of our operating
expenses are realized or incurred in U.S. dollars.
Our financial statements are prepared based upon Canadian generally accepted
accounting principles. For a discussion of the effect of differences in
generally accepted accounting principles in Canada and the United States on our
financial statements, see Note 11 to our audited consolidated financial
statements and Note 7 to our unaudited consolidated condensed financial
statements which are included elsewhere in this prospectus supplement.
OPERATING RESULTS
FIRST NINE MONTHS 1999 COMPARED TO FIRST NINE MONTHS 1998
PRODUCTION AND PRICING. Our average daily combined natural gas and oil
production increased 15% to 93.9 MMcfe (113.7 MMcfe before royalties) for the
first nine months of 1999 from 81.4 MMcfe (98.6 MMcfe before royalties) for the
corresponding period in 1998. Natural gas comprised 74% of our production for
the first nine months of 1999 and 79% of our production for the corresponding
period in 1998. For the first nine months of 1999, our natural gas production
increased 9% to 19.1 Bcf (23.3 Bcf before royalties) compared to 17.5 Bcf (21.4
Bcf before royalties) for the corresponding period in 1998. For the first nine
months of 1999, our oil and natural gas liquids production increased 38% to
1,091 MBbls (1,285 MBbls before royalties) compared to 792 MBbls (912 MBbls
before royalties) for the corresponding period in 1998. Natural gas prices
averaged $1.89 per Mcf for the first nine months of 1999 compared to $2.02 per
Mcf for the corresponding period in 1998. Oil and natural gas liquids prices
averaged $15.62 per barrel for the first nine months of 1999 compared to $12.39
per barrel for the corresponding period in 1998.
PRODUCTION REVENUES. For the first nine months of 1999, our combined natural
gas and oil production volumes increased 15% from the corresponding period in
1998. A 26% recovery in oil prices was partially offset by a 6% decrease in
natural gas prices. As a result, our production revenues for the first nine
months of 1999 increased 18% ($8.1 million) to $53.0 million from the
corresponding period in 1998.
Eighty-four percent of our natural gas production for the first nine months of
1999 resulted from our interests in 92 wells in the Gulf of Mexico. Our natural
gas production increased 9% in the first nine months of 1999 over the
corresponding period in 1998. This increase in production resulted primarily
from the commencement of production from South Marsh Island 39 at the end of the
first quarter of 1999 and from the commencement of initial natural gas
production from Main Pass 250 B during the latter half of the second quarter of
1999. We expect to add production in the fourth quarter of 1999
S-21
<PAGE>
from a discovery made at South Marsh Island 39 during the third quarter of 1999
and from Main Pass 225 D.
At September 30, 1999, we were producing 68.6 MMcf per day of natural gas (82.9
MMcf per day before royalties), of which 57.9 MMcf per day (72.2 MMcf per day
before royalties) was from the U.S. and 10.7 MMcf per day (before and after
royalties) was from the North Sea. At September 30, 1999, oil production was
4,301 barrels per day (5,089 barrels per day before royalties) of which 1,770
barrels per day (2,027 barrels per day before royalties) was from the Aneth and
Ratherford Units in Utah and 2,493 barrels per day (3,022 barrels per day before
royalties) was from the Gulf of Mexico.
PRODUCTION COSTS. Our production costs for the first nine months of 1999
decreased 10% from the corresponding period in 1998. This decrease primarily
reflects significant pipeline repair costs in the South Pass area during the
first quarter of 1998 and a succession of weather induced evacuations of manned
facilities in the Gulf of Mexico in the third quarter of 1998. Production costs
on a per unit basis decreased to $0.43 per Mcfe ($0.35 per Mcfe before
royalties), down 22% from the first nine months' average for 1998 of $0.55 per
Mcfe ($0.45 per Mcfe before royalties).
For the first nine months of 1999, production costs were $0.30 per Mcfe ($0.24
per Mcfe before royalties) for Gulf of Mexico area properties, $1.36 per Mcfe
($1.19 per Mcfe before royalties) for the Utah oil producing properties where
secondary and tertiary recovery methods are being used, and $0.08 per Mcfe
(before and after royalties) for the United Kingdom properties.
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses
for the first nine months of 1999 decreased 9% from the corresponding period in
1998. This decrease reflects higher performance-based compensation payments made
during the first quarter of 1998 than during the corresponding period in 1999.
General and administrative costs for the first nine months of 1999, on a per
unit basis, decreased 21% to $0.13 per Mcfe ($0.11 per Mcfe before royalties)
compared to $0.17 per Mcfe ($0.14 per Mcfe before royalties) for the
corresponding period of 1998.
INTEREST EXPENSE. Our interest expense for the first nine months of 1999
increased compared to the corresponding period in 1998 due to greater credit
facility utilization. Our weighted average debt outstanding for the nine months
ended September 30, 1999 was $43.3 million compared to $6.1 million for the
corresponding period in 1998. The effective interest rate on our outstanding
debt for the nine months ended September 30, 1999 was 5.76% compared to 6.19%
for the corresponding period in 1998. The weighted average interest rate on our
debt at September 30, 1999 was 6.24%.
DEPLETION AND AMORTIZATION. Our depletion and amortization expense for the
first nine months of 1999 increased 29% from the corresponding period in 1998 as
a result of a 15% increase in our production and an 11% increase in our average
depletion rate to $1.51 per Mcfe ($1.25 per Mcfe before royalties). The
significant downward revision in our proved reserves at December 31, 1998 that
resulted from the low oil prices on that date is primarily responsible for the
increase in our effective depletion rate in the first nine months of 1999
compared to the corresponding period in 1998.
In Libya, Chieftain and its partners concluded that a multi-year exploration
program and production test is not commercial under the terms of the concession
and will therefore terminate the program. As a result, additional depletion of
$11.4 million was recorded in the second quarter of 1999 to eliminate this
investment, resulting in a charge to operations, net of income taxes, of
$6.3 million.
1998 COMPARED TO 1997
PRODUCTION AND PRICING. Our average daily production increased 10% to 85.2
MMcfe (103.2 MMcfe before royalties) in 1998 from 77.8 MMcfe (93.4 MMcfe before
royalties) in 1997. Natural gas comprised 79% of our production in 1998 and 83%
in 1997. In 1998, our natural gas production increased 5% to 24.5 Bcf (30.0 Bcf
before royalties) compared to 23.4 Bcf (28.3 Bcf before royalties) in
S-22
<PAGE>
1997. In 1998, our oil and natural gas liquids production increased 33% to 1,100
MBbls (1,271 MBbls before royalties) compared to 825 MBbls (962 MBbls before
royalties) in 1997. We received an average price of $1.99 per Mcf in 1998
compared to $2.33 per Mcf in 1997 and we received an average price of $11.74 per
barrel in 1998 compared to $18.94 per barrel in 1997.
The combination of economic problems in Asia, the mild North American winter and
aggressive international competition for market share caused crude oil prices to
fall sharply during 1998, bringing the average price that we received for oil
and natural gas liquids to $11.74 per barrel, down 38% from the 1997 average.
The mild North American winter of 1997-98 had a significant downward effect on
natural gas prices. Prices during the fourth quarter of 1998 were down 33% from
the corresponding quarter in 1997. The average price received for our 1998 U.S.
natural gas production declined by 17% to an average of $2.06 per Mcf. In 1998,
natural gas production contributed 79% of our revenue.
PRODUCTION REVENUES. In 1998, growth in our combined natural gas and oil
production volumes was more than offset by decreases in natural gas and oil
prices. As a result, 1998 production revenues decreased 12% to $61.6 million
($74.9 million before royalties).
Eighty-six percent of our 1998 natural gas production came from our interests in
105 wells in the Gulf of Mexico. Our natural gas production in the Gulf of
Mexico was up 6% in 1998 from 1997, with increases coming from the Main Pass,
Mustang Island, Eugene Island, East Cameron, High Island and Vermilion areas.
Comparing 1998 and 1997, the primary contributors to growth in our production
volumes were the East Cameron and Main Pass areas in the Gulf of Mexico and the
Aneth and Ratherford Units in southeast Utah. During 1998, 64% of our oil
production came from our interests in 269 wells in the Aneth and Ratherford
Units and 26% of our oil production came from the Gulf of Mexico.
At year-end 1998, we were producing 78.2 MMcf per day of natural gas (95.5 MMcf
per day before royalties), of which 67.9 MMcf per day (85.2 MMcf per day before
royalties) was from the U.S. and 10.3 MMcf per day (before and after royalties)
was from the North Sea. Our year-end 1998 oil production was 3,453 barrels per
day (4,030 barrels per day before royalties) of which 1,893 barrels per day
(2,170 barrels per day before royalties) was from the Aneth and Ratherford Units
in Utah and 1,280 barrels per day (1,550 barrels per day before royalties) was
from the Gulf of Mexico. An additional 220 barrels per day (before and after
royalties) was contributed by our interests in two wells in Libya's Sirte Basin.
OTHER REVENUE. Interest and other revenue received by us in 1998 included 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.
PRODUCTION COSTS. Our production costs in 1998 increased 23% from 1997
primarily as a result of several weather-induced evacuations of manned
facilities in the Gulf of Mexico during the third quarter of 1998, the
commencement of production at East Cameron 349 and significant pipeline repair
costs in the South Pass area. Our production costs in 1998 increased to $0.53
per Mcfe ($0.43 per Mcfe before royalties), up 12% from the 1997 rate of $0.47
per Mcfe ($0.39 per Mcfe before royalties). Our higher level of oil production,
compared to our gas production, was also responsible for our higher 1998
production costs. Higher lifting costs are associated with oil production and
oil production comprised 21% of our production volumes in 1998 compared to 17%
in 1997.
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses
increased 11% for 1998 compared to 1997. This increase reflects
performance-based compensation payments, made during the first quarter, which
were higher in 1998 than in 1997. Our general and administrative costs remained
constant at $0.15 per Mcfe ($0.13 per Mcfe before royalties) in both 1998 and
1997.
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<PAGE>
INTEREST EXPENSE. Our interest expense in 1998 increased compared to 1997 due
to initial credit facility utilization. Our weighted average debt outstanding
for 1998 was $12.3 million and the effective interest rate on our outstanding
debt for 1998 was 6.19%. The weighted average interest rate on our debt at
December 31, 1998 was 5.65%.
DEPLETION AND AMORTIZATION. Our depletion and amortization expense in 1998
increased 14% compared to 1997 as a result of a 10% increase in production and a
4% increase in the average depletion rate to $1.35 per Mcfe ($1.12 per Mcfe
before royalties).
1997 COMPARED TO 1996
PRODUCTION AND PRICING. Our average daily production increased 8% to 77.8 MMcfe
(93.4 MMcfe before royalties) in 1997 from 71.8 MMcfe (85.8 MMcfe before
royalties) in 1996. Natural gas comprised 83% of our production in 1997 and
1996. In 1997, our natural gas production increased 7% to 23.4 Bcf (28.3 Bcf
before royalties) compared to 21.9 Bcf (26.3 Bcf before royalties) in 1996. In
1997, our oil and natural gas liquids production increased 12% to 825 MBbls (962
MBbls before royalties) compared to 734 MBbls (857 MBbls before royalties) in
1996. The natural gas prices we received in 1997 averaged $2.33 per Mcf compared
to $2.09 per Mcf in 1996. The oil prices we received in 1997 averaged $18.94 per
barrel compared to $20.99 per barrel in 1996.
Exceptionally strong prices for natural gas in North America prevailed during
the winter months at the start of 1997 and also during the period from August to
November of 1997. Natural gas prices weakened at year-end due to warm weather
and higher than normal deliveries from storage which reduced demand for natural
gas.
PRODUCTION REVENUES. Despite the fall in oil prices in 1997, growth in both our
natural gas and oil production volumes, combined with a rise in natural gas
prices, increased our production revenues 15% ($9 million) to $69.6 million
compared to 1996.
Our natural gas production was up 7% in 1997 over 1996, with increases in
production coming from the Matagorda Island, East Cameron and Main Pass areas.
Eighty-two percent of our 1997 natural gas production came from our interests in
99 natural gas wells in the Gulf of Mexico.
Our production of oil and natural gas liquids increased by 12% in 1997 over
1996. During 1997, 73% of our oil production was from interests in 268 wells in
the Aneth and Ratherford Units and 23% was from the Gulf of Mexico.
At 1997 year-end, we were producing 64.1 MMcf per day of natural gas (76.5 MMcf
per day before royalties). 50.3 MMcf per day (62.7 MMcf per day before
royalties) of this production came from our interests in the U.S. and 13.8 MMcf
per day (before and after royalties) came from our interests in the North Sea.
Our 1997 year-end oil production was 2,779 barrels per day (3,196 barrels per
day before royalties) of which 1,738 barrels per day (2,000 barrels per day
before royalties) was from the Aneth and Ratherford Units in Utah and 650
barrels per day (800 barrels per day before royalties) was from the Gulf of
Mexico.
PRODUCTION COSTS. Our production costs in 1997 increased 9% from 1996 primarily
as a result of the 8% increase in our production volumes. Our production costs
were $0.47 per Mcfe ($0.39 per Mcfe before royalties), compared to the 1996 rate
of $0.46 per Mcfe ($0.39 per Mcfe before royalties).
GENERAL AND ADMINISTRATIVE EXPENSES. Our general and administrative expenses
increased 8% in 1997 compared to 1996. Our general and administrative costs were
$0.15 per Mcfe ($0.13 per Mcfe before royalties) in 1997, unchanged from $0.15
per Mcfe ($0.13 per Mcfe before royalties) in 1996.
S-24
<PAGE>
DEPLETION AND AMORTIZATION. Our depletion and amortization expense in 1997
increased 20% as a result of an 8% increase in our production and an 11%
increase in our average depletion rate to $1.30 per Mcfe ($1.08 per Mcfe before
royalties).
CAPITAL RESOURCES AND LIQUIDITY
Our primary sources of cash are funds generated from our operations and
financing activities. Our primary cash outflows are for exploration and
development activities.
Discretionary cash flow, a frequently used measure of performance for
exploration and production companies, is derived by adjusting net income (loss)
attributable to common shares to eliminate the effects of depletion and
amortization, additional depletion and deferred income taxes. We generated
discretionary cash flow of $33.6 million during the first nine months of 1999
compared to $27.5 million for the corresponding period in 1998. This 22%
increase is primarily a result of our higher operating revenues.
Our financing activities in the first nine months of 1999 provided $4.9 million
of cash, the net result of the drawdown of $5 million of our revolving credit
facility, the exercise of employee stock options and the purchase for
cancellation of 7,500 common shares under our share repurchase program, which
expires on November 1, 1999. Financing activities during the corresponding
period in 1998 provided $20.1 million of cash, which was the net result of:
- the drawdown of $25 million of our revolving credit facility;
- the exercise of employee stock options for $0.4 million; and
- the purchase for cancellation of 264,600 common shares at the cost of
$5.3 million under our share repurchase program.
Cash used in investing activities decreased 38% to $42.2 million for the first
nine months of 1999 from $67.8 million for the corresponding period in 1998. Our
capital expenditures during the first nine months of 1999 totaled
$36.2 million. Of this amount, $1.8 million was expended on development
drilling, $23.0 million on exploratory drilling, $4.7 million on capital field
development and the balance was expended on leasehold, seismic and geological
costs. Of the 15 wells in which we participated in 1999, ten were in the Gulf of
Mexico (four of which were still being drilled at September 30, 1999), three
were onshore in the U.S. and two were in Libya. Five additional wells were
drilled on our Gulf of Mexico acreage at no cost to us, one of which resulted in
a natural gas well and four of which were unsuccessful. We are currently
drilling or plan to drill approximately 15 exploratory and development wells in
the Gulf of Mexico and the Gulf Coast area during the fourth quarter of 1999.
Our September 30, 1999 cash balance of $0.6 million was down $5.5 million from
the balance at September 30, 1998. We had outstanding borrowings of $45 million
on our $100 million revolving credit facility at September 30, 1999. The
weighted average interest rate on our borrowings for the first nine months of
1999 was 5.76%. If we apply the net proceeds of this offering to reduce our bank
debt, we will have repaid all or substantially all of the outstanding balance
under our revolving credit facility, resulting in a borrowing base of
approximately $100.0 million.
OUTLOOK
Currently, we have budgeted approximately $18.6 million for exploration and
development capital expenditures for the fourth quarter of 1999. Our preliminary
2000 capital expenditure budget is estimated at $86 million. We expect to fund
most of these expenditures from our operational cash flow. These capital
expenditures can vary significantly as a result of exploration success,
availability of equipment and services and opportunities. We will monitor
capital spending and adjust investment
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<PAGE>
levels based on cash flow projections. We will continue to focus on natural gas
production in the Gulf of Mexico.
YEAR 2000 DISCLOSURE
We have completed our assessment of our internal Year 2000 issues and have made
the changes and employed the testing procedures that we deemed necessary. At
this time, we are confident that no internal issues remain that could have a
material effect on our financial condition or results of operations. We
substantially completed our assessment of the readiness of third parties by the
end of the second quarter of 1999. We continue to monitor the readiness of
significant third parties in order to obtain assurances that interruptions, if
any, will be held to a minimum. We do not consider the costs that we have
incurred to date and which we expect to incur in the future to be material.
We have interests in a substantial number of offshore oil and natural gas
production facilities that are operated by others. We are required to rely on
assessments by others as to Year 2000 readiness of such facilities. Production
volumes are transported through pipelines and processed through facilities that
are also operated by others. Computers are used extensively to control and
operate such pipelines and facilities in the oil and natural gas industry and it
is reasonably likely that one or more of these facilities will experience a
computer related event which could result in the shutdown of production,
transportation or processing facilities for such time as is required to effect
alternative controls. We cannot reasonably quantify the estimated lost revenue,
if any, which would result from such an interruption. To mitigate the effect of
any interruptions, we intend to continue our review of contingency plans
prepared by our various operating partners. See "Risk Factors--We and our
suppliers or partners may not be Year 2000 compliant, which could result in
disruption of our operations."
S-26
<PAGE>
BUSINESS AND PROPERTIES
Chieftain is an independent energy company engaged in the exploration,
development and production of natural gas and oil. Our producing properties and
exploration acreage are primarily located in the shallow waters of the U.S. Gulf
of Mexico. We also have properties located onshore in Louisiana, in the Four
Corners area of southeast Utah and in the U.K. sector of the North Sea. We were
incorporated under the Business Corporations Act (Alberta) in 1988 and commenced
operations upon the closing of our initial public offering on April 20, 1989.
We have assembled a large natural gas and oil lease acreage position in the Gulf
of Mexico. Our lease interests in the Gulf of Mexico include a balanced
portfolio of exploration and development drilling prospects. These prospects
range from high-impact prospects with relatively greater risks, which we believe
have the potential to add substantially to our reserves, to relatively lower
risk development and exploitation projects with lower reserve potential. Our
exploration efforts are supported by an extensive 3-D seismic database covering
most of our leases. We believe that our seismic database and related
technological expertise have contributed to our successful exploration and
development track record. We believe our conservative capital structure provides
us with the financial flexibility to take advantage of our prospects and other
opportunities, including acquisitions of leasehold acreage and producing
properties.
We hold interests in 133 lease blocks located on the continental shelf of the
Gulf of Mexico. We also have interests in ten deep-water blocks. Of these lease
blocks, 94 are held as exploratory acreage and 49 are held by production. We
operate 38 of these blocks. Our average working interest in our Gulf of Mexico
leases is approximately 40%. In the third quarter of 1999, we had net production
of 75.9 MMcfe per day in the Gulf of Mexico, which represented approximately 77%
of our total production.
In addition to our Gulf of Mexico properties, we own various interests in two
large light oil producing units in the Four Corners area of southeast Utah where
we had net production of 1,774 barrels per day in the third quarter of 1999. We
own an interest in approximately 9,600 net acres in the U.K. sector of the North
Sea where we had net production of 10.5 MMcfe per day in the third quarter of
1999. We are also active in exploratory activities onshore in Louisiana.
At December 31, 1998, we had estimated proved reserves of 207.9 Bcfe. These
reserves had a present value of net cash flows before income taxes, discounted
at 10%, of $152.5 million using constant natural gas and oil prices in effect on
December 31, 1998, which averaged $2.12 per Mcf for natural gas and $9.72 per
barrel for oil. If our realized natural gas and oil prices in effect at
September 30, 1999 were used in this determination, assuming no other changes,
our estimated proved reserves at December 31, 1998, would have increased to
222.7 Bcfe and the present value of net cash flows before income taxes,
discounted at 10%, would have increased to $279.0 million. Our average realized
prices for our production at September 30, 1999 were $2.58 per Mcf for natural
gas and $20.16 per barrel for oil. At December 31, 1998, approximately 62% of
our proved reserves were natural gas and approximately 70% of our proved
reserves were developed. Our total proved reserves at December 31, 1998 had a
reserves-to-production ratio of approximately 6.8 years.
We have experienced substantial growth in proved reserves, production, revenue
and cash flow as demonstrated by the following:
- Since 1994, our overall drilling success rate has been 74% and our drilling
success rate for exploratory wells has been 40%. For the nine months ended
September 30, 1999, our overall drilling success rate was 73% and our
drilling success rate for exploratory wells was 62%.
S-27
<PAGE>
- Since 1994, we have added proved reserves of 235 Bcfe, of which 127 Bcfe has
been from drilling, 72 Bcfe has been from acquisitions and 36 Bcfe has been
from upward revisions of previous estimates.
- Since 1994, we have replaced 208% of our production.
- We have increased our average daily production 157% to 98.3 MMcfe per day in
the third quarter of 1999 from 38.2 MMcfe per day in 1994.
- We have increased our net production revenues 18% to $53.0 million for the
first nine months of 1999 from $44.9 million for the first nine months of
1998.
- We have increased our EBITDA 24% to $39.2 million for the first nine months
of 1999 from $31.6 million for the first nine months of 1998.
OUR STRENGTHS
We believe that our historical success and future performance are directly
related to the following combination of strengths:
- SUBSTANTIAL INVENTORY OF DRILLING PROJECTS IN THE GULF OF MEXICO. In the
Gulf of Mexico, we have generated an inventory of over 45 drilling locations,
of which 36 are exploratory. Substantially all of these locations have been
evaluated and defined using 3-D seismic data. Our large inventory permits us
to be flexible in project selection and in the timing of drilling. By
identifying new exploration targets and acquiring additional acreage, we
continually add to our drilling inventory.
- PROVEN EXPLORATORY EXPERTISE. Our ability to define and participate in
successful exploratory prospects in the Gulf of Mexico is demonstrated by our
exploratory drilling success rate in the Gulf of Mexico of 88% over the nine
months ended September 30, 1999.
- EXPERIENCED TECHNICAL TEAM. Our technical team is comprised of highly
respected industry professionals with an average of 22 years of industry
experience. We believe our exploration success is a direct result of this
team's engineering and technical analyses.
- FINANCIAL FLEXIBILITY. With the net proceeds of this offering, we will have
the ability to repay all or substantially all of our outstanding
indebtedness, resulting in approximately $100 million of availability under
our revolving credit facility. We seek to maintain low levels of debt in
order to respond quickly to drilling or acquisition opportunities.
BUSINESS STRATEGY
Our strategy is to increase our reserves, production, revenue and cash flow
through exploration and development drilling and through the acquisition of
leasehold acreage and producing properties. The elements of our strategy include
the following:
- FOCUS ON THE GULF OF MEXICO. We focus our operations on the Gulf of Mexico
where we have acquired a significant exploration acreage position and
assembled a substantial 3-D seismic database. We believe this region combines
significant geological potential, reservoir size, quality and deliverability
with favorable commodity pricing and attractive finding, development and
operating costs.
- GROW THROUGH EXPLORATION. We are pursuing an active technology-driven
exploration program that is designed to balance projects with lower risk and
moderate potential with drilling prospects which have higher risk and
substantial potential. We generate exploration prospects through geological
and geophysical analysis of 3-D seismic and other data and also review
prospects generated by others. Currently, we have budgeted approximately
$18.6 million for exploration and
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<PAGE>
development capital expenditures for the fourth quarter of 1999 and we expect
to use $14.9 million of this amount for exploration activities. We are
currently drilling or plan to drill approximately 15 exploratory and
development wells in the Gulf of Mexico and in the Gulf Coast area during the
fourth quarter of 1999. We have budgeted approximately $86.2 million for
exploration and development capital expenditures for 2000, $50.0 million of
which we expect to use for exploration activities.
- MANAGE DRILLING RISKS THROUGH JOINT VENTURES AND THE USE OF ADVANCED
TECHNOLOGIES. We seek to limit our financial and operating risks in selected
projects by participating in drilling with industry partners and operators.
We believe this strategy limits our risk exposure in high potential
prospects. Additionally, we have increasingly relied on advanced
technologies, including 3-D seismic analysis, to define geologic risks,
thereby enhancing the results of our drilling efforts. We also seek to
operate our projects in order to better control drilling costs and the timing
of drilling.
- EVALUATE AND PURSUE STRATEGIC ACQUISITIONS. We continually review
opportunities to acquire leasehold acreage and producing properties. We seek
to acquire properties that we believe have significant exploration potential
and to increase our working interest in producing lease blocks when available
to us on economically favorable terms.
PROPERTIES
Our principal natural gas and oil properties are concentrated in the U.S. Gulf
of Mexico and, to a lesser extent, onshore Louisiana, Utah and other parts of
the U.S. and in the U.K. sector of the North Sea.
The following table summarizes our estimated proved reserves by major operating
area and the estimated present value of net cash flows before income taxes,
discounted at 10%, of these reserves at December 31, 1998:
<TABLE>
<CAPTION>
PROVED RESERVES
------------------------------ ESTIMATED PRESENT
OIL AND VALUE BEFORE
NATURAL INCOME TAXES OF
NATURAL GAS PROVED RESERVES
GAS LIQUIDS TOTAL (U.S.$ IN
(MMCF) (MBBLS) (MMCFE) THOUSANDS)
-------- -------- -------- -----------------
<S> <C> <C> <C> <C>
Gulf of Mexico............................ 96,774 3,865 119,965 $ 121,090
Onshore Louisiana......................... 20,672 79 21,145 19,422
Utah and Other Onshore.................... 1,517 9,163 56,496 2,991
------- ------ ------- -----------------
Total U.S............................. 118,963 13,107 197,606 143,503
U.K. (North Sea).......................... 10,110 27 10,271 9,005
------- ------ ------- -----------------
Total(1).............................. 129,073 13,134 207,877 $ 152,508
======= ====== ======= =================
</TABLE>
- ---------------------
(1) If our realized prices in effect at September 30, 1999 were used in this
determination, assuming no other changes, proved reserves would have
increased to 222.7 Bcfe and PV-10 Value would have increased to
$279.0 million.
GULF OF MEXICO
We concentrate our exploration and development activities in, and devote
substantial managerial and financial resources to, the offshore U.S. Gulf of
Mexico. The Gulf of Mexico contains a prolific oil and natural gas basin. This
area is more than 600 miles long and 100 miles wide and extends from the State
of Texas to the State of Florida. We primarily focus our exploration and
development activities in the
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shallow waters (less than 600 feet deep) of the Gulf of Mexico continental
shelf. The continental shelf is a low cost operating environment for which
technical and analytical data, including 3-D seismic data, are readily
available. The vast network of gathering systems and pipelines in the shallow
waters of the basin provides excellent access to markets. The Gulf of Mexico's
geology is generally characterized by multiple productive horizons and good
permeability which is conducive to high initial production and relatively rapid
capital payback.
We maintain a large acreage position in the Gulf of Mexico. With an average
interest of 40% in 143 blocks, we rank as the sixteenth largest leaseholder and
the ninth largest independent producer on the continental shelf. Of these lease
blocks, 133 are shallow water blocks and ten are deep-water blocks. We acquired
three blocks covering 15,000 acres at the March 1999 Central Gulf of Mexico
lease sale. We participated in high bids for three blocks, covering 17,000
acres, at the Western Gulf of Mexico lease sale in late August 1999. Our acreage
in the Gulf of Mexico covered 684,495 gross (268,386 net) acres at
September 30, 1999. We operate 38 blocks in the Gulf of Mexico.
Described below are the areas of our current exploration and development
activity in the Gulf of Mexico. Of these properties, we operate High Island
Blocks A-510, A-530 and A-531 and West Cameron Blocks 300 and 386.
HIGH ISLAND. In August 1999, we announced that our exploratory well on High
Island Blocks A-510/A-531, located offshore Texas, resulted in an oil and
natural gas discovery. This well was drilled to a total depth of 11,107 feet and
encountered more than 260 net feet of hydrocarbon-bearing pay in multiple zones.
We are now drilling an additional well on Block A-510 and will then design and
install production facilities. We operate, and have a 50% working interest in,
this project.
VERMILION 267. We have a 60% working interest in the Vermilion 267 No. 1
natural gas discovery well located offshore Louisiana. This well reached a total
depth of 13,370 feet in early October 1999 and encountered 52 feet of high
quality net effective hydrocarbon-bearing reservoir rock. This well has been
cased for production and the design of production facilities is in progress.
Additional exploratory and development drilling is planned to fully develop the
block.
SOUTH MARSH ISLAND. In March 1999, we commenced production of oil and natural
gas from two wells on South Marsh Island Block 39 in which we have a 50% working
interest. We commenced additional production in the third quarter of 1999 from
two successful exploratory wells drilled into separate fault blocks during the
first quarter of 1999. In the third quarter of 1999, we drilled a successful
well to test geological zones below then-productive formations which commenced
production in late August 1999. A total of six successful wells have been
drilled on the block. Our share of production from this block averaged 7.6 MMcf
per day of natural gas and 1,500 barrels per day of light oil in the third
quarter of 1999 and was the principal contributor to our increased production
during this period.
MAIN PASS. Our share of natural gas and natural gas liquids production from
Main Pass averaged 14.0 MMcfe per day during the third quarter of 1999. We are
continuing drilling and development activity on this property. Production from a
new platform is scheduled to commence in the fourth quarter of 1999.
EUGENE ISLAND. Design of production facilities is under way for Eugene Island
Block 189 where two successful oil and natural gas discoveries were drilled on
separate fault blocks in 1997. A third well is planned after the production
platform has been installed. New production is anticipated in early 2000.
OTHER OFFSHORE AREAS. At South Timbalier Block 196, production from a 1999
first-quarter multiple zone oil and natural gas discovery, in which we have a
50% working interest, is expected to commence in early 2000.
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Exploratory drilling is under way, or is planned to commence prior to the
1999 year-end, on High Island Block A-530, in which we have a 75% interest, West
Cameron Block 300, in which we have a 35% interest, West Cameron Block 386, in
which we have an 80% interest, Grand Isle Block 103, in which we have a 20%
interest, West Cameron Block 613, in which we have a 25% interest, Matagorda
Island Block 704, in which we have a 25% interest, and High Island Block A-510,
in which we have a 50% interest.
ONSHORE LOUISIANA
Currently, we are actively exploring three onshore prospects in Louisiana. These
prospects are described below.
VERMILION PARISH--NORTHEAST WRIGHT FIELD. In the second quarter of 1999,
drilling commenced to follow up a 1998 discovery well, D.W. Guidry No. 1. The
Guidry well discovered 150-feet of net natural gas pay below 17,000 feet. Our
interest in this well is subject to a recovery penalty on a portion of well
costs. The follow-up well, Broussard No. 1, was drilled as a delineation well to
confirm and extend natural gas reserves discovered in the Guidry well. The
Broussard No. 1 well was drilled to a measured depth of 18,340 feet in early
October 1999 and production liner has been run to total depth. This well
encountered a significant accumulation of natural gas-bearing high quality
reservoir rock. Completion procedures are in progress and we expect production
from the Broussard No. 1 well to commence during the fourth quarter of 1999.
Production facilities and flow lines in the field are being expanded to
accommodate increased production volumes and additional drilling is planned to
fully develop the field. We own a 50% interest in the Broussard No. 1 well and
3,100 acres in the Northeast Wright Field.
LAFOURCHE PARISH--NORTHEAST CHACAHOULA PROSPECT. We are participating, with a
50% interest, in a 17,280-foot exploratory well, Levert No. 1, on the 850-acre
Northeast Chacahoula Prospect, which is prospective for both natural gas and
oil.
IBERIA PARISH--BAYOU PIGEON PROSPECT. In September 1999, we commenced drilling
of a 15,500-foot exploratory well, Williams Land Co. No. 1. We have a 50%
interest in the 1,973-acre Bayou Pigeon Prospect.
UTAH AND OTHER ONSHORE
In the Four Corners area of Utah, we have a 13.4% interest in the Aneth Unit and
a 21.4% interest in the Ratherford Unit, both of which produce light oil. During
1998, we drilled 30 multi-lateral horizontal development wells in these fields.
We currently have a carbon dioxide tertiary recovery pilot project at the Aneth
Unit and we are planning a field-wide tertiary recovery project at the
Ratherford Unit. Due to higher operating costs, economic recovery of the
reserves in these units is more sensitive to low oil prices than our other
properties. For the nine months ended September 30, 1999, our share of
production from these fields averaged 1,794 barrels per day. In addition, we
also have onshore interests in Montana, North Dakota, Pennsylvania and Texas.
Production from these interests during the nine months ended September 30, 1999
was minimal.
UNITED KINGDOM (NORTH SEA)
In the North Sea, we produce natural gas from two fields in the southern basin
of the U.K. sector in which we have a 17% average interest. Our production
averaged 9.7 MMcf per day in the nine months ended September 30, 1999 and
amounted to 14% of our total natural gas production and 7% of our total natural
gas revenue for this period. We plan to participate in a 3-D seismic program on
a portion of our North Sea acreage.
S-31
<PAGE>
RESERVES
The following table sets forth certain summary information with respect to
estimates of our oil and natural gas reserves for the periods indicated.
Estimates of our U.S. oil and natural gas reserves, the future net revenues
therefrom and their discounted present value at a rate of 10%, or PV-10 Value,
have been prepared by Netherland, Sewell & Associates, Inc., independent
petroleum engineers. Estimates of our U.K. reserves and related information have
been prepared by our personnel. U.K. reserves comprise 5% of our total reserves
on a Bcfe basis.
<TABLE>
<CAPTION>
AS AT DECEMBER 31,
-------------------------------------------------------------------
1998 1997 1996 1995 1994
----------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
ESTIMATED PROVED OIL AND NATURAL GAS RESERVES:
Natural gas reserves--before royalties (MMcf):
Proved developed............................... 122,164 105,990 102,017 99,709 40,624
Proved undeveloped............................. 36,900 43,453 48,597 50,225 26,107
----------- -------- -------- -------- --------
Total........................................ 159,064 149,443 150,614 149,934 66,731
=========== ======== ======== ======== ========
Natural gas reserves--net of royalties (MMcf):
Proved developed............................... 99,432 89,139 86,997 85,705 33,581
Proved undeveloped............................. 29,641 35,958 39,804 40,986 25,155
----------- -------- -------- -------- --------
Total........................................ 129,073 125,097 126,801 126,691 58,736
=========== ======== ======== ======== ========
Oil reserves--before royalties (MBbls):
Proved developed............................... 8,786 9,591 9,482 8,501 6,317
Proved undeveloped............................. 6,441 3,415 1,087 1,101 956
----------- -------- -------- -------- --------
Total........................................ 15,227 13,006 10,569 9,602 7,273
=========== ======== ======== ======== ========
Oil reserves--net of royalties (MBbls):
Proved developed............................... 7,534 8,397 8,397 7,509 5,588
Proved undeveloped............................. 5,600 2,916 907 943 797
----------- -------- -------- -------- --------
Total........................................ 13,134 11,313 9,304 8,452 6,385
=========== ======== ======== ======== ========
Total proved oil and natural gas
reserves--before royalties (MMcfe)(1)........ 250,426 227,479 214,028 207,546 110,370
=========== ======== ======== ======== ========
Total proved oil and natural gas reserves--net
of royalties (MMcfe)(1)...................... 207,877 192,975 182,625 177,403 97,046
=========== ======== ======== ======== ========
ESTIMATED PRESENT VALUE OF PROVED RESERVES (U.S. $
IN THOUSANDS):
Proved developed............................... $ 135,867 $187,697 $218,961 $111,608 $ 43,595
Proved undeveloped............................. 16,641 50,615 85,335 40,096 19,333
----------- -------- -------- -------- --------
Total PV-10 Value (before income taxes)........ $ 152,508(2) $238,312 $304,296 $151,704 $ 62,928
=========== ======== ======== ======== ========
Standardized measure of discounted estimated
future net cash flows after income
taxes(3)..................................... $ 152,508 $199,573 $239,023 $137,494 $ 60,374
=========== ======== ======== ======== ========
PRICES USED IN CALCULATING END OF YEAR PROVED
RESERVES:
U.S. natural gas reserves (per Mcf).............. $ 2.15 $ 2.74 $ 3.43 $ 2.06 $ 1.62
U.K. natural gas reserves (per Mcf).............. 1.74 1.76 2.04 0.86 2.25
Oil (per barrel)................................. 9.72 16.69 24.03 18.48 16.50
</TABLE>
- ---------------------------
(1) Oil is converted into natural gas equivalents using a conversion ratio of 6
Mcf of natural gas to 1 barrel of oil.
(2) If our realized prices in effect at September 30, 1999 were used in this
determination, proved reserves would have increased to 222.7 Bcfe and their
PV-10 Value would have increased to $279.0 million.
(3) At December 31, 1998, no income taxes would be payable at these natural gas
and oil price levels.
S-32
<PAGE>
ACREAGE
The following table summarizes our acreage held as at September 30, 1999. Where
applicable, interests that are not working interests (none of which is material)
have been converted to working interest equivalents.
<TABLE>
<CAPTION>
GROSS ACRES NET ACRES
----------- ---------
<S> <C> <C>
United States
Offshore Gulf of Mexico
Louisiana............................................... 315,414 110,119
Texas................................................... 369,081 158,267
----------- ---------
Total Offshore Gulf of Mexico......................... 684,495 268,386
----------- ---------
Onshore
Louisiana............................................... 6,478 3,025
Montana................................................. 3,240 3,240
North Dakota............................................ 2,277 415
Pennsylvania............................................ 324 36
Utah.................................................... 30,980 5,626
----------- ---------
Total Onshore......................................... 43,299 12,342
----------- ---------
Total United States......................................... 727,794 280,728
----------- ---------
United Kingdom
North Sea................................................. 60,273 9,644
----------- ---------
Total, all areas...................................... 788,067 290,372
=========== =========
</TABLE>
DRILLING ACTIVITY
During the nine months ended September 30, 1999, we participated in drilling
nine wells in the Gulf of Mexico area, of which eight were successful for an 89%
success rate. We accelerated our drilling activity in the Gulf of Mexico region
during the third quarter in response to higher natural gas and oil prices. We
are currently drilling or plan to drill approximately 15 exploratory and
development wells in the Gulf of Mexico and the Gulf Coast area during the
fourth quarter of 1999.
The following table summarizes the results of our drilling activities during
each of the three years ended December 31, 1998 and the nine months ended
September 30, 1999.
<TABLE>
<CAPTION>
GROSS WELLS NET WELLS
---------------------------- -----------------------
PERIOD TYPE OF WELL DRY SUCCESSFUL TOTAL DRY SUCCESSFUL TOTAL
- ----------------------------------- -------------------------------- --------- ---------- ----- ---- ---------- -----
<S> <C> <C> <C> <C> <C> <C> <C>
Nine months ended Exploratory..................... 3 5 8 0.45 4.60 5.05
September 30, 1999 Development..................... -- 3 3 -- 1.04 1.04
Year ended Exploratory..................... 8 7 15 3.45 2.24 5.69
December 31, 1998 Development..................... -- 35 35 -- 6.58 6.58
Year ended Exploratory..................... 9 8 17 2.99 3.32 6.31
December 31, 1997 Development..................... 1 43 44 0.50 7.92 8.42
Year ended Exploratory..................... 8 7 15 2.26 1.72 3.98
December 31, 1996 Development..................... 2 28 30 0.67 5.00 5.67
</TABLE>
S-33
<PAGE>
WELLS
Our productive natural gas and oil wells as at December 31, 1996, 1997 and 1998
and as at September 30, 1999 are listed in the following table.
<TABLE>
<CAPTION>
NATURAL
GAS WELLS OIL WELLS TOTAL WELLS
--------- --------- -----------
<S> <C> <C> <C>
September 30, 1999
Gross..................................................... 100 290 390
Net....................................................... 20.85 51.29 72.14
December 31, 1998
Gross..................................................... 100 287 387
Net....................................................... 20.44 49.86 70.30
December 31, 1997
Gross..................................................... 118 287 405
Net....................................................... 29.06 49.66 78.72
December 31, 1996
Gross..................................................... 93 295 388
Net....................................................... 21.28 50.79 72.07
</TABLE>
PRODUCTION
The commencement of production from South Marsh Island Block 39 and new
production from Main Pass Block 250 were the principal contributors to our
increased production in the first nine months of 1999. During the third quarter
of 1999, we increased our production of oil and natural gas liquids by 56% from
the third quarter of 1998 to a record level of 4,394 barrels per day. The
average price that we received for oil and natural gas liquids in the third
quarter of 1999 was $19.31 per barrel, an increase of 63% from the third quarter
of 1998. Our natural gas production increased by 21% from the third quarter of
1998 to 72 MMcf per day. The average price that we received for U.S. natural gas
production in the third quarter was $2.46 per Mcf, an increase of 25% from the
third quarter of 1998. The average price that we received for North Sea natural
gas production was $0.81 per Mcf, a decrease of 32% from the third quarter of
1998.
The following table summarizes our production volume and weighted average sales
prices for the periods indicated.
<TABLE>
<CAPTION>
NINE MONTHS
ENDED
SEPTEMBER 30, YEAR ENDED DECEMBER 31,
------------------- ----------------------------------------------------
1999 1998 1998 1997 1996 1995 1994
-------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C>
NET SALES VOLUME:
Natural gas--before royalties (MMcf)............ 23,327 21,433 30,048 28,316 26,277 12,954 12,604
Oil and natural gas liquids--before
royalties (MBbls)............................. 1,285 912 1,271 962 857 693 691
Total production--before royalties
(MMcfe)(1).................................... 31,035 26,906 37,674 34,088 31,416 17,111 16,753
Natural gas--net of royalties (MMcf)............ 19,098 17,470 24,504 23,431 21,894 10,754 10,382
Oil and natural gas liquids--net of
royalties (MBbls)............................. 1,091 792 1,100 825 734 600 595
Total production--net of royalties
(MMcfe)(2).................................... 25,642 22,223 31,102 28,383 26,296 14,351 13,953
WEIGHTED AVERAGE SALES PRICES:
Natural gas (per Mcf)........................... $ 1.89 $ 2.02 $ 1.99 $ 2.33 $ 2.09 $ 1.54 $ 1.97
Oil and natural gas liquids (per barrel)........ 15.62 12.39 11.74 18.94 20.99 16.94 15.86
</TABLE>
- ---------------------------
(1) Oil is converted into natural gas equivalents using a conversion ratio of
6 Mcf of natural gas to 1 barrel of oil.
S-34
<PAGE>
MARKETING
Most of our natural gas reserves are located in the U.S. Gulf of Mexico area
where ready deliverability of natural gas through numerous large capacity
pipelines and auxiliary feeder pipelines provides flexibility in marketing our
natural gas production in the U.S. spot market. Natural gas prices in the U.S.
and in the British North Sea are largely determined by competitive market
forces.
Most of the natural gas we have produced has been marketed since 1989 by
Highland Energy Company, an aggregator for several U.S. natural gas producers,
at prices based on spot market prices. Highland Energy Company also assists us
in arranging for the marketing of our U.K. natural gas production.
We have sold our oil production from the Aneth and Ratherford Units in the Four
Corners area of Utah under successive term contracts to a regional refiner since
1989. Due to the quantity and quality of this oil, we have obtained premiums
over locally posted prices for this production. Most of our Gulf of Mexico oil
and natural gas liquids production is marketed by Highland Energy Company.
We believe that alternative marketing arrangements would be readily available
for our natural gas, oil and natural gas liquids production although any
alternative arrangement could be less advantageous to us.
PRICE RISK MANAGEMENT
Market prices of oil and natural gas fluctuate and can adversely affect our
operating results. To mitigate some of this risk, from time to time, we may
enter into forward contracts for a portion of our production so as to lock in a
firm natural gas price for a specific volume and delivery period. We sell most
of our gas under short term contractual arrangements and do not engage in
speculative forward selling of volumes that cannot be physically delivered.
LITIGATION
We are, in the ordinary course of business, party to various legal proceedings.
In the opinion of our management, none of these proceedings, either individually
or in the aggregate, is material.
EMPLOYEES
At September 30, 1999, we employed 40 persons. None of our employees is
represented by a union. We consider relations with our employees to be
excellent.
S-35
<PAGE>
MANAGEMENT
DIRECTORS AND EXECUTIVE OFFICERS
Our directors and executive officers and their ages as of the date of this
prospectus supplement are as follows:
<TABLE>
<CAPTION>
NAME AGE POSITION
- ---- -------- --------
<S> <C> <C>
David E. Mitchell, O.C. ............. 73 Director and Chairman of the Board
of Directors
Stanley A. Milner.................... 70 Director, President and Chief
Executive Officer
Stephen C. Hurley.................... 49 Director, Senior Vice President and
Chief Operating Officer
Edward L. Hahn....................... 62 Senior Vice President, Finance and
Treasurer
Esther S. Ondrack.................... 59 Director, Senior Vice President and
Secretary
James B. Lewis....................... 49 Senior Vice President, Operations
S. Jay Milner........................ 41 Vice President, Drilling and
Production
Ronald J. Stefure.................... 52 Vice President and Controller
Hugh J. Kelly........................ 74 Director
John E. Maybin....................... 74 Director
Louis G. Munin....................... 65 Director
Stuart T. Peeler..................... 69 Director
</TABLE>
Our Board of Directors consists of eight members. Each member of the Board is
elected for a term of three years and their terms are staggered. At our last
annual meeting of shareholders, held in May 1999, Messrs. Kelly, Munin and
Peeler were re-elected to serve until 2002. The terms of Messrs. Hurley and
Maybin and of Mrs. Ondrack expire in 2000. The terms of Messrs. Milner and
Mitchell expire in 2001. All of our Directors are also Directors of our
subsidiary, Chieftain International Funding Corp.
DAVID E. MITCHELL, O.C., who is Chairman Emeritus of Alberta Energy
Company Ltd., has been Chairman of the Board of Directors of Chieftain since
February 1989. A graduate in engineering of the University of Oklahoma, he was
President and Chief Executive Officer and a director of Alberta Energy from 1974
until 1993 and chairman of its Board of Directors from 1993 to 1999.
Mr. Mitchell is also a former director of Air Canada, The Bank of Nova Scotia,
Hudson's Bay Company, Lafarge Corporation, Noranda Mines Ltd. and Pan-Alberta
Gas Ltd. He has been awarded the Order of Canada and he is a former president of
the Independent Petroleum Association of Canada. Mr. Mitchell is Stanley A.
Milner's first cousin.
STANLEY A. MILNER has been President and Chief Executive Officer and a Director
of Chieftain since Chieftain's incorporation in 1988. Mr. Milner served in the
same capacities with Chieftain Development Co. Ltd., which he founded in
June 1964. A graduate of the University of Alberta and a member of the
S-36
<PAGE>
Engineering Institute of Canada, he is chairman of the Board of Directors of
Alberta Energy Company Ltd. and a former director of Canadian Imperial Bank of
Commerce and Canadian Pacific Limited. He is a former president of the
Independent Petroleum Association of Canada, a former alderman of the City of
Edmonton and a former chairman of the Board of Governors of the University of
Alberta. Mr. Milner is S. J. Milner's father and David E. Mitchell's first
cousin.
STEPHEN C. HURLEY has been Senior Vice President, Chief Operating Officer and a
Director of Chieftain since 1997. He joined Chieftain in 1995 as Senior Vice
President, Exploration and Chief Operating Officer. From 1991 to 1995, he was
employed by Murphy Exploration and Production Company as Vice President,
Exploration and Production responsible for worldwide exploration. Mr. Hurley was
employed by Ocean Drilling & Exploration Company, a subsidiary of Murphy
Exploration and Production, as Vice President, Exploration from 1987 to 1991,
General Manager, Exploration from 1984 to 1987 and Senior Geologist from 1980 to
1984. From 1975 to 1980 he was employed by Exxon Company USA. Mr. Hurley
graduated in 1975 from the University of Arkansas with a Master of Science
degree in geology. He is a member of the American Association of Petroleum
Geologists, the New Orleans Geological Society, the Society of Exploration
Geophysicists and the American Petroleum Institute.
EDWARD L. HAHN has been Senior Vice President, Finance and Treasurer of
Chieftain since 1995. From the time of Chieftain's incorporation in 1988 to
1995, he was Vice President, Finance and Treasurer. Prior to 1988, Mr. Hahn was
Senior Vice President, Finance and Treasurer of Chieftain Development Co. Ltd. A
chartered accountant, Mr. Hahn joined Chieftain Development as Controller in
1976 with 15 years experience in public accounting and seven years of experience
in oil field manufacturing.
ESTHER S. ONDRACK has been Senior Vice President, Secretary and a Director of
Chieftain since 1995. From the time of Chieftain's incorporation in 1988 to
1995, she was Vice President, Secretary and a Director. Prior to 1988,
Mrs. Ondrack was Senior Vice President, Administration, Corporate Secretary and
a director of Chieftain Development Co. Ltd. A graduate of the University of
Alberta, Mrs. Ondrack joined Chieftain Development in 1964. Mrs. Ondrack is a
former director of TELUS Corporation and has also served as a public governor of
the Canadian Institute of Chartered Accountants.
JAMES B. LEWIS was appointed Senior Vice President, Operations of Chieftain on
October 1, 1999. Mr. Lewis was a consultant to Chieftain from May 1998 until
September 1999. He was employed by Enron Oil & Gas Company as Vice President and
General Manager, Offshore Division from 1992 to April 1998 and Offshore
Operations Manager from 1984 to 1992. Prior to joining Enron, he was Vice
President, Acquisitions for Conquest Petroleum for two years and, prior to his
employment with Conquest, he was employed by Tenneco Oil Company in various
engineering capacities. Mr. Lewis holds a degree from Louisiana State University
in petroleum engineering. He is a registered engineer in Texas and Louisiana and
is a member of the Society of Petroleum Engineers.
S. JAY MILNER has been Vice President, Drilling and Production of Chieftain
since 1995. From the time of Chieftain's incorporation in 1988 to 1995, he held
the position of Manager, Drilling and Production. Prior to 1988, Mr. Milner was
Manager, Drilling and Production of Chieftain Development Co. Ltd. Before
joining Chieftain Development, he was employed by Dome Petroleum Limited as a
drilling engineer. Mr. Milner holds a degree in engineering from the University
of Alberta. Mr. Milner is Stanley A. Milner's son.
RONALD J. STEFURE has been Vice President and Controller of Chieftain since
1995. From October 1989 to 1995, he was Chieftain's Controller. Prior to that
date, Mr. Stefure was Accounting Manager with Chieftain Development Co. Ltd.
HUGH J. KELLY, an energy consultant, has been a Director of Chieftain since
July 1989. Mr. Kelly served as Chief Executive Officer of Ocean Drilling &
Exploration Company from 1958 to June 1989. He was also associated with Chevron
Oil Company for seven years before joining Ocean Drilling. Mr. Kelly is a
S-37
<PAGE>
director of Tidewater Inc. and Gulf Island Fabrication Inc. and a former
director of Baroid Corporation, Central Louisiana Electric Co., and Hibernia
National Bank. He is also a former chairman of Mid-Continent Oil and Gas
Association and the National Ocean Industries Association. Mr. Kelly is a
graduate of Louisiana State University Law School.
JOHN E. MAYBIN, who is a consultant, has been a Director of Chieftain since
June 1991. He has held executive positions with various companies, including
Canadian Utilities Limited and petroleum-related organizations. Mr. Maybin, a
former director of Alberta Energy Company Ltd., Colmac Energy, Inc.,
International Mill Services Limited and Majestic Contractors Limited, is also a
former chairman of the Canadian Gas Association. Mr. Maybin is a graduate of the
University of Alberta and Princeton University.
LOUIS G. MUNIN, a financial consultant, has been a Director of Chieftain since
February 1989. A graduate of DePaul University and a certified public
accountant, Mr. Munin was engaged in public accounting with the firm of Arthur
Andersen from 1955 until 1966. After leaving Arthur Andersen, he held various
executive positions with General Portland Cement Company and its successor,
Lafarge Corporation, through 1988. He is a director of Lafarge Canada Inc. and
Walden Residential Properties, Inc. and also serves as a member of the Finance
Committee of the Board of Directors of Lafarge Corporation.
STUART T. PEELER, a petroleum industry consultant, has been a Director of
Chieftain since February 1989. A graduate of Stanford University Law,
Mr. Peeler practiced law with the firm of Musick, Peeler & Garrett from 1953
until 1973 and has held various senior positions with independent energy
companies. Mr. Peeler is a director of CalMat Co. (formerly California Portland
Cement Company), Homestake Mining Company and Homestake Gold of Australia, Ltd.
He is also a trustee of The J. Paul Getty Trust and The J. Paul Getty Museum.
S-38
<PAGE>
CERTAIN INCOME TAX CONSIDERATIONS
CANADIAN FEDERAL INCOME TAX CONSIDERATIONS FOR UNITED STATES RESIDENTS
In the opinion of Bennett Jones, Canadian counsel to Chieftain, the following is
a summary of certain of the Canadian federal income tax considerations which
will generally be applicable to holders of the common shares who are residents
of the United States ("U.S. Residents") for the purposes of the CANADA-UNITED
STATES INCOME TAX CONVENTION, 1980 (the "Convention") and are not residents of
Canada for the purposes of the INCOME TAX ACT (Canada) who deal at arm's length
with us for the purposes of the Canadian Tax Act and who do not use or hold, and
are not deemed to use or hold, such common shares in, or in the course of,
carrying on a business in Canada. This summary is based upon the current
provisions of the INCOME TAX ACT (Canada) and the regulations thereunder,
proposed amendments thereto publicly announced by the Minister of Finance,
Canada, prior to the date hereof, and the provisions of the Convention as in
effect on the date hereof.
THIS SUMMARY IS OF GENERAL NATURE ONLY AND IS NOT INTENDED TO BE LEGAL OR TAX
ADVICE TO ANY PARTICULAR U.S. RESIDENT. ACCORDINGLY, U.S. RESIDENTS SHOULD
CONSULT WITH THEIR OWN TAX ADVISORS FOR ADVICE WITH RESPECT TO THEIR OWN
PARTICULAR CIRCUMSTANCES.
A U.S. Resident will only be subject to taxation in respect of the disposition
of its common shares to the extent such shares constitute "taxable Canadian
property." Generally, common shares will constitute taxable Canadian property to
a U.S. Resident if, at any time during the five year period immediately
preceding the disposition or deemed disposition of the common shares, the U.S.
Resident, either alone or together with persons with whom the U.S. Resident did
not deal at arm's length, owned or had an interest in or an option to acquire
25% or more of the issued shares of any class or series of our capital stock, or
the U.S. Resident's common shares were acquired in a tax deferred exchange in
consideration for property that was itself "taxable Canada property."
A U.S. Resident whose common shares constitute taxable Canadian property may
nonetheless be exempted from taxation on gains to the extent that it can avail
itself of the provisions of the Convention. The Convention provides such an
exemption for a U.S. Resident, provided that the value of the common shares at
the time of disposition is not derived principally from real property situated
in Canada (including certain rights and royalties to explore for petroleum and
natural gas resources in Canada).
Dividends paid or credited or deemed to be paid or credited to a U.S. Resident
in respect of the common shares will generally be subject to Canadian
withholding tax. Currently, under the Convention, the rate of Canadian
withholding tax which would apply on dividends paid or credited or deemed to be
paid or credited by us to a U.S. Resident is (a) 5% if the beneficial owner of
the dividends is a company which owns at least 10% of our voting stock, and
(b) 15% in all other cases.
UNITED STATES FEDERAL INCOME TAX CONSIDERATIONS
In the opinion of Cravath, Swaine & Moore, U.S. counsel to Chieftain, the
following is a general description of the material U.S. federal income tax
consequences applicable to United States holders of common shares. The following
discussion deals only with common shares held as a capital asset by U.S.
holders. It does not deal with special situations, such as those of foreign
persons, dealers in securities, financial institutions, life insurance
companies, holders whose "functional currency" is not the U.S. dollar, or
certain "straddle" or hedging transactions. A "U.S. holder" is (i) a citizen or
resident of the United States for United States federal income tax purposes,
(ii) a corporation, or other entity taxable as a corporation, created or
organized under the laws of the United States or any state thereof
S-39
<PAGE>
(including the District of Columbia), (iii) an estate the income of which is
subject to United States federal income taxation regardless of its source,
(iv) a trust that is subject to the supervision of a court within the United
States and the control of one or more United States persons or (v) a person
otherwise subject to United States federal income tax on its worldwide income.
PROSPECTIVE PURCHASERS ARE URGED TO CONSULT THEIR TAX ADVISORS REGARDING THE
PARTICULAR TAX CONSEQUENCES OF PURCHASING, HOLDING AND DISPOSING OF COMMON
SHARES, INCLUDING THE TAX CONSEQUENCES ARISING UNDER ANY STATE OR LOCAL LAW.
The gross amount of a distribution with respect to common shares will include
the amount of any Canadian federal income tax withheld, and will be includible
in gross income as a taxable dividend to the extent of our current and
accumulated earnings and profits (calculated under U.S. tax principles), as a
return of capital to the extent in excess of such earnings and profits and not
in excess of the holder's tax basis in the common shares, and as capital gain to
the extent of any balance. Dividends will not be eligible for the
dividends-received deduction. Holders generally will be entitled, subject to
certain limitations, to a credit against their U.S. federal income tax for
Canadian federal income taxes withheld from such dividends. Holders may claim a
deduction for such taxes if they do not elect to claim such foreign tax credit.
If a dividend distribution is paid in Canadian dollars, the amount includible in
income will be the U.S. dollar value, on the date of receipt, of the Canadian
dollar amount distributed. Any subsequent gain or loss in respect of such
Canadian dollars arising from exchange rate fluctuations will be ordinary income
or loss.
The sale of common shares will generally result in the recognition of gain or
loss in an amount equal to the difference between the amount realized on the
sale and the holder's adjusted basis in such common shares. Gain or loss upon
the sale of the common shares will be long-term or short-term capital gain or
loss, depending on whether the common shares have been held for more than one
year.
Special rules are applicable to U.S. persons holding shares in a so-called
"passive foreign investment company" (a "PFIC"). A PFIC is any foreign
corporation if at least 75% of its gross income for the taxable year is passive
income (the "Income Test") or if at least 50% by value of the assets it holds
during the taxable year produce or are held for the production of passive income
(the "Asset Test"). For that purpose, "passive income" includes the excess of
gains over losses from certain commodities transactions, including certain
transactions involving oil and natural gas. Gains from commodities transactions,
however, are generally excluded from the definition of passive income if
"substantially all" of a merchant's, producer's or handler's business is as an
active merchant, producer or handler of such commodities.
Based upon the advice of our counsel, we believe that we are not currently, and
will not become, a PFIC. However, the application of the PFIC provisions of the
Code to oil and natural gas producers is somewhat unclear. Therefore, no
assurance can be made regarding our PFIC status.
If we are a PFIC, a U.S. holder of common shares will be subject to a special
tax regime with respect to certain dividends and with respect to gain on a
disposition of such shares (including a gift or pledge of shares). Such income
would be allocated ratably over the holder's holding period for the shares,
would be taxed, in the year of dividend or disposition, at ordinary income tax
rates (using the highest tax rate in effect for each period to which the income
is allocated), and would be subject to an interest charge reflecting the
deferral of tax from the year to which the income was allocated to the year of
dividend or disposition.
United States reporting requirements may apply with respect to the payment of
dividends on the common shares. Certain noncorporate U.S. holders may be subject
to backup withholding at the rate of 31% with respect to dividends when a U.S.
holder (i) fails to furnish or certify a correct taxpayer
S-40
<PAGE>
identification number to the payor in the manner required, (ii) is notified by
the Internal Revenue Service that it has failed to report payments of interest
or dividends properly or (iii) fails, under certain circumstances, to certify
that it has not been notified by the Internal Revenue Service that it is subject
to backup withholding for failure to report interest and dividend payments. The
amount of any backup withholding from a payment to a U.S. Holder will be allowed
as a credit against the U.S. Holder's United States federal income tax
liability.
S-41
<PAGE>
UNDERWRITING
Chieftain has entered into an underwriting agreement with the underwriters named
below. CIBC World Markets Corp., Dain Rauscher Wessels, a division of Dain
Rauscher Incorporated, and A.G. Edwards & Sons, Inc. are acting as
representatives of the underwriters.
The underwriting agreement provides for the purchase of a specific number of the
common shares by each of the underwriters. The underwriters' obligations are
several, which means that each underwriter is required to purchase a specified
number of shares, but is not responsible for the commitment of any other
underwriter to purchase shares. Subject to the terms and conditions of the
underwriting agreement, each underwriter has severally agreed to purchase the
number of common shares set forth opposite its name below:
<TABLE>
<CAPTION>
UNDERWRITERS NUMBER OF SHARES
- ------------ ----------------
<S> <C>
CIBC World Markets Corp. ...................................
Dain Rauscher Wessels.......................................
A.G. Edwards & Sons, Inc. ..................................
----------------
Total................................................. 2,500,000
================
</TABLE>
The underwriters will offer the common shares in the U.S. The underwriters may
also offer the common shares in Canada through their Canadian affiliates in
private transactions.
The underwriters have agreed to purchase all of the shares offered by this
prospectus supplement (other than those covered by the over-allotment option
described below) if any are purchased. Under the underwriting agreement, if an
underwriter defaults in its commitment to purchase shares, the commitments of
non-defaulting underwriters may be increased or the underwriting agreement may
be terminated, depending on the circumstances.
The shares should be ready for delivery on or about , 1999 against payment
in immediately available funds. The representatives have advised Chieftain that
the underwriters propose to offer the shares directly to the public at the
public offering price that appears on the cover page of this prospectus
supplement. In addition, the representatives may offer some of the shares to
certain securities dealers at the initial offering price less a concession of
$ per share. The underwriters may also allow, and the dealers may reallow,
a concession not in excess of $ per share to other dealers. After the
shares are released for sale to the public, the representatives may change the
offering price and other selling terms at various times.
Chieftain has granted the underwriters an over-allotment option. This option,
which is exercisable for up to 30 days after the date of this prospectus
supplement, permits the underwriters to purchase a maximum of 375,000 additional
common shares from Chieftain to cover over-allotments. If the underwriters
exercise all or part of this option, they will purchase shares covered by the
option at the initial public offering price that appears on the cover page of
this prospectus supplement, less the underwriting discount. If this option is
exercised in full, the total price to the public will be $ million
and the total proceeds to Chieftain will be $ million. The underwriters
have severally agreed that, to the extent the over-allotment option is
exercised, they will each purchase a
S-42
<PAGE>
number of additional shares proportionate to the underwriters' initial amount
reflected in the foregoing table.
The following table provides information regarding the amount of the discount to
be paid to the underwriters by Chieftain:
<TABLE>
<CAPTION>
TOTAL WITHOUT TOTAL WITH FULL
EXERCISE OF OVER- EXERCISE OF
ALLOTMENT OVER-ALLOTMENT
PER SHARE OPTION OPTION
- --------------------- ----------------- ---------------
<S> <C> <C>
$ $ $
</TABLE>
Chieftain estimates that its total expenses of the offering, excluding the
underwriting discount, will be approximately $ .
Chieftain has agreed to indemnify the underwriters against certain liabilities,
including liabilities under the Securities Act of 1933.
The common shares have not been and will not be qualified for public
distribution under the securities laws of Canada or any province or territory of
Canada. The common shares are not being and may not be offered or sold, directly
or indirectly, in Canada in violation of the securities laws of Canada or any
province or territory of Canada. Each underwriter has agreed that, except
pursuant to exemptions under applicable securities laws in Canada, it will not
offer or sell the common shares offered hereby within Canada.
Chieftain's directors and officers have agreed to a 90-day "lock-up" with
respect to the common shares and certain other Chieftain securities that they
beneficially own, including securities that are convertible into common shares
and securities that are exchangeable or exercisable for common shares. This
means that, subject to the exceptions described below, for a period of 90 days
following the date of this prospectus supplement, such persons may not offer,
sell, pledge or otherwise dispose of such Chieftain securities without the prior
written consent of CIBC World Markets Corp. As part of this lock-up, Chieftain
has also agreed not to issue common shares or other securities that are
convertible into common shares and securities that are exchangeable or
exercisable for common shares, except as described below, for the period of 90
days following the date of this prospectus supplement.
The lock-up does not restrict Chieftain from:
- granting options to purchase common shares pursuant to Chieftain's Share
Option Plan;
- issuing common shares pursuant to the exercise of the options granted under
the Share Option Plan; or
- issuing common shares pursuant to the exercise of conversion rights attached
to outstanding preferred shares issued by Chieftain's subsidiary, Chieftain
International Funding Corp.
Rules of the Securities and Exchange Commission may limit the ability of the
underwriters to bid for or purchase shares before the distribution of the shares
is completed. However, the underwriters may engage in the following activities
in accordance with applicable United States law:
- Stabilizing transactions--The representatives may make bids or purchases for
the purpose of pegging, fixing or maintaining the price of the shares, so
long as stabilizing bids do not exceed a specified maximum.
S-43
<PAGE>
- Over-allotments and syndicate covering transactions--The underwriters may
create a short position in the shares by selling more shares than are set
forth on the cover page of this prospectus supplement. If a short position is
created in connection with the offering, the representatives may engage in
syndicate covering transactions by purchasing the shares in the open market.
The representatives may also elect to reduce any short position by exercising
all or part of the over-allotment option.
- Penalty bids--If the representatives purchase shares in the open market in a
stabilizing transaction or syndicate covering transaction, they may reclaim a
selling concession from the underwriters and selling group members who sold
these shares as part of this offering.
- Passive market making--Market makers in the shares who are underwriters or
prospective underwriters may make bids for or purchases of shares, subject to
certain limitations, until the time, if ever, at which a stabilizing bid is
made.
Stabilization and syndicate covering transactions may cause the price of the
shares to be higher than it would be in the absence of such transactions. The
imposition of a penalty bid might also have an effect on the price of the shares
if it discourages resales of the shares.
Neither Chieftain nor the underwriters make any representation or prediction as
to the effect that the transactions described above may have on the price of the
shares. These transactions may occur on the American Stock Exchange or the
Toronto Stock Exchange or otherwise. If such transactions are commenced, they
may be discontinued without notice at any time.
From time to time, CIBC World Market Corp. provides financial advisory services
to Chieftain for which it receives customary compensation. CIBC Mellon Trust
Company, an affiliate of CIBC World Market Corp., is Chieftain's transfer agent
and registrar for the common shares in Canada. Chieftain may use more than ten
percent of the net proceeds of the sale of the shares to repay indebtedness it
owes to Canadian Imperial Bank of Commerce, an affiliate of CIBC World Markets
Corp. Therefore, the offering is being made in compliance with the requirements
of Rule 2710(c)(8) of the National Association of Securities Dealers, Inc.
Conduct Rules.
LEGAL MATTERS
The U.S. tax matters referred to under "Certain Income Tax Considerations" and
certain other legal matters relating to the issue of the common shares will be
passed on by Cravath, Swaine & Moore on our behalf. The Canadian tax matters
referred to under "Certain Income Tax Considerations" and certain other Canadian
legal matters relating to the issue of the shares offered hereby will be passed
on by Bennett Jones on our behalf. Certain legal matters relating to the issue
of the common shares will be passed on for the underwriters by Andrews & Kurth
L.L.P.
S-44
<PAGE>
EXPERTS
The audited financial statements included or incorporated by reference in this
prospectus supplement have been audited by PricewaterhouseCoopers LLP, as
indicated in their reports with respect to such audited financial statements,
and are included or incorporated by reference in reliance upon the authority of
such firm as experts in giving such reports. PricewaterhouseCoopers LLP is
located at 1501 TD Tower, 10088 - 102 Avenue, Edmonton, Alberta, Canada,
T5J 2Z1.
The reserve estimates, relating to our U.S. reserves, of Netherland, Sewell &
Associates, Inc. included or incorporated by reference in this prospectus
supplement and the accompanying prospectus have been included in or incorporated
by reference in reliance upon the authority of such firm as experts in petroleum
engineering.
TRANSFER AGENTS AND REGISTRARS
The transfer agent and registrar for our common shares in Canada is CIBC Mellon
Trust Company at its principal office located in each of the cities of Calgary
and Toronto. The transfer agent and registrar for our common shares in the
United States is ChaseMellon Shareholder Services of New York at its principal
office located in the City of New York.
S-45
<PAGE>
CHIEFTAIN INTERNATIONAL, INC.
AND SUBSIDIARY COMPANIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
<TABLE>
<CAPTION>
PAGE
--------
<S> <C>
Audited Consolidated Financial Statements
Auditors' Report.......................................... F-2
Consolidated Balance Sheet................................ F-3
Consolidated Statement of Income (Loss) and Deficit....... F-4
Consolidated Statement of Changes in Financial Position... F-5
Notes to Consolidated Financial Statements................ F-6
Unaudited Consolidated Condensed Financial Statements
Consolidated Condensed Balance Sheet...................... F-24
Consolidated Condensed Statement of Income (Loss)......... F-25
Consolidated Condensed Statement of Cash Flows............ F-26
Notes to Consolidated Condensed Financial Statements...... F-27
</TABLE>
F-1
<PAGE>
AUDITORS' 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.
PricewaterhouseCoopers LLP
Chartered Accountants
Edmonton, Alberta
February 4, 1999
F-2
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED BALANCE SHEET
(U.S. $ IN THOUSANDS EXCEPT SHARE DATA)
(Full Cost Method of Accounting)
<TABLE>
<CAPTION>
AS AT DECEMBER 31,
---------------------
1998 1997
--------- ---------
<S> <C> <C>
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
========= =========
</TABLE>
Approved by the Board
<TABLE>
<S> <C>
/s/ S. A. Milner /s/ L. G. Munin
- -------------------------------------------- --------------------------------------------
S. A. Milner, Director L. G. Munin, Director
</TABLE>
See Notes to Consolidated Financial Statements.
F-3
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF INCOME
(LOSS) AND DEFICIT
(U.S. $ IN THOUSANDS EXCEPT SHARES AND PER SHARE AMOUNTS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------
1998 1997 1996
---------- ---------- ----------
<S> <C> <C> <C>
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
========== ========== ==========
</TABLE>
See Notes to Consolidated Financial Statements.
F-4
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED STATEMENT OF
CHANGES IN FINANCIAL POSITION
(U.S. $ IN THOUSANDS)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
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 natural 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
======== ======== ========
</TABLE>
See Notes to Consolidated Financial Statements.
F-5
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
DECEMBER 31, 1998, 1997 AND 1996
The Company is engaged in natural 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 natural gas industry
credit risks. Long-term debt is subject to normal floating interest rate risk.
(E) NATURAL RESOURCE PROPERTIES
The Company accounts for natural gas and oil properties in accordance with
Canadian guidelines on full cost accounting.
F-6
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
Under this method, all costs associated with the acquisition, exploration and
development of natural 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 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 natural 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:
<TABLE>
<CAPTION>
AS AT DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
<S> <C> <C> <C>
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
====== ====== ======
</TABLE>
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:
<TABLE>
<CAPTION>
NATURAL GAS CRUDE OIL & NGLS
(PER MCF) (PER BARREL)
----------- ----------------
<S> <C> <C>
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
===== =====
</TABLE>
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).
F-7
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (CONTINUED)
General and administrative costs relating directly to lease acquisition,
exploration and development activities have been capitalized as follows:
<TABLE>
<CAPTION>
AS AT DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C>
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
======= ======= =======
</TABLE>
At December 31, 1998, Libyan property carrying costs of $9.9 million
(1997--$14.6 million) were excluded from depletion calculations pending
evaluation.
(F) LAND, BUILDINGS AND OTHER EQUIPMENT
Amortization is provided as follows:
<TABLE>
<CAPTION>
RATE PER
ANNUM METHOD
-------- -------------
<S> <C> <C>
Buildings............................................. 5% Straight-line
Furniture, office equipment and leasehold
improvements........................................ 10-20% Straight-line
</TABLE>
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 ARRANGEMENTS
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
F-8
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
2. REVOLVING CREDIT AND TERM LOAN ARRANGEMENTS (CONTINUED)
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.
4. SHARE CAPITAL
(A) COMMON SHARES
<TABLE>
<CAPTION>
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
---------- --------- ---------- --------- ---------- ---------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
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
========== ========= ========== ========= ========== =========
</TABLE>
- ------------------------
* 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.
F-9
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
4. SHARE CAPITAL (CONTINUED)
(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.
The following is a summary of activity related to the Plan for the years ended
December 31, 1998, 1997 and 1996.
<TABLE>
<CAPTION>
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
--------- -------- --------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C>
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
========= ========= =======
</TABLE>
F-10
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
4. SHARE CAPITAL (CONTINUED)
The following table summarizes information about options outstanding at
December 31, 1998.
<TABLE>
<CAPTION>
OPTIONS OUTSTANDING OPTIONS EXERCISABLE
- ---------------------------------------------------------- -------------------
WEIGHTED
AVERAGE WEIGHTED WEIGHTED
NUMBER REMAINING AVERAGE NUMBER AVERAGE
RANGE OF OF CONTRACTUAL OPTION OF OPTION
OPTION PRICES SHARES LIFE PRICE SHARES PRICE
- --------------------- --------- ----------- -------- -------- --------
<S> <C> <C> <C> <C> <C>
$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
========= =======
</TABLE>
5. INTEREST AND OTHER REVENUE
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 judgment 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:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1998 1997 1996
------------------- ------------------- -------------------
CANADA US CANADA US CANADA US
-------- -------- -------- -------- -------- --------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
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
======== ======= ======== ======== ======== ========
</TABLE>
F-11
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
6. INCOME TAXES (CONTINUED)
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:
<TABLE>
<CAPTION>
1998 1997 1996
------------------- ------------------- -------------------
CANADA US CANADA US CANADA US
-------- -------- -------- -------- -------- --------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
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
======== ======== ======= ======= ====== ========
</TABLE>
The actual tax rate differs from the expected tax rate for the following
reasons:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C>
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%
======== ======== ========
</TABLE>
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.
F-12
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
8. PENSION 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.
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 natural 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 natural gas, oil and
liquids.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C>
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
========= ========= =========
</TABLE>
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.
F-13
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
10. UNCERTAINTY DUE TO THE YEAR 2000 (CONTINUED)
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.
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
natural gas and oil prices of $2.15 per Mcf and $9.72 per barrel, and June 30 US
natural 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.
F-14
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
11. UNITED STATES ACCOUNTING PRINCIPLES (CONTINUED)
(D) EFFECT ON EARNINGS
The effect on consolidated earnings of the differences between Canadian and
US accounting principles is summarized as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------------------
1998 1997 1996
------------ ------------ ------------
(U.S. $ IN THOUSANDS
EXCEPT SHARES AND PER SHARE AMOUNTS)
<S> <C> <C> <C>
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
============ ============ ============
</TABLE>
(E) EFFECT ON BALANCE SHEET
The effect on the Consolidated Balance Sheet of the differences between
Canadian and US accounting principles is as follows:
<TABLE>
<CAPTION>
AS AT DECEMBER 31,
---------------------------------------------
1998 1997
--------------------- ---------------------
UNDER US UNDER US
AS ACCOUNTING AS ACCOUNTING
REPORTED PRINCIPLES REPORTED PRINCIPLES
-------- ---------- -------- ----------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C> <C>
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)
</TABLE>
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-15
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
11. UNITED STATES ACCOUNTING PRINCIPLES (CONTINUED)
(F) INCOME TAX DISCLOSURES
Deferred tax assets (liabilities) are comprised of the following:
<TABLE>
<CAPTION>
AS AT DECEMBER 31,
------------------------
1998 1997
--------- ---------
(U.S. $ IN THOUSANDS)
<S> <C> <C>
Deferred tax assets
Depletion and amortization........................ $ 6,971 $ 3,413
Financing costs................................... 390 633
Loss carry forwards............................... 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)
========= =========
</TABLE>
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.
Provisions for deferred income taxes are as follows:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------
1998 1997 1996
--------------------- ------------------- -------------------
CANADA US CANADA US CANADA US
--------- --------- -------- -------- -------- --------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C> <C> <C> <C>
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
========= ========= ======== ======== ======== ========
</TABLE>
F-16
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (CONTINUED)
DECEMBER 31, 1998, 1997 AND 1996
11. UNITED STATES ACCOUNTING PRINCIPLES (CONTINUED)
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:
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C>
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%
========= ========= =========
</TABLE>
(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.
F-17
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
SUPPLEMENTARY FINANCIAL INFORMATION
(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:
<TABLE>
<CAPTION>
CRUDE OIL &
NATURAL GAS--MMCF NGLS--
------------------------------------ BARRELS*
UNITED STATES NORTH SEA TOTAL UNITED STATES
------------- --------- -------- -------------
<S> <C> <C> <C> <C>
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
======= ====== ======= ===========
</TABLE>
TOTAL PROVED RESERVES AFTER ROYALTY DEDUCTIONS:
<TABLE>
<CAPTION>
CRUDE OIL &
NATURAL GAS--MMCF NGLS--
------------------------------------ BARRELS*
UNITED STATES NORTH SEA TOTAL UNITED STATES
------------- --------- -------- -------------
<S> <C> <C> <C> <C>
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
======= ====== ======= ===========
</TABLE>
- ------------------------
* 26,800 (1997--58,900) barrels of natural gas liquids, before and after
royalty deductions, associated with the UK natural gas reserves are not
included in this table.
F-18
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
SUPPLEMENTARY FINANCIAL INFORMATION
(UNAUDITED)
PROVED DEVELOPED PRODUCING RESERVES BEFORE ROYALTY DEDUCTIONS:
<TABLE>
<CAPTION>
NATURAL GAS--MMCF
------------------------------ CRUDE OIL & NGLS--BARRELS
UNITED UNITED UNITED
STATES KINGDOM TOTAL STATES
-------- -------- -------- -------------------------
<S> <C> <C> <C> <C>
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
====== ====== ====== =========
</TABLE>
PROVED DEVELOPED PRODUCING RESERVES AFTER ROYALTY DEDUCTIONS:
<TABLE>
<CAPTION>
NATURAL GAS--MMCF
------------------------------ CRUDE OIL & NGLS--BARRELS
UNITED UNITED UNITED
STATES KINGDOM TOTAL STATES
-------- -------- -------- -------------------------
<S> <C> <C> <C> <C>
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
====== ====== ====== =========
</TABLE>
RESULTS OF OPERATIONS FOR NATURAL GAS AND OIL PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------------
1998 1997 1996
-------- -------- --------
(U.S.$ IN THOUSANDS)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
F-19
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
SUPPLEMENTARY FINANCIAL INFORMATION
(UNAUDITED)
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31
------------------------------
1998 1997 1996
-------- -------- --------
(U.S.$ IN THOUSANDS)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
CAPITALIZED COSTS RELATING TO NATURAL GAS AND OIL EXPLORATION AND PRODUCTION
ACTIVITIES
<TABLE>
<CAPTION>
AS AT DECEMBER 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(U.S.$ IN THOUSANDS)
<S> <C> <C> <C>
Proved natural gas and oil properties.................. $ 475,902 $ 402,885 $ 337,538
Unproved natural 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
========= ========= =========
</TABLE>
F-20
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
SUPPLEMENTARY FINANCIAL INFORMATION
(UNAUDITED)
COSTS INCURRED IN NATURAL GAS AND OIL PROPERTY ACQUISITION, EXPLORATION AND
DEVELOPMENT ACTIVITIES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
------------------------------
1998 1997 1996
-------- -------- --------
(U.S.$ IN THOUSANDS)
<S> <C> <C> <C>
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
======== ======== ========
</TABLE>
F-21
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
(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.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C>
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) (1,450) (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) (75,016) (97,533)
--------- --------- ---------
Standardized measure of discounted future net cash
flows................................................... $ 152,508 $ 199,573 $ 239,023
========= ========= =========
</TABLE>
F-22
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES (CONTINUED)
(UNAUDITED)
The following table sets out principal sources of change in the standardized
measure of discounted future net cash flows during the respective periods.
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31,
---------------------------------
1998 1997 1996
--------- --------- ---------
(U.S. $ IN THOUSANDS)
<S> <C> <C> <C>
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
========= ========= =========
</TABLE>
QUARTERLY FINANCIAL INFORMATION
<TABLE>
<CAPTION>
GROSS INCOME PER COMMON
QUARTER ENDED REVENUE PROFIT (LOSS) SHARE
- ------------- -------- -------- -------- ----------
(U.S. $ IN THOUSANDS, EXCEPT PER SHARE AMOUNTS)
<S> <C> <C> <C> <C>
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
</TABLE>
F-23
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED BALANCE SHEET
(U.S. $ IN THOUSANDS)
(Full Cost Method of Accounting)
<TABLE>
<CAPTION>
SEPTEMBER 30, DECEMBER 31,
1999 1998
------------- ------------
(UNAUDITED)
<S> <C> <C>
ASSETS
Current assets:
Cash and short-term deposits.............................. $ 597 $ 10,613
Accounts receivable....................................... 20,111 14,030
Other..................................................... 792 282
--------- ---------
21,500 24,925
Capital assets--net......................................... 275,471 288,477
Deferred income taxes....................................... 10,892 5,182
--------- ---------
$ 307,863 $ 318,584
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued.............................. $ 16,791 $ 22,533
Long-term debt.............................................. 45,000 40,000
Abandonment cost accrual.................................... 8,305 7,421
Deferred income taxes....................................... 13,978 13,684
Shareholders' equity:
Preferred shares of a subsidiary.......................... 63,403 63,403
Common shares............................................. 189,010 189,108
Contributed surplus....................................... 26 --
Deficit................................................... (28,650) (17,565)
--------- ---------
223,789 234,946
--------- ---------
$ 307,863 $ 318,584
========= =========
</TABLE>
See Notes to the Consolidated Condensed Financial Statements.
F-24
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENT OF INCOME (LOSS)
(U.S. $ IN THOUSANDS EXCEPT SHARES AND PER SHARE AMOUNTS)
(UNAUDITED)
<TABLE>
<CAPTION>
PERIOD ENDED SEPTEMBER 30,
-----------------------------------------------------
NINE MONTHS THREE MONTHS
------------------------- -------------------------
1999 1998 1999 1998
----------- ----------- ----------- -----------
<S> <C> <C> <C> <C>
Production revenue, net of royalties...... $ 52,954 $ 44,852 $ 22,569 $ 13,822
Interest and other revenue (Note 2)....... 570 2,613 194 121
----------- ----------- ----------- -----------
53,524 47,465 22,763 13,943
Production costs.......................... 10,985 12,219 3,623 4,206
General and administrative expenses....... 3,354 3,668 981 917
Interest.................................. 1,867 285 666 260
Depletion and amortization................ 38,711 30,096 13,619 9,905
Additional depletion: Libyan properties
(Note 3)................................ 11,393 -- -- --
----------- ----------- ----------- -----------
66,310 46,268 18,889 15,288
----------- ----------- ----------- -----------
Income (loss) before income taxes and
dividends on a preferred shares of a
subsidiary.............................. (12,786) 1,197 3,874 (1,345)
Income taxes (Note 4)..................... (5,408) 1,141 1,356 (109)
----------- ----------- ----------- -----------
Income (loss) before dividends on
preferred shares of a subsidiary........ (7,378) 56 2,518 (1,236)
Dividends on preferred shares of
a subsidiary............................ 3,707 3,707 1,236 1,236
----------- ----------- ----------- -----------
Net income (loss) applicable to
common shares........................... $ (11,085) $ (3,651) $ 1,282 $ (2,472)
=========== =========== =========== ===========
Net income (loss) per common share
(Note 5):
--Basic............................... $ (0.83) $ (0.27) $ 0.10 $ (0.18)
=========== =========== =========== ===========
--Fully diluted....................... $ (0.83) $ (0.27) $ 0.10 $ (0.18)
=========== =========== =========== ===========
Weighted average number of common shares
outstanding:
--Basic............................... 13,350,383 13,520,786 13,348,645 13,438,005
=========== =========== =========== ===========
--Fully diluted....................... 13,350,383 13,520,786 13,348,645 13,438,005
=========== =========== =========== ===========
</TABLE>
See Notes to Consolidated Condensed Financial Statements.
F-25
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
CONSOLIDATED CONDENSED STATEMENT OF
CASH FLOWS
(U.S. $ IN THOUSANDS)
(UNAUDITED)
<TABLE>
<CAPTION>
NINE MONTHS ENDED SEPTEMBER 30,
-------------------------------
1999 1998
-------------- --------------
<S> <C> <C>
Operating activities:
Net income (loss) applicable to common shares............. $ (11,085) $ (3,651)
Items not requiring a current cash outlay................. 44,688 31,210
--------- ---------
33,603 27,559
Net change in non-cash operating working capital (Note
6)...................................................... (6,358) (713)
--------- ---------
27,245 26,846
Financing activities:
Increase in long-term debt................................ 5,000 25,000
Purchase of common shares for cancellation................ (80) (5,355)
Issue of common shares.................................... 9 437
--------- ---------
4,929 20,082
Investing activities:
Lease acquisition, exploration and drilling costs......... (30,270) (55,847)
Pipelines and production equipment acquired............... (6,072) (10,351)
Sale of producing properties.............................. 155 --
--------- ---------
(36,187) (66,198)
Purchase of other capital assets.......................... (28) (87)
Change in investing accounts payable and accrued.......... (5,975) (1,465)
--------- ---------
(42,190) (67,750)
--------- ---------
Change in cash and short-term deposits.................... (10,016) (20,822)
Beginning cash and short-term deposits.................... 10,613 26,925
--------- ---------
Ending cash and short-term deposits....................... $ 597 $ 6,103
========= =========
</TABLE>
See Notes to Consolidated Condensed Financial Statements.
F-26
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS
SEPTEMBER 30, 1998 AND 1999
(UNAUDITED)
1. BASIS OF PRESENTATION
In the opinion of Chieftain International, Inc. (the "Company" and together
with its subsidiaries "Chieftain"), the accompanying unaudited consolidated
condensed financial statements contain all adjustments (consisting of only
normal recurring accruals) necessary to present fairly the financial position as
at September 30, 1999 and December 31, 1998 and the results of operations and
cash flows for the nine month periods ended September 30, 1999 and 1998. Certain
information and notes normally included in Chieftain's financial statements
prepared in conformity with Canadian generally accepted accounting principles
have been condensed or omitted pursuant to the rules and regulations of the
Securities and Exchange Commission. These consolidated condensed financial
statements should be read in conjunction with the audited consolidated financial
statements and the notes thereto included in Chieftain's Annual Report on
Form 10-K for the year ended December 31, 1998.
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.
The results of operations and cash flows for the nine month period ended
September 30, 1999 are not necessarily indicative of the results to be expected
for the full year.
Material differences between Canadian and US accounting principles that affect
Chieftain are referred to in Note 7, which provides the effects of such
differences on earnings and balance sheet accounts.
2. INTEREST AND OTHER REVENUE
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 judgment interest in the
amounts of $1,129,000, $282,000 and $189,000, respectively.
3. ADDITIONAL DEPLETION
Additional depletion of $11.4 million arises from the termination of an
exploration program and production test in Libya.
F-27
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (CONTINUED)
SEPTEMBER 30, 1998 AND 1999
(UNAUDITED)
4. INCOME TAXES
The provision for income taxes differs from the amount of income tax
determined by applying the Canadian statutory rate to pre-tax income (loss)
before dividends paid on preferred shares of a subsidiary as a result of the
following:
<TABLE>
<CAPTION>
NINE MONTHS ENDED THREE MONTHS ENDED
SEPTEMBER 30, SEPTEMBER 30,
------------------- -------------------
1999 1998 1999 1998
-------- -------- -------- --------
(U.S.$ IN THOUSANDS)
<S> <C> <C> <C> <C>
Tax at statutory Canadian rate
44.62%............................. $ (5,705) $ 534 $ 1,729 $ (603)
Lower income tax rate on earnings of
US subsidiaries.................... (76) (144) (407) 95
Canadian income tax on exchange loss
(gain) which is eliminated upon
consolidation...................... 634 220 41 47
Prior years' tax reassessments....... -- 208 -- 208
Exchange revaluation of Canadian
deferred tax assets................ (289) 222 (9) 105
Other................................ 28 101 2 39
-------- -------- -------- --------
Tax at effective rate................ $ (5,408) $ 1,141 $ 1,356 $ (109)
======== ======== ======== ========
Effective tax rate................... 42.3% 95.3% 35.0% 8.1%
======== ======== ======== ========
</TABLE>
5. 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 period.
In the calculation of fully diluted earnings per share, shares outstanding are
adjusted for share options and shares issuable on conversion of preferred shares
were dilutive. Earnings are adjusted by the amount of imputed interest on share
option proceeds and preferred share dividends.
6. SUPPLEMENTAL CASH FLOW INFORMATION
Cash outflows for (inflows from) income taxes during the 1999 third quarter
were $(29,000) (year-to-date--$(12,000)) (1998--third quarter--$14,000;
year-to-date--$41,000). Cash outflows for long-term debt interest during the
1999 third quarter were $653,000 (year-to-date--$1,804,000) (1988--
third-quarter--$156,000; year-to-date--$156,000).
F-28
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (CONTINUED)
SEPTEMBER 30, 1998 AND 1999
(UNAUDITED)
7. UNITED STATES ACCOUNTING PRINCIPLES
(A) FULL COST ACCOUNTING
US full cost accounting rules differ materially from the Canadian full cost
accounting guidelines followed by Chieftain. The US rules require an impairment
test to be conducted quarterly whereas the Canadian guidelines require this test
only at year-end. 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. The quarterly test required
by US accounting rules, using a March 31, 1999 UK natural gas price of $0.84 per
mcf to determine future net revenues, would have resulted in a write-down of UK
property carrying costs at March 31, 1999 of $7.1 million and, after providing
for tax recoveries of $3.1 million, a net charge to operations of $4.0 million.
Using June 30, 1998 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 at June 30, 1998 of $24.7 million and, after providing
for tax recoveries of $8.6 million, a net charge to operations of
$16.1 million.
(B) EFFECT ON EARNINGS
The effect on consolidated earnings of these differences is summarized as
follows:
<TABLE>
<CAPTION>
NINE MONTHS ENDED
SEPTEMBER 30,
-----------------------------------
1999 1998
-------------- --------------
(U.S. $ IN THOUSANDS, EXCEPT SHARES
AND PER SHARE AMOUNTS)
<S> <C> <C>
Net income (loss) applicable to common shares as
reported...................................... $ (11,085) $ (3,651)
Additional depletion............................ (7,104) (24,725)
----------- -----------
(18,189) (28,376)
Add reduction in depletion expense.............. 13,122 2,631
Decrease (increase) in deferred tax provision... (1,656) 7,449
----------- -----------
Net income (loss) applicable to common shares
under
US accounting principles...................... $ (6,723) $ (18,296)
=========== ===========
Net income (loss) per common share under
US accounting principles:
--Basic................................... $ (0.50) $ (1.35)
=========== ===========
--Fully diluted........................... $ (0.50) $ (1.35)
=========== ===========
Fully diluted number of common shares
outstanding................................... 13,350,383 13,520,786
=========== ===========
</TABLE>
F-29
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (CONTINUED)
SEPTEMBER 30, 1998 AND 1999
(UNAUDITED)
<TABLE>
<CAPTION>
THREE MONTHS ENDED
SEPTEMBER 30
-----------------------------------
1999 1998
-------------- --------------
(U.S. $ IN THOUSANDS, EXCEPT SHARES
AND PER SHARE AMOUNTS)
<S> <C> <C>
Net income (loss) applicable to common shares as
reported...................................... $ 1,282 $ (2,472)
----------- -----------
Add reduction in depletion expense.............. 4,926 1,212
Decrease (increase) in deferred tax provision... (1,830) (708)
----------- -----------
Net income (loss) applicable to common shares
under
US accounting principles...................... $ 4,378 $ (1,968)
=========== ===========
Net income (loss) per common share under
US accounting principles:
--Basic................................... $ 0.33 $ (0.15)
=========== ===========
--Fully diluted........................... $ 0.32 $ (0.15)
=========== ===========
Fully diluted number of common shares
outstanding................................... 13,493,458 13,438,005
=========== ===========
</TABLE>
(C) EFFECT ON BALANCE SHEET
The effect on the Consolidated Condensed Balance Sheet of the differences
between Canadian and US accounting principles is as follows:
<TABLE>
<CAPTION>
AS AT AS AT
SEPTEMBER 30, 1999 DECEMBER 31, 1998
----------------------- -----------------------
UNDER US UNDER US
AS ACCOUNTING AS ACCOUNTING
REPORTED PRINCIPLES REPORTED PRINCIPLES
---------- ---------- ---------- ----------
(U.S.$ IN THOUSANDS)
<S> <C> <C> <C> <C>
Net capital assets............ $ 275,471 $ 178,529 $ 288,477 $ 185,517
Deferred tax--asset........... $ 10,892 $ 31,993 $ 5,182 $ 28,233
Deferred tax--liability....... $ 13,978 $ -- $ 13,684 $ --
Deficit....................... $ (28,650) $ (90,513) $ (17,565) $ (83,790)
</TABLE>
Additionally for U.S. reporting purposes, the preferred shares shown as
shareholders' equity in these consolidated condensed financial statements would
be shown outside the equity section.
F-30
<PAGE>
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
NOTES TO CONSOLIDATED CONDENSED FINANCIAL STATEMENTS (CONTINUED)
SEPTEMBER 30, 1998 AND 1999
(UNAUDITED)
(D) 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. For the nine months ended September 30, 1999 such impact would amount
to a net of tax charge to income (loss) of $946,000 (1998--$1,270,000) and for
the three months ended September 30, such impact would amount to a net of tax
charge to income (loss) of $355,000 (1998--$397,000). Under US accounting
principles after reflecting this charge, for the nine months ended
September 30, pro forma net income (loss) applicable to common shares would be
$(7,669,000) (1998--($19,566,000)); net income (loss) per common share would be
$(0.57) (1998--$(1.45)); and pro forma fully diluted earnings (loss) per common
share would be $(0.57) (1998--$(1.45)). For the three months ended
September 30, pro forma net income (loss) applicable to common shares under US
accounting principles would be $4,023,000 (1998--$(2,365,000)); pro forma net
income (loss) per common share would be $0.30 (1998--$(0.18)); and pro forma
fully diluted earnings (loss) per common share would be $0.30 (1998--$(0.18)).
These effects are not necessarily indicative of those to be expected in future
periods.
F-31
<PAGE>
PROSPECTUS
$300,000,000
[LOGO]
CHIEFTAIN INTERNATIONAL, INC.
COMMON SHARES, PREFERRED SHARES,
DEBT SECURITIES AND WARRANTS
- --------------------------------------------------------------------------------
We will offer and sell from time to time Chieftain common shares, preferred
shares, debt securities, or warrants. We will provide specific terms of these
securities in supplements to this prospectus. The terms of the securities will
include the initial offering price, aggregate amount of the offering, listing on
any securities exchange or quotation system, risk factors and the agents,
dealers or underwriters, if any, to be used in connection with the sale of these
securities. You should read this prospectus and any supplement together with any
and all documents incorporated by reference herein and in any supplement
carefully before you invest.
Our common shares are listed on the American Stock Exchange and The Toronto
Stock Exchange under the symbol "CID."
INVESTING IN OUR SECURITIES INVOLVES RISKS. SEE "RISK FACTORS" ON PAGE 6.
- --------------------------------------------------------------------------------
NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES, OR DETERMINED IF
THIS PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.
THE DATE OF THIS PROSPECTUS IS OCTOBER 20, 1999.
<PAGE>
TABLE OF CONTENTS
<TABLE>
<CAPTION>
PAGE
---------
<S> <C>
About This Prospectus....................................... 3
Enforcement of Civil Liabilities............................ 3
Where You Can Find More Information......................... 3
Forward-Looking Statements.................................. 4
Chieftain................................................... 5
Risk Factors................................................ 6
Ratios of Earnings to Fixed Charges......................... 8
Use of Proceeds............................................. 9
Description of Share Capital................................ 9
Description of Debt Securities.............................. 14
Description of Warrants..................................... 19
Plan of Distribution........................................ 21
Legal Matters............................................... 22
Experts..................................................... 22
</TABLE>
----------------------------
YOU SHOULD RELY ONLY ON THE INFORMATION WE HAVE INCLUDED OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS. WE HAVE NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH
ADDITIONAL OR DIFFERENT INFORMATION. IF YOU RECEIVE ANY UNAUTHORIZED
INFORMATION, YOU MUST NOT RELY ON IT. WE ARE OFFERING TO SELL THE SECURITIES
ONLY IN JURISDICTIONS WHERE SALES ARE PERMITTED. YOU SHOULD NOT ASSUME THAT THE
INFORMATION WE HAVE INCLUDED IN THIS PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER
THAN THE DATE OF THIS PROSPECTUS OR THAT ANY INFORMATION WE HAVE INCORPORATED BY
REFERENCE IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE OF THE DOCUMENT
INCORPORATED BY REFERENCE.
2
<PAGE>
ABOUT THIS PROSPECTUS
This prospectus is part of a registration statement that we filed with the SEC
using a "shelf" registration process. Under the shelf registration process, we
may sell any combination of the securities described in this prospectus in one
or more offerings up to a total dollar amount of $300,000,000. This prospectus
provides you with a general description of the securities we may offer. Each
time we sell securities, we will provide a prospectus supplement that will
contain specific information about the terms of that offering. The prospectus
supplement may also add, update or change information contained in this
prospectus. You should read both this prospectus and any prospectus supplement,
together with additional information described under the heading "Where You Can
Find More Information."
As used in this prospectus, "Chieftain," "we," "us" and "our" refer to Chieftain
International, Inc., a company organized under the laws of the Province of
Alberta, Canada, and its subsidiaries.
ENFORCEMENT OF CIVIL LIABILITIES
We are a corporation organized in Canada under the Business Corporations Act
(Alberta). Most of our directors and officers are not residents of the United
States, and all or a substantial portion of the assets of our directors and
officers are located outside of the United States. As a result, it may be
difficult for holders of our securities to effect service of process within the
United States upon those directors and officers who do not reside in the U.S. or
to enforce against them in the U.S. courts judgments obtained in U.S. courts
predicated upon the civil liability provisions under U.S. federal securities
laws. We have been advised by our Canadian counsel, Bennett Jones, that there is
doubt as to whether, in original actions or actions for enforcement of judgments
of U.S. courts, liabilities predicated solely upon U.S. federal securities laws
are enforceable in Canada against us or any of our directors or officers or the
experts named herein, who are not residents of the United States.
WHERE YOU CAN FIND MORE INFORMATION
We are subject to the informational requirements of the Securities Exchange Act
of 1934, which requires us to file annual, quarterly and special reports, proxy
statements and other information with the SEC. You may read and copy any
document that we file at the Public Reference Room of the SEC at 450 Fifth
Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-SEC-0330 for
further information on the operation of its public reference room. You may also
inspect our filings at the regional offices of the SEC located at Citicorp
Center, 500 West Madison Street, Suite 1400, Chicago, Illinois 60661 and 7 World
Trade Center, New York, New York 10048 or over the Internet at the SEC's web
site at http://www.sec.gov.
This prospectus constitutes part of a registration statement on Form S-3 filed
with the SEC under the Securities Act of 1933. It omits some of the information
contained in the registration statement, and reference is made to the
registration statement for further information with respect to us and the
securities we are offering. Any statement contained in this prospectus
concerning the provisions of any document filed as an exhibit to the
registration statement or otherwise filed with the SEC is not necessarily
complete, and in each instance reference is made to the copy of the filed
document.
The SEC allows us to "incorporate by reference" the information we file with
them, which means that we can disclose important information to you by referring
you to those documents. The information incorporated by reference is considered
to be part of this prospectus, and later information that we file with the SEC
will automatically update and supersede this information and the information in
the
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prospectus. We incorporate by reference the documents listed below and any
future filings made with the SEC under Sections 13(a), 13(c), 14 or 15(d) of the
Securities Act of 1934:
1. Our Annual Report on Form 10-K for the year ended December 31, 1998.
2. Our Proxy Statement dated March 11, 1999 filed with the SEC on April 7,
1999.
3. Our Quarterly Reports on Form 10-Q for the fiscal quarters ended March 31,
June 30 and September 30, 1999.
4. The description of our common shares contained in our registration statement
on Form 8-A, dated April 7, 1989, as amended on April 12, 1989, and any
subsequent amendment or report filed before or after the date of this
prospectus for the purpose of updating the description.
5. The description of our Shareholder Rights Plan Agreement contained in our
registration statement on Form 8-A, dated October 20, 1999, and any
subsequent amendment or report filed on or after the date of this prospectus
for the purpose of updating the description.
You may request a copy of these filings at no cost, by writing or telephoning
Esther S. Ondrack, Senior Vice President and Secretary, Chieftain
International, Inc., 1201 TD Tower, 10088 - 102 Avenue, Edmonton, Alberta,
Canada T5J 2Z1, telephone number (780) 425-1950.
FORWARD-LOOKING STATEMENTS
Some of the information included in this prospectus and in the documents we have
incorporated by reference contains, and any prospectus supplement may contain,
forward-looking statements. Forward-looking statements use forward-looking terms
such as "believe," "may," "intend," "will," "project," "budget," "should" or
"anticipate" or other similar words. These statements discuss "forward-looking"
information such as:
- anticipated capital expenditures and budgets;
- future cash flows and borrowings; and
- pursuit of potential future acquisition or drilling opportunities.
These forward-looking statements are based on assumptions that we believe are
reasonable, but they are open to a wide range of uncertainties and business
risks, including the following:
- fluctuations of the prices received or demand for oil and natural gas;
- uncertainty of drilling results, reserve estimates and reserve replacement;
- operating hazards;
- acquisition risks;
- unexpected substantial variances in capital requirements;
- environmental matters;
- Year 2000 computer-related interruptions; and
- general economic conditions.
Other factors that could cause actual results to differ materially from those
anticipated are discussed in our periodic filings with the SEC.
When considering these forward-looking statements, you should keep in mind the
risk factors and other cautionary statements in this prospectus, in any
prospectus supplement and in the documents we have
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incorporated by reference. We will not update these forward-looking statements
unless the securities laws require us to do so.
CHIEFTAIN
Chieftain International, Inc. is an independent energy company engaged in the
exploration, development and production of natural gas and oil. Our producing
properties and exploration acreage are primarily located in the shallow waters
of the U.S. Gulf of Mexico. We also have properties located onshore in
Louisiana, in the Four Corners area of southeast Utah and the U.K. sector of the
North Sea.
We have assembled a large natural gas and oil lease acreage position in the Gulf
of Mexico. Our lease interests in the Gulf of Mexico include a balanced
portfolio of exploration and development drilling prospects. These prospects
range from high-impact prospects with relatively greater risks, which we believe
have the potential to add substantially to our reserves, to relatively lower
risk development and exploitation projects with lower reserve potential. Our
exploration efforts are supported by an extensive 3-D seismic database covering
most of our leases. We believe that our seismic database and related
technological expertise have contributed to our successful exploration and
development track record. We believe our conservative capital structure provides
us with the financial flexibility to take advantage of our prospects and other
opportunities, including acquisitions of leasehold acreage and producing
properties.
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RISK FACTORS
An investment in our securities involves significant risks. You should carefully
consider the following risk factors before you decide to buy any of our
securities. You should also carefully read and consider all of the information
we have included, or incorporated by reference, in this prospectus before you
decide to buy any of our securities.
IF WE CANNOT REPLACE OUR RESERVES, OUR PRODUCTION AND FINANCIAL CONDITION WILL
SUFFER.
Unless we successfully replace our reserves, our production will decline,
resulting in lower revenues and cash flow. Replacing our reserves is
particularly important because most of our reserves are in the Gulf of Mexico
where wells normally have steeper rates of decline than onshore wells. Reduced
reserves may also make borrowing and raising equity more difficult. In response
to lower oil and natural gas prices, our capital expenditures in 1999 are
expected to be $55 million, compared to $92.6 million in 1998. At this level of
capital expenditures, it is more difficult to replace our reserves. Furthermore,
for the reasons discussed below, even if capital is spent on drilling or to make
acquisitions, such efforts have a risk of being unsuccessful.
DRILLING WELLS IS SPECULATIVE AND CAPITAL INTENSIVE.
Exploring for oil and natural gas and developing oil and natural gas properties
require significant capital expenditures and involve a high degree of financial
risk. The budgeted costs of drilling, completing and operating wells are often
exceeded and can increase significantly when drilling costs rise and supply
tightens. Drilling may be unsuccessful for many reasons, including weather, cost
overruns, equipment shortages and mechanical difficulties. Moreover, the
successful drilling of an oil or gas well does not ensure a profit on
investment. Exploratory wells bear a much greater risk of loss than development
wells. A variety of factors, both geological and market-related, can cause a
well to become uneconomic or only marginally economic. In addition to their
costs, unsuccessful wells can hurt our efforts to replace reserves.
RESERVES ON PROPERTIES WE BUY MAY NOT MEET OUR EXPECTATIONS AND COULD CHANGE THE
NATURE OF OUR BUSINESS.
Property acquisition decisions are based on various assumptions and subjective
judgments that are speculative. Although available geological and geophysical
information can provide information about the potential of a property, it is
impossible to predict accurately a property's production and profitability.
In addition, we may have difficulty integrating future acquisitions into our
operations, and they may not achieve our desired profitability objectives.
Likewise, as is customary in the industry, we generally acquire oil and gas
acreage without any warranty of title except through the transferor. In some
instances, title opinions are not obtained if, in our judgment, it would be
uneconomical or impractical to do so. Losses may result from title defects or
from defects in the assignment of leasehold rights. While our current operations
are primarily in shallow waters of the U.S. Gulf of Mexico (offshore Texas and
Louisiana), we may pursue acquisitions or properties located in other geographic
areas, which would decrease our geographical concentration.
ESTIMATES OF OUR PROVED RESERVES ARE UNCERTAIN AND OUR REVENUES FROM PRODUCTION
MAY VARY SIGNIFICANTLY FROM ESTIMATED AMOUNTS.
The quantities and values of our proved reserves included in this prospectus are
only estimates and are subject to numerous uncertainties. Estimates by other
engineers might differ materially. The accuracy of any reserve estimate is a
function of the quality of available data and of engineering and geological
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interpretation. These estimates depend on assumptions regarding quantities and
production rates of recoverable oil and natural gas reserves, future prices for
oil and natural gas, timing and amounts of development expenditures and
operating expenses, all of which will vary from those assumed in our estimates.
These variances may be significant.
Any significant variance from the assumptions used could result in the actual
amounts of oil and natural gas ultimately recovered and future net cash flows
being materially different from the estimates in our reserve reports. In
addition, results of drilling, testing, production and changes in prices after
the date of the estimate may result in substantial downward revisions. These
estimates may not accurately predict the present value of net cash flows from
oil and natural gas reserves.
At December 31, 1998, approximately 30% of our estimated proved reserves were
undeveloped. Recovery of undeveloped reserves generally requires additional
capital expenditures and successful drilling operations. The reserve data
assumes that we can and will make these expenditures and conduct these
operations successfully, which may not occur.
WE DO NOT INSURE AGAINST ALL POTENTIAL LOSSES AND COULD BE SERIOUSLY HARMED BY
UNEXPECTED LIABILITIES.
Exploration for and production of oil and natural gas can be hazardous,
involving natural disasters and other unforeseen occurrences such as blowouts,
cratering, fires and loss of well control, which can damage or destroy wells or
production facilities, injure or kill people, and damage property and the
environment. Because third party drilling contractors are used to drill our
wells, we may not realize the full benefit of worker's compensation laws in
dealing with their employees. We maintain insurance against many potential
losses and liabilities arising from our operations. However, in accordance with
customary industry practice, we may not be fully insured against these risks,
nor may all such risks be insurable.
GOVERNMENTAL REGULATIONS ARE COSTLY AND COMPLEX, ESPECIALLY REGULATIONS RELATING
TO ENVIRONMENTAL PROTECTION.
Our U.S. exploration, production and marketing operations are regulated
extensively at the federal, state and local levels. These regulations affect the
costs, manner and feasibility of our operations. As an owner and operator of oil
and gas properties, we are subject to federal, state and local regulation of
discharge of materials into, and protection of, the environment. We have made
and will continue to make significant expenditures in our efforts to comply with
the requirements of these environmental regulations, which may impose liability
on us for the cost of pollution clean-up resulting from operations, subject us
to liability for pollution damage and require suspension or cessation of
operations in affected areas. Changes in, or additions to, regulations regarding
the protection of the environment could increase our compliance costs and may
negatively impact our business.
We are subject to state and local regulations that impose permitting,
reclamation, land use, conservation and other restrictions on our ability to
drill and produce. These laws and regulations can require well and facility
sites to be closed and reclaimed. We buy and sell interests in properties that
have been operated in the past, and, as a result of these transactions, we may
retain or assume clean-up or reclamation obligations for our own operations or
those of third parties.
U.S. offshore oil and gas operations are subject to regulations of the United
States Department of the Interior, which currently impose 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 damage. 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 U.K., 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
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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.
WE MAY HAVE DIFFICULTY COMPETING FOR OIL AND GAS PROPERTIES OR SUPPLIES.
We operate in a highly competitive environment, competing with major integrated
and independent energy companies for desirable oil and gas properties, as well
as for the equipment, labor and materials required to develop and operate those
properties. Many of these competitors have financial resources substantially
greater than ours. We may incur higher costs or be unable to acquire and develop
desirable properties at costs we consider reasonable because of this
competition.
OUR SHAREHOLDER RIGHTS PLAN AND BY-LAWS DISCOURAGE UNSOLICITED TAKEOVER
PROPOSALS AND COULD PREVENT YOU FROM REALIZING A PREMIUM FOR YOUR COMMON SHARES.
We have a shareholder rights plan that may have the effect of discouraging
unsolicited takeover proposals. The rights issued under the shareholder rights
plan would cause substantial dilution to a person or group that attempts to
acquire us on terms not approved in advance by our board of directors. In
addition, our articles of incorporation and by-laws contain provisions that may
discourage unsolicited takeover proposals that shareholders may consider to be
in their best interests which include:
- provisions that members of the board of directors are elected and retire in
rotation; and
- the ability of the board of directors to designate the terms of, and to issue
new series of, preferred shares.
Together, these provisions and our shareholder rights plan may discourage
transactions that otherwise could involve payment to you of a premium over
prevailing market prices for your common shares.
RATIOS OF EARNINGS TO FIXED CHARGES
The following table sets forth our consolidated ratio of earnings to fixed
charges or the deficiency of our consolidated earnings to cover fixed charges
for each period indicated.
<TABLE>
<CAPTION>
SIX MONTHS YEAR ENDED DECEMBER 31,
ENDED --------------------------------------------------
JUNE 30, 1999 1998 1997 1996 1995 1994
------------- -------- ------- ------- -------- --------
(U.S. $ IN THOUSANDS, EXCEPT RATIOS)
<S> <C> <C> <C> <C> <C> <C>
CANADIAN GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES:
Ratio of Earnings to Fixed Charges...... -- -- 2.1 2.0 -- --
Deficiency of Earnings to Cover Fixed
Charges............................... $20,820 $12,157 -- -- $ 4,551 $21,757
U.S. GENERALLY ACCEPTED ACCOUNTING
PRINCIPLES (1):
Ratio of Earnings to Fixed Charges...... -- -- 2.5 2.3 -- --
Deficiency of Earnings to Cover Fixed
Charges............................... $20,026 $98,013 -- -- $12,337 $20,798
</TABLE>
- ---------------------
(1) See Note 11 to the audited consolidated financial statements for the year
ended December 31, 1998 that appear in our Annual Report on Form 10-K for
the year ended December 31, 1998 and Note 7 to the unaudited consolidated
condensed financial statements for the period ended June 30, 1999 that
appear in our Quarterly Report on Form 10-Q for the fiscal quarter ended
June 30, 1999.
For purposes of computing the ratios of earnings to fixed charges, earnings
represent income (loss) before income taxes and fixed charges. Fixed charges
consist of interest expense and preferred share dividend requirements of our
consolidated subsidiary, Chieftain International Funding Corp.
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USE OF PROCEEDS
Unless otherwise indicated in the applicable prospectus supplement, we will use
the net proceeds from the sale of the securities for our general corporate
purposes, which may include repaying indebtedness and funding capital
expenditures, acquisitions and working capital.
DESCRIPTION OF SHARE CAPITAL
The following description of our share capital is based upon our articles of
incorporation, our by-laws and applicable provisions of law. The following
description is qualified in its entirety by reference to such articles of
incorporation and by-laws, which have been filed as exhibits to earlier
registration statements filed by us with the SEC. See "Where You Can Find More
Information."
Certain provisions of our articles of incorporation and by-laws summarized in
the following paragraphs may be deemed to have an anti-takeover effect and may
delay, defer or prevent a tender offer or takeover attempt that a shareholder
might consider in its best interests, including those attempts that might result
in a premium over the market price for shares held.
AUTHORIZED AND OUTSTANDING SHARE CAPITAL
Our authorized share capital consists of an unlimited number of common shares,
an unlimited number of First Preferred shares and an unlimited number of Second
Preferred shares. As of September 30, 1999 there were 13,349,059 common shares
outstanding and no First Preferred shares or Second Preferred shares
outstanding.
COMMON SHARES
VOTING RIGHTS
Pursuant to our articles of incorporation and by-laws, the holders of our common
shares are entitled to one vote for each common share held at all meetings of
shareholders other than meetings of another class or series of shares. However,
pursuant to the subordinated guarantee agreement that we entered into in 1992
when our subsidiary, Chieftain International Funding Corp., issued its $1.8125
Convertible Redeemable Preferred shares, we have agreed to use our best efforts,
subject to applicable law, to nominate and cause to be elected to our board of
directors two persons designated by the holders of a majority of the outstanding
Chieftain International Funding Corp. $1.8125 Convertible Redeemable Preferred
shares if Chieftain International Funding Corp. shall have failed to declare and
pay dividends on its $1.8125 Convertible Redeemable Preferred shares in the
manner required for any six or more quarterly dividend payments and until all
such accumulated and unpaid dividends are paid in full.
DIVIDENDS AND LIQUIDATION RIGHTS
The holders of our common shares are entitled to any dividends as may be
declared by the board of directors, subject to the preferential rights attaching
to the First Preferred shares and the Second Preferred shares and any other of
our shares ranking in priority to the common shares. In addition, pursuant to
the subordinated guarantee agreement that we entered into in 1992 when our
subsidiary, Chieftain International Funding Corp., issued its $1.8125
Convertible Redeemable Preferred shares, we have agreed that we will not declare
or pay or set apart for payment any dividend on any of our share capital and
that no other distribution shall be paid or declared and set apart for payment
and no other distribution shall be made upon any of our share capital unless
(a) the full cumulative dividends on all outstanding $1.8125 Convertible
Redeemable Preferred shares have been paid, (b) sufficient funds have been set
apart for the payment of dividends for the then current period on the $1.8125
Convertible
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Redeemable Preferred shares and (c) the full redemption price for the $1.8125
Convertible Redeemable Preferred shares which have been called for redemption
has been paid or set apart for payment in accordance with the certificate of
designation for the $1.8125 Convertible Redeemable Preferred shares.
In the event of our liquidation, dissolution or winding up, the holders of our
common shares are entitled, subject to the rights of the holders of our shares
ranking in priority to the common shares, to participate ratably among
themselves, and ratably with the holders of any shares ranking on a parity with
the common shares, in any distribution of our assets remaining after the payment
of all our liabilities.
OTHER PROVISIONS
There are no preemptive rights to subscribe for any additional securities which
we may issue and there are no redemption provisions or sinking fund provisions
applicable to the common shares. All outstanding common shares are legally
issued, fully paid and nonassessable.
TRANSFER AGENTS AND REGISTRARS
The transfer agent and registrar for our common shares in Canada is the CIBC
Mellon Trust Company at its principal office located in each of the cities of
Calgary and Toronto. The transfer agent and registrar for our common shares in
the United States is ChaseMellon Shareholder Services of New York at its
principal office located in the City of New York.
PREFERRED SHARES
Pursuant to our articles of incorporation and by-laws, we are authorized to
issue one or more series of First Preferred shares and Second Preferred shares.
The First Preferred shares and the Second Preferred shares are alike in all
respects except that any First Preferred shares have a preference over the
Second Preferred shares upon our liquidation, dissolution or winding up or in
respect of payment of any dividends thereon.
Either the First Preferred shares or the Second Preferred shares may be issued
in one or more series. Each series may consist of the number of shares as may be
determined by our board of directors. Our board of directors may, by resolution,
fix the designation, rights, privileges, restrictions and conditions attaching
to the preferred shares of each series including:
- the rate of preferential dividends;
- the dates of payment of dividends;
- the terms and conditions of redemption, purchase or conversion, if any; and
- any sinking fund or other provisions.
The holders of preferred shares are not entitled, as such, to receive notice of
or to vote at any meeting of our common shareholders except as may be required
by law.
The preferred shares of each series will rank on a parity with the preferred
shares of every other series of the same class. They will be entitled to
preference over our common shares and any other shares ranking junior to them
with respect to priority in payment of dividends and to the distribution of
assets or return of capital in the event of our liquidation, dissolution or
winding up, or any other distribution of the assets or return of capital among
our shareholders for the purpose of winding up our affairs. However, pursuant to
the subordinated guarantee agreement that we entered into in 1992 when our
subsidiary, Chieftain International Funding Corp., issued its $1.8125
Convertible Redeemable Preferred shares, we may not pay dividends on our
preferred shares until the payment of dividends on the
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$1.8125 Convertible Redeemable Preferred shares has been provided for. See
"Common Shares--Dividends and Liquidation Rights" for more information. In the
event of our liquidation, dissolution, winding up or other distribution of our
assets or return of capital, the holders of the preferred shares will be
entitled to receive, in priority to the holders of our common shares and any
other shares ranking junior to the preferred shares, the amount paid up on the
preferred shares and all accrued and unpaid dividends. The holders of the
preferred shares will not be entitled to share in any further distribution of
our property or assets.
The applicable prospectus supplement will describe the terms of any series of
preferred shares being offered, including:
- the number of shares and designation or title of the shares;
- any liquidation preference per share;
- any redemption, repayment or sinking fund provisions;
- any dividend rate or rates and the dates of payment (or the method for
determining the dividend rates or dates of payment);
- any voting rights;
- the currency or currencies, including composite currencies in which the
preferred shares are denominated and/or in which payments will or may be
payable;
- the method by which amounts in respect of the preferred shares may be
calculated and any commodities, currencies or indices, or value, rate or
price, relevant to such calculation;
- whether the preferred shares are convertible or exchangeable and, if so, the
securities or rights into which the preferred shares are convertible or
exchangeable, and the terms and conditions of conversion or exchange;
- the place or places where dividends and other payments on the preferred
shares will be payable;
- any conditions or restrictions on the creation and the issuance of any
additional shares; and
- any additional voting, dividend, liquidation, redemption and other rights,
preferences, privileges, limitations and restrictions.
The transfer agent for each series of preferred shares will be described in the
applicable prospectus supplement.
ANTI-TAKEOVER EFFECTS OF PROVISIONS OF OUR ARTICLES OF INCORPORATION AND BY-LAWS
Our articles of incorporation and by-laws provide that our directors shall be
elected and retire in rotation. Directors are elected to three year terms and
only one-third of the directors stands for election in a given year. In
addition, our board of directors has the ability to designate the terms of, and
to issue new series of, preferred shares. These provisions may have the effect
of discouraging unsolicited takeover proposals that our common shareholders
might consider to be in their best interests and that otherwise could involve
payment to our common shareholders of a premium over prevailing market prices
for their common shares.
OUR RIGHTS PLAN
Pursuant to our shareholder rights plan, one right to purchase additional common
shares attaches to each of our common shares. In addition, one convertible right
attaches to each $1.8125 Convertible Redeemable Preferred share of Chieftain
International Funding Corp. Each convertible right entitles its
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holder to receive one right to purchase additional common shares for each whole
common share issued upon conversion of such convertible preferred share into our
common shares. The rights and the convertible rights trade automatically with
their respective shares and become exercisable under the circumstances described
below. Until a right is exercised, the holder of the right, as such, will have
no rights as a shareholder, including the right to vote or receive dividends.
CERTAIN EFFECTS OF OUR RIGHTS PLAN
Our rights plan is designed to protect our shareholders in the event of
unsolicited offers to acquire us and other coercive takeover tactics. The
primary purpose of our rights plan is to ensure that any bid for our common
shares, in the context of a takeover, will be made for all our common shares, at
the same price, and with sufficient time for our common shareholders to fully
consider the bid. The provisions of our rights plan may render an unsolicited
takeover of us more difficult or less likely to occur or might prevent such a
takeover, even though such a takeover may offer our common shareholders the
opportunity to sell their common shares at a price above the prevailing market
rate and may be favored by a majority of our common shareholders. See "Risk
Factors--Our shareholder rights plan and by-laws discourage unsolicited takeover
proposals and could prevent you from realizing a premium for your common
shares."
SUMMARY OF PRINCIPAL ATTRIBUTES OF OUR RIGHTS PLAN
The following is a general summary of the terms of our rights plan, which is
qualified in its entirety by reference to the text of the rights plan agreement.
(a) One right to purchase common shares on the terms and conditions set forth in
the rights plan agreement is issued at no cost and attaches to each
outstanding common share.
(b) One convertible right entitling the holder to receive one right for each
whole common share issued on conversion of a $1.8125 Convertible Redeemable
Preferred share of Chieftain International Funding Corp., which is
convertible into our common shares, is issued at no cost and attaches to
each such outstanding convertible preferred share.
(c) Until the "separation time" (the eighth trading day following the earlier of
(1) the date on which a person or group of people acquire beneficial
ownership (as defined in the rights plan) of 25% or more of our common
shares (an "acquiring person") and (2) the commencement date of a takeover
bid which is not a Permitted Bid (as defined below)), rights trade with the
common shares to which they are attached, have no value and may not be
exercised.
(d) At the separation time, rights separate and trade separately from the common
shares and, promptly following the separation time, separate certificates
evidencing the rights are mailed to holders of record of our common shares
and, as applicable, to the holders of record of the $1.8125 Convertible
Redeemable Preferred shares of Chieftain International Funding Corp. as of
the separation time. In addition, after the separation time, each right
(other than any rights held by the acquiring person) may be exercised to
acquire, on payment of the exercise price, common shares having an aggregate
market value equal to twice the exercise price. The initial exercise price
of a right is Cdn. $80 or the U.S.$ equivalent thereof (the "exercise
price") and is subject to certain adjustments. Where a takeover bid that is
not a Permitted Bid or a Competing Permitted Bid (as defined below) is
withdrawn after the separation time, our board of directors may elect to
redeem all the outstanding rights at a price of Cdn. $0.001 each. Upon such
redemption, the rights plan will continue in effect as if the separation
time had never occurred.
(e) A Permitted Bid is an offer:
- that is open for a minimum of 75 days;
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- that is made to acquire all of our outstanding common shares;
- that is made by an offeror holding not more than 10% of our common
shares;
- pursuant to which the offeror agrees not to acquire any additional
common shares unless 50% or more of the shares not held by the offeror
are tendered, failing which the offer will cease to be a Permitted Bid;
and
- which, if successful, allows shareholders who have not already tendered
their shares a further 15 business days in which to do so.
(f) A Competing Permitted Bid has the same requirements as a Permitted Bid
except that a Competing Permitted Bid must remain open for the greater of
21 days and the time then remaining under the outstanding Permitted Bid. The
reduction in the acceptance time for a Competing Permitted Bid is intended
to allow, to the extent possible, all takeover bids to be considered by our
common shareholders within the same time period.
(g) The shareholder rights plan has a term of 10 years from February 23, 1994.
GENERAL IMPACT OF OUR RIGHTS PLAN
Our rights plan should not deter a person from acquiring control of us if that
person is prepared to make a takeover bid pursuant to the Permitted Bid or
Competing Permitted Bid requirements. However, if an acquiring person makes a
bid to acquire 25% or more of our common shares, other than by a Permitted Bid
or Competing Permitted Bid, holders of rights, other than the acquiring person,
may acquire additional common shares at a 50% discount to the then prevailing
market price. As a result, it is unlikely that any person will acquire 25% or
more of our outstanding common shares other than by way of a Permitted Bid or a
Competing Permitted Bid.
The proxy mechanism of the Business Corporations Act (Alberta) is not affected
by our rights plan, and a shareholder may use his statutory rights thereunder to
promote a change in our management or direction. Under the Business Corporations
Act (Alberta), shareholders holding not less than 5% of a company's outstanding
shares that carry the right to vote at a meeting may requisition the board of
directors of that company to call a meeting of shareholders.
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DESCRIPTION OF DEBT SECURITIES
This section describes the general terms and provisions of the debt securities
that we may issue under the shelf registration statement. The prospectus
supplement will describe the specific terms of the debt securities offered by
that prospectus supplement.
We may issue debt securities either separately or together with, or upon the
conversion of, or in exchange for, other securities. The debt securities are to
be either our senior obligations, issued in one or more series and referred to
herein as the "senior debt securities," or subordinated obligations issued in
one or more series and referred to herein as the "subordinated debt securities."
The senior debt securities and the subordinated debt securities are collectively
referred to as the "debt securities." We will issue each series of debt
securities under an "indenture" to be entered into by us and a "trustee,"
qualified under the Trust Indenture Act of 1939. The name of the trustee will be
set forth in the applicable prospectus supplement.
The indenture will be subject to and governed by the Trust Indenture Act of
1939.
SPECIFIC TERMS OF EACH SERIES OF DEBT SECURITIES IN THE PROSPECTUS SUPPLEMENT
The applicable prospectus supplement will describe the terms of any debt
securities being offered, including:
- the designation, aggregate principal amount and authorized denominations;
- whether the debt securities are senior debt securities or subordinated debt
securities;
- the maturity date;
- the interest rate, if any, and the method for calculating the interest rate;
- the interest payment dates and the record dates for the interest payments;
- any mandatory or optional redemption terms or prepayment, conversion, sinking
fund or exchangeability or convertibility provisions;
- the places where the principal and interest will be payable;
- if other than denominations of $1,000 or multiples of $1,000, the
denominations the debt securities will be issued in;
- whether the debt securities will be issued in the form of global securities
or certificates;
- additional provisions, if any, relating to the defeasance and covenant
defeasance of the debt securities;
- whether the debt securities will be issuable in registered form or bearer
form or both and, if bearer securities are issuable, any restrictions
applicable to the exchange of one form for another and the offer, sale and
delivery of bearer securities;
- any applicable material federal tax consequences;
- the dates on which a premium, if any, will be payable;
- our right, if any, to defer payment of interest and the maximum length of
such deferral period;
- any listing on a securities exchange;
- if convertible into common shares or preferred shares, the terms on which
such debt securities are convertible;
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- the terms, if any, of any guarantee of the payment of principal of, and
premium, if any, and interest on debt securities of the series and any
corresponding changes to the provisions of the indenture as currently in
effect;
- the terms, if any, of the transfer, mortgage, pledge, or assignment as
security for the debt securities of the series of any properties, assets,
moneys, proceeds, securities or other collateral, including whether certain
provisions of the Trust Indenture Act are applicable, and any corresponding
changes to provisions of the indenture as currently in effect;
- if the purchase price of any debt securities is payable in a currency other
than U.S. dollars or if principal of, or premium, if any, or interest on any
of the debt securities is payable in any currency other than U.S. dollars,
the specific terms and other information with respect to such debt securities
and such foreign currency;
- the initial public offering price; and
- other specific terms, including covenants and the events of default provided
for with respect to the debt securities.
Debt securities may be issued with original issue discount to be sold at a
substantial discount below their principal amount. They may include "zero
coupon" securities that do not pay any cash interest for the entire term of the
securities. In the event of an acceleration of the maturity of any original
issue discount security, the amount payable to the holder thereof upon such
acceleration will be determined in the manner described in the applicable
prospectus supplement. Conditions pursuant to which payment of the principal of
the subordinated debt securities may be accelerated will be set forth in the
applicable prospectus supplement. Material federal income tax and other
considerations applicable to original issue discount securities will be
described in the applicable prospectus supplement.
COVENANTS
Under the indenture, we will be required to:
- pay the principal, interest and any premium on the debt securities when due;
- maintain a place of payment;
- deliver a report to the trustee at the end of each fiscal year reviewing our
obligations under the indenture; and
- deposit sufficient funds with any paying agent on or before the due date for
any principal, interest or any premium.
Any particular series of debt securities may contain covenants limiting:
- the incurrence of additional debt (including guarantees) by us and our
subsidiaries;
- the making of certain payments by us and our subsidiaries;
- our business activities and those of our subsidiaries;
- the issuance of other securities by our subsidiaries;
- asset dispositions;
- transactions with our subsidiaries and other affiliates;
- a change of control;
- the incurrence of liens; and
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- certain mergers and consolidations involving us and our subsidiaries.
Any additional covenants will be described in the applicable prospectus
supplement.
REGISTRATION, TRANSFER, PAYMENT AND PAYING AGENT
Unless otherwise indicated in a prospectus supplement, each series of debt
securities will be issued in registered form only, without coupons. The
indenture, however, will provide that we may also issue debt securities in
bearer form only, or in both registered and bearer form. Bearer securities will
not be offered, sold, resold or delivered in connection with their original
issuance in the United States or to any United States person other than offices
located outside the United States of certain United States financial
institutions.
Principal, interest and any premium on fully registered securities will be paid
at the office of the paying agent that we may designate. We will make payment by
check mailed to persons in whose names the debt securities are registered on
days specified in the indenture or any prospectus supplement. Debt security
payments in other forms will be paid at a place designated by us and specified
in a prospectus supplement.
Fully registered securities may be transferred or exchanged at the corporate
trust office of the trustee or at any other office or agency maintained by us
for these purposes, without payment of any service charge, except for any tax or
governmental charge.
RANKING OF DEBT SECURITIES
The senior debt securities will be our unsubordinated obligations and will rank
equally in right of payment with all of our other unsubordinated indebtedness.
The subordinated debt securities will be subordinated in right of payment to all
existing and future senior indebtedness as set forth in the applicable
prospectus supplement.
GLOBAL SECURITIES
The debt securities of a series may be issued in whole or in part in the form of
one or more global securities that will be deposited with, or on behalf of, a
"depositary" identified in the prospectus supplement relating to such series.
Unless and until it is exchanged in whole or in part for individual certificates
evidencing debt securities, a global debt security may not be transferred except
as a whole (1) by the depositary to a nominee of such depositary, (2) by a
nominee of such depositary to such depositary or another nominee of such
depositary or (3) by such depositary or any such nominee to a successor of such
depositary or a nominee of such successor. See "Book-Entry, Delivery and Form"
below for additional information.
To the extent not described in this prospectus, the terms of the depositary
arrangement with respect to a series of global debt securities and certain
limitations and restrictions relating to a series of global bearer securities
will be described in the prospectus supplement.
DISCHARGING OUR OBLIGATIONS
Except as may otherwise be set forth in any prospectus supplement, we may choose
to either discharge our obligations on the debt securities of any series in a
legal defeasance or release ourselves from our covenant restrictions on the debt
securities of any series in a covenant defeasance. We may do so at
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any time prior to the stated maturity or redemption of the debt securities of
the series if, among other conditions:
- we deposit with the trustee sufficient cash or U.S. government securities to
pay the principal, interest, any premium and any other sums due to the stated
maturity date or redemption date of the debt securities of the series; and
- we provide an opinion of our counsel that holders of the debt securities will
not be affected for U.S. federal income tax purposes by the defeasance.
If we choose the legal defeasance option, holders of the debt securities of that
series will not be entitled to the benefits of the indenture except for
registration of transfer and exchange of debt securities, replacement of lost,
stolen or mutilated debt securities, any required conversion or exchange of debt
securities, any required sinking fund payments and receipt of principal and
interest on the original stated due dates or specified redemption dates.
BOOK-ENTRY, DELIVERY AND FORM
Unless otherwise stated in any prospectus supplement, The Depository Trust
Company, New York, New York ("DTC") will act as depositary. Book-entry debt
securities of a series will be issued in the form of a global debt security that
will be deposited with DTC. This means that we will not issue certificates to
each holder. One global debt security will be issued to DTC who will keep a
computerized record of its participants (for example, your broker) whose clients
have purchased the debt securities. The participant will then keep a record of
its clients who purchased the debt securities. Unless it is exchanged in whole
or in part for a certificated debt security, a global debt security may not be
transferred; except that DTC, its nominees and their successors may transfer a
global debt security as a whole to one another.
Beneficial interests in global debt securities will be shown on, and transfers
of global debt securities will be made only through, records maintained by DTC
and its participants.
DTC has provided us with the following information: DTC is a limited-purpose
trust company organized under the New York Banking Law, a "banking organization"
within the meaning of the New York Banking Law, a member of the United States
Federal Reserve System, a "clearing corporation" within the meaning of the New
York Uniform Commercial Code and a "clearing agency" registered under the
provisions of Section 17A of the Securities Exchange Act of 1934. DTC holds
securities that its participants ("Direct Participants") deposit with DTC. DTC
also records the settlement among Direct Participants of securities
transactions, such as transfers and pledges, in deposited securities through
computerized records for Direct Participant's accounts. This eliminates the need
to exchange certificates. Direct Participants include securities brokers and
dealers, banks, trust companies, clearing corporations and some other
organizations.
DTC's book-entry system is also used by other organizations such as securities
brokers and dealers, banks and trust companies that work through a Direct
Participant. The rules that apply to DTC and its participants are on file with
the SEC.
DTC is owned by a number of its Direct Participants and by the New York Stock
Exchange, Inc., The American Stock Exchange, Inc. and the National Association
of Securities Dealers, Inc.
We will wire principal and interest payments to DTC's nominee. We and the
trustee will treat DTC's nominee as the owner of the global debt securities for
all purposes. Accordingly, we, the trustee and any paying agent will have no
direct responsibility or liability to pay amounts due on the global debt
securities to owners of beneficial interests in the global debt securities.
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It is DTC's current practice, upon receipt of any payment of principal or
interest, to credit Direct Participants' accounts on the payment date according
to their respective holdings of beneficial interests in the global debt
securities as shown on DTC's records. In addition, it is DTC's current practice
to assign any consenting or voting rights to Direct Participants whose accounts
are credited with debt securities on a record date, by using an omnibus proxy.
Payments by participants to owners of beneficial interests in the global debt
securities, and voting by participants, will be governed by the customary
practices between the participants and owners of beneficial interests, as is the
case with debt securities held for the account of customers registered in
"street name." However, payments will be the responsibility of the participants
and not of DTC, the trustee or us.
Debt securities represented by a global debt security will be exchangeable for
certificated debt securities with the same terms in authorized denominations
only if:
- DTC notifies us that it is unwilling or unable to continue as depositary or
if DTC ceases to be a clearing agency registered under applicable law and a
successor depositary is not appointed by us within 90 days; or
- We determine not to require all of the debt securities of a series to be
represented by a global debt security and notify the trustee of our decision.
MODIFICATION OF INDENTURE
Under the indenture, generally we and the trustee will be able to modify our
rights and obligations and the rights of the holders with the consent of the
holders of a specified percentage of the outstanding holders of each series of
debt affected by the modification. No modification of the principal or interest
payment terms, and no modification reducing the percentage required for
modifications, will be effective against any holder without its consent. In
addition, we and the trustee will be able to amend the indenture without the
consent of any holder of the debt securities to make technical changes.
THE TRUSTEES
The Trust Indenture Act contains limitations on the rights of a trustee, should
it become a creditor of ours, to obtain payment of claims in certain cases or to
realize on certain property received by it in respect of any such claims, as
security or otherwise. Each trustee will be permitted to engage in other
transactions with us and our subsidiaries from time to time, provided that if
such Trustee should acquire any conflicting interest it must eliminate such
conflict upon the occurrence of an event of default under the relevant
indenture, or else resign.
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DESCRIPTION OF WARRANTS
We may issue warrants for the purchase of debt securities, preferred shares or
common shares. Warrants may be issued independently or together with debt
securities, preferred shares or common shares offered by any prospectus
supplement and may be attached to or separate from any such offered securities.
Each series of warrants will be issued under a separate warrant agreement to be
entered into between us and a bank or trust company, as warrant agent. The
warrant agent will act solely as our agent in connection with the warrants and
will not assume any obligation or relationship of agency or trust for or with
any holders or beneficial owners of warrants. The following summary of certain
provisions of the warrants does not purport to be complete and is subject to,
and qualified in its entirety by reference to, the provisions of the warrant
agreement that will be filed with the SEC in connection with the offering of
such warrants.
DEBT WARRANTS
The prospectus supplement relating to a particular issue of debt warrants will
describe the terms of such debt warrants, including the following:
- the title of such debt warrants;
- the offering price for such debt warrants, if any;
- the aggregate number of such debt warrants;
- the designation and terms of the debt securities that may be purchased upon
exercise of such debt warrants;
- if applicable, the designation and terms of the debt securities with which
such debt warrants are issued and the number of such debt warrants issued
with each such debt security;
- if applicable, the date from and after which such debt warrants and any debt
securities issued therewith will be separately transferable;
- the principal amount of debt securities that may be purchased upon exercise
of a debt warrant and the price at which such principal amount of debt
securities may be purchased upon exercise (which price may be payable in
cash, securities, or other property);
- the date on which the right to exercise such debt warrants shall commence and
the date on which such right shall expire;
- if applicable, the minimum or maximum amount of such debt warrants that may
be exercised at any one time;
- whether the debt warrants represented by the debt warrant certificates or
debt securities that may be issued upon exercise of the debt warrants will be
issued in registered or bearer form;
- information with respect to book-entry procedures, if any;
- the currency or currency units in which the offering price, if any, and the
exercise price are payable;
- if applicable, a discussion of material United States federal income tax
considerations;
- the antidilution provisions of such debt warrants, if any;
- the redemption or call provisions, if any, applicable to such debt warrants;
and
- any additional terms of such debt warrants, including terms, procedures, and
limitations relating to the exchange and exercise of such debt warrants.
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SHARE WARRANTS
The prospectus supplement relating to any particular issue of preferred share
warrants or common share warrants will describe the terms of such warrants,
including the following:
- the title of such warrants;
- the offering price for such warrants, if any;
- the aggregate number of such warrants;
- the designation and terms of the common shares or preferred shares that may
be purchased upon exercise of such warrants;
- if applicable, the designation and terms of the offered securities with which
such warrants are issued and the number of such warrants issued with each
such offered security;
- if applicable, the date from and after which such warrants and any offered
securities issued therewith will be separately transferable;
- the number of common shares or preferred shares that may be purchased upon
exercise of a warrant and the price at which such shares may be purchased
upon exercise;
- the date on which the right to exercise such warrants shall commence and the
date on which such right shall expire;
- if applicable, the minimum or maximum amount of such warrants that may be
exercised at any one time;
- the currency or currency units in which the offering price, if any, and the
exercise price are payable;
- if applicable, a discussion of material United States federal income tax
considerations;
- the antidilution provisions of such warrants, if any;
- the redemption or call provisions, if any, applicable to such warrants; and
- any additional terms of such warrants, including terms, procedures and
limitations relating to the exchange and exercise of such warrants.
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PLAN OF DISTRIBUTION
The distribution of the securities may be effected from time to time in one or
more transactions at a fixed price or prices (which may be changed from time to
time), at market prices prevailing at the time of sale, at prices related to
such prevailing market prices or at negotiated prices. Each prospectus
supplement will describe the method of distribution of the securities offered
therein.
Chieftain may sell securities directly, through agents designated from time to
time, through underwriting syndicates led by one or more managing underwriters
or through one or more underwriters acting alone. Each prospectus supplement
will describe the terms of the securities to which such prospectus supplement
relates, the name or names of any underwriters or agents with whom we have
entered into arrangements with respect to the sale of such securities, the
public offering or purchase price of such securities and the net proceeds we
will receive from such sale. In addition, each prospectus supplement will
describe any underwriting discounts and other items constituting underwriters'
compensation, any discounts and commissions allowed or paid to dealers, if any,
any commissions allowed or paid to agents, and the securities exchange or
exchanges, if any, on which such securities will be listed. Dealer trading may
take place in certain of the securities, including securities not listed on any
securities exchange.
If so indicated in the applicable prospectus supplement, we will authorize
underwriters or agents to solicit offers from certain institutions to purchase
securities from us pursuant to delayed delivery contracts providing for payment
and delivery at a future date. Institutions with which such contracts may be
made include, among others:
- commercial and savings banks;
- insurance companies;
- pension funds;
- investment companies; and
- educational and charitable institutions.
In all cases, such institutions must be approved by us. Unless otherwise set
forth in the applicable prospectus supplement, the obligations of any purchaser
under any such contract will not be subject to any conditions except that
(a) the purchase of the securities will not at the time of delivery be
prohibited under the laws of the jurisdiction to which such purchaser is subject
and (b) if the securities are also being sold to underwriters acting as
principals for their own account, the underwriters will have purchased such
securities not sold for delayed delivery. The underwriters and such other
persons will not have any responsibility in respect of the validity or
performance of such contracts.
Any underwriter or agent participating in the distribution of the securities may
be deemed to be an underwriter, as that term is defined in the Securities Act,
of the securities so offered and sold and any discounts or commission received
by them, and any profit realized by them on the sale or resale of the securities
may be deemed to be underwriting discounts and commissions under the Securities
Act.
Certain of any such underwriters and agents, including their associates, may
engage in transactions with and perform services for us and our subsidiaries in
the ordinary course of business. One or more of our affiliates may from time to
time act as an agent or underwriter in connection with the sale of the
securities to the extent permitted by applicable law. The participation of any
such affiliate in the offer and sale of the securities will comply with
Rule 2720 of the Conduct Rules of the National Association of Securities
Dealers, Inc. regarding the offer and sale of securities of an affiliate.
Except as indicated in the applicable prospectus supplement, the securities are
not expected to be listed on a securities exchange, except for the common
shares, which are listed on the American Stock
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Exchange and The Toronto Stock Exchange, and any underwriters or dealers will
not be obligated to make a market in securities. We cannot predict the activity
or liquidity of any trading in the securities.
LEGAL MATTERS
The validity of the securities in respect of which this prospectus is being
delivered will be passed on for us by Bennett Jones, Calgary, Alberta. Certain
other legal matters in connection with the securities will be passed on for us
by Cravath, Swaine & Moore, New York, New York.
EXPERTS
The audited financial statements incorporated by reference in this prospectus
have been audited by PricewaterhouseCoopers LLP, as indicated in their report
with respect to such audited financial statements, and are incorporated by
reference in reliance upon the authority of such firm as experts in giving such
reports. PricewaterhouseCoopers LLP is located at 1501 TD Tower, 10088 - 102
Avenue, Edmonton, Alberta, Canada, T5J 2Z1. The reserve estimates relating to
our U.S. reserves, of Netherland, Sewell & Associates, Inc. incorporated by
reference in this prospectus, have been incorporated by reference in reliance
upon the authority of such firm as experts in petroleum engineering.
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[LOGO]
CHIEFTAIN INTERNATIONAL, INC.
2,500,000 SHARES
COMMON SHARES
------------------------------
PROSPECTUS SUPPLEMENT
------------------------------
, 1999
CIBC WORLD MARKETS
DAIN RAUSCHER WESSELS
A DIVISION OF DAIN RAUSCHER INCORPORATED
A.G. EDWARDS & SONS, INC.
- --------------------------------------------------------------------------------
YOU SHOULD RELY ONLY ON THE INFORMATION WE HAVE INCLUDED OR INCORPORATED BY
REFERENCE IN THIS PROSPECTUS SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS. WE HAVE
NOT AUTHORIZED ANYONE TO PROVIDE YOU WITH ADDITIONAL OR DIFFERENT INFORMATION.
IF YOU RECEIVE ANY UNAUTHORIZED INFORMATION, YOU MUST NOT RELY ON IT. WE ARE
OFFERING TO SELL THE SECURITIES ONLY IN JURISDICTIONS WHERE SALES ARE PERMITTED.
YOU SHOULD NOT ASSUME THAT THE INFORMATION WE HAVE INCLUDED IN THIS PROSPECTUS
SUPPLEMENT AND THE ACCOMPANYING PROSPECTUS IS ACCURATE AS OF ANY DATE OTHER THAN
THE DATE OF THIS PROSPECTUS SUPPLEMENT OR THAT ANY INFORMATION WE HAVE
INCORPORATED BY REFERENCE IS ACCURATE AS OF ANY DATE OTHER THAN THE DATE OF THE
DOCUMENT INCORPORATED BY REFERENCE.
