<PAGE> 1
FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 1999
Commission File number 1-10216:
CHIEFTAIN INTERNATIONAL, INC.
(Exact name of registrant as specified in its charter)
ALBERTA, CANADA NONE
- ---------------------------------- -----------------------------------------
(State or other jurisdiction of (I.R.S. Employer Identification No.)
incorporation or organization)
1201 TD TOWER, 10088 - 102 AVENUE,
EDMONTON, ALBERTA, CANADA T5J 2Z1
- ---------------------------------- -----------------------------------------
(Address of Registrant's principal (Postal Code)
executive offices)
Registrant's telephone number, including area code: (780) 425-1950
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
Title of each class Name of each exchange on which registered
- ------------------- -----------------------------------------
Common Shares, no par value, of
Chieftain International, Inc. American Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. YES X NO
--- ---
The aggregate market value of the voting stock of Chieftain International, Inc.
held by non-affiliates of said registrant on March 14, 2000 was
U.S.$265,825,098.
The number of shares outstanding of the common stock of Chieftain International,
Inc. on March 14, 2000 was 16,224,059.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Chieftain International, Inc. Information Circular dated March
15, 2000 for its annual meeting of shareholders to be held on May 25, 2000, are
incorporated by reference into Part III hereof, to the extent indicated herein.
The Exhibits Index can be found on page 56 of this document.
This report contains forward-looking statements that are subject to risk factors
associated with the oil and gas business. The Company believes that the
expectations reflected in these statements are reasonable, but may be affected
by a variety of factors including, but not limited to: price fluctuations,
currency fluctuations, drilling and production results, imprecision of reserve
estimates, loss of market, industry competition, environmental risks, political
risks and capital restrictions.
<PAGE> 2
CHIEFTAIN INTERNATIONAL, INC.
1999 FORM 10-K ANNUAL REPORT
Table of Contents
<TABLE>
<CAPTION>
Page
<S> <C>
PART I
Item 1. Business ..................................................................................... 1
Segment Information ....................................................................... 1
Properties ................................................................................ 2
Acreage ................................................................................... 6
Gas and Oil Capital Expenditures .......................................................... 6
Drilling Activity ......................................................................... 7
Wells ..................................................................................... 7
Reserves .................................................................................. 7
Production Volumes, Prices and Costs ...................................................... 8
Employees ................................................................................. 8
Business Risks ............................................................................ 8
Glossary .................................................................................. 11
Item 2. Properties ................................................................................... 12
Item 3. Legal Proceedings ............................................................................ 12
Item 4. Submission of Matters to a Vote of Security Holders .......................................... 12
Executive Officers of the Registrant ...................................................... 12
PART II
Item 5. Market for the Registrant's Securities and Related Stockholder Matters ....................... 13
Item 6. Selected Consolidated Financial Data ......................................................... 14
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations ........ 15
Item 8. Financial Statements and Supplementary Data .................................................. 29
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure ......... 55
PART III
Item 10. Directors and Executive Officers ............................................................. 55
Item 11. Executive Compensation ....................................................................... 55
Item 12. Security Ownership of Certain Beneficial Owners and Management ............................... 55
Item 13. Certain Relationships and Related Transactions ............................................... 55
PART IV
Item 14. Exhibits and Reports on Form 8-K ............................................................. 55
Signatures .............................................................................................. 57
</TABLE>
<PAGE> 3
PART I
ITEM 1. BUSINESS
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 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 129 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, 93 are held as exploratory acreage and 46 are held by production. We
operate 39 of these blocks. Our average working interest in our Gulf of Mexico
leases is approximately 40%. In 1999, we had production of 88.6 mmcfe per day
(71.0 mmcfe per day after royalties) in the Gulf of Mexico, which represented
approximately 78% 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 production of 2,026 barrels per day (1,770 barrels per day after
royalties) in 1999. We own an interest in approximately 9,600 net acres in the
U.K. sector of the North Sea where we had production of 10.0 mmcfe per day
(before and after royalties) in 1999. We are also active in exploratory
activities onshore in Louisiana.
At December 31, 1999, we had estimated proved reserves of 290.3 bcfe (239.7 bcfe
after royalties). These reserves had a present value of net cash flows before
income taxes, discounted at 10%, of $266.5 million using constant natural gas
and oil prices in effect on December 31, 1999, which averaged $2.51 per mcf for
U.S. natural gas, $0.99 per mcf for U.K. natural gas and $20.40 per barrel for
oil. At December 31, 1999, approximately 64% of our proved reserves were natural
gas and approximately 63% of our proved reserves were developed. Our total
proved reserves at December 31, 1999 had a reserves-to-production ratio of
approximately 7.1 years.
SEGMENT INFORMATION
Reference is made to page 42 hereof for financial information with respect to
the geographic segments of Chieftain for the years ended December 31, 1999, 1998
and 1997.
- ---------------------------
* Unless the context indicates another meaning, the terms "Chieftain", "the
Company", "we", "us" and "our" refer to Chieftain International, Inc., a company
organized under the laws of the Province of Alberta, Canada, and its
subsidiaries. For definitions of certain terms used throughout this report, see
"Glossary".
The Company's accounts are maintained, and all dollar amounts herein are stated,
in United States dollars unless otherwise indicated.
1
<PAGE> 4
PROPERTIES
Our principal natural gas and oil properties are concentrated in the U.S. Gulf
of Mexico and, to a lesser extent, onshore Louisiana, Utah and other parts of
the U.S. and in the U.K. sector of the North Sea.
The following table summarizes our estimated proved reserves by major operating
area and the estimated present value of net cash flows before income taxes,
discounted at 10%, of these reserves at December 31, 1999:
<TABLE>
<CAPTION>
Estimated
Proved reserves (before royalties) present value before
---------------------------------------------------------- income taxes of
Natural gas Oil and ngls Total proved reserves
(mmcf) (mbbls) (mmcfe) (U.S.$ in thousands)
----------- ------------- -------- ---------------------
<S> <C> <C> <C> <C>
Gulf of Mexico.............. 131,098 5,504 164,122 $186,039
Onshore Louisiana........... 47,083 158 48,031 42,283
Utah and Other Onshore...... 1,729 11,648 71,617 36,040
-------- ------- ------- ---------
Total U.S. ............... 179,910 17,310 283,770 264,362
U.K. (North Sea)............ 6,376 20 6,496 2,112
-------- ------- ------- ---------
Total..................... 186,286 17,330 290,266 $266,474
======== ======= ======== =========
</TABLE>
GULF OF MEXICO
We concentrate our exploration and production 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 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 3D 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 139 blocks, we rank as the ninth largest independent
producer on the continental shelf. Of these lease blocks, 129 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 661,410 (266,249 net) acres at December 31, 1999. We operate 39 blocks
in the Gulf of Mexico.
Described below are the areas of our current exploration and development
activity in the Gulf of Mexico.
WESTERN GULF (OFFSHORE TEXAS)
MUSTANG ISLAND:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
------ ------------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
5 21,818 10,549 48% 9.3 mmcf/d 7.7 mmcf/d
</TABLE>
Most of our production in this area comes from Block 784 (Chieftain 50%) where a
well was successfully recompleted, maintaining production rates at prior year's
levels. No significant exploration or development work was done in 1999 and
none is currently planned for 2000.
2
<PAGE> 5
MATAGORDA ISLAND:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
------ ----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
9 47,609 13,279 28% 10.6 mmcf/d 8.2 mmcf/d
</TABLE>
During 1999, two wells on Block 604 (Chieftain 37%) were successfully
recompleted and at year-end were producing 2.2 mmcf/d, net to our working
interest. On Block 704 (Chieftain 25%), a 12,700 foot exploration well commenced
drilling during the fourth quarter of 1999. On Block 634 (Chieftain 24%) a 9,900
foot exploration well is expected to commence drilling by mid-2000.
HIGH ISLAND/EAST ADDITION/SOUTH EXTENSION:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
------ ----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
16 62,772 25,205 40% 10.0 mmcf/d and 81 bbls/d 8.2 mmcf/d and 66 bbls/d
</TABLE>
On Block 207 (Chieftain 50%), production increased significantly with a full
year's output from a well completed in 1998. During 1999 we sold our interest in
Block 134 (Chieftain 50%). On Block 206 (Chieftain 25%), acquired early in 2000,
a 12,000 foot exploration well commenced drilling in the first quarter.
HIGH ISLAND SOUTH ADDITION:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
------ ----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
12 64,800 37,008 57% 0.2 mmcf/d 0.1 mmcf/d
</TABLE>
Successful drilling was carried out on Blocks A-510/A-531 (Chieftain 50%) and
A-530 during 1999. For the 2000 year, additional exploratory and development
drilling is planned on Blocks A-510/A-531 and A-567. We operate High Island
A-510/A-531 where an 11,107 foot well encountered more than 260 feet of natural
gas and oil bearing pay in multiple zones. Design of production facilities, in a
water depth of 235 feet, is underway and production is scheduled to commence
late in 2000. At High Island A-530 (Chieftain 75%), a successful exploration
well encountered a total of 155 feet of natural gas pay in two zones. We also
operate this well, which is four miles southeast of the A-510/A-531 discovery. A
production facility is being designed for Block A-530 and initial production is
expected to commence during the fourth quarter of 2000.
CENTRAL GULF (OFFSHORE LOUISIANA)
EAST CAMERON:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
------ ----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
12 51,479 15,660 30% 2.7 mmcf/d and 627 bbls/d 2.2 mmcf/d and 522 bbls/d
</TABLE>
The well on Block 34 (Chieftain 40%) was recompleted in the fourth quarter of
1999 and at year-end was producing 4.0 mmcf/d, net to our working interest. We
will act as operator and drill a 13,500 foot well on Block 255 (Chieftain 60%)
in the fourth quarter of 2000.
VERMILION:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
------ ----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
4 10,806 3,447 32% 1.5 mmcf/d 1.1 mmcf/d
</TABLE>
During the fourth quarter of 1999, we participated in a natural gas discovery on
Block 267 (Chieftain 60%). Production facilities are being constructed and
initial production is scheduled to commence in the second quarter of 2000. When
facilities have been installed, two exploratory wells will be drilled from the
platform. Each of these wells will test a separate fault structure on the Block.
An exploratory well is also planned for Block 16 (Chieftain 14%) and a
development well is scheduled for Block 23 (Chieftain 25%).
3
<PAGE> 6
SOUTH MARSH ISLAND:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
- ------ ----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
5 22,852 17,352 76% 4.9 mmcf/d and 1,250 bbls/d 4.1 mmcf/d and 1,041 bbls/d
</TABLE>
Production commenced from two wells on Block 39 (Chieftain 50%) during the
first quarter of 1999. Three successful wells, two exploratory and one
development, were drilled during the year and commenced production during the
third quarter. Further drilling in the South Marsh Island area is planned for
2000, including a development well on Block 39 (Chieftain 50%), a 13,500 foot
exploration well on Block 110 (Chieftain 50%) and an operated exploration well
on Block 138 (Chieftain 100%).
SOUTH TIMBALIER:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
- ------ ----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
5 22,186 9,843 44% -- --
</TABLE>
A 1999 discovery well on Block 196 (Chieftain 50%) encountered multiple natural
gas and oil sands. Platform installation and initial production is scheduled
for the second quarter of 2000. Additional exploratory drilling is planned for
Block 196 in 2000. We plan to drill a 10,000 foot exploratory well on Block 78
(Chieftain 50%) where we are operator.
WEST CAMERON:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
- ------ ----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
10 43,934 16,421 37% 1.6 mmcf/d 1.4 mmcf/d
</TABLE>
During 1999 we participated in two natural gas discoveries in this area. On
Block 613 (Chieftain 25%), we participated in a multi-zone natural gas
discovery. Facilities design and construction is under way and first production
is expected to commence in mid-2000. Additional drilling on Block 613 is
scheduled to follow installation of the production facility. At West Cameron
300 (Chieftain 35%), an operated exploration well was drilled to 9,500 feet in
early 2000 and encountered two natural gas zones. A follow-up well is being
drilled. Facilities design for this project, in 40 feet of water, has commenced
and initial production is scheduled for late 2000. During the first half of
2000, we will participate, as operator, in the drilling of a 9,500 foot
exploration well on Block 386 (Chieftain 80%). In late 2000, a development well
will be drilled on producing Blocks 192/193 (Chieftain 25%).
MAIN PASS:
<TABLE>
<CAPTION>
Blocks Gross Acres Net Acres Average Interest Average Production Average Production
- ------ ----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C> <C>
7 26,690 3,452 13% 18.0 mmcf/d and 206 bbls/d 13.8 mmcf/d and 155 bbls/d
</TABLE>
The Main Pass area is currently the most significant contributor to our natural
gas production. During 1999, development activity included drilling,
completions and facilities installation on Block 250 (Chieftain 20%) and Block
225 (Chieftain 10%), maintaining production at the prior year's levels.
OTHER GULF OF MEXICO OPERATIONS:
Our 2000 drilling program for the Gulf of Mexico region includes approximately
27 wells, up from the 18 that were drilled in 1999. In addition to the wells
described above in our area analysis, the following wells are planned for 2000:
operated exploration wells at Brazos A-1 (Chieftain 100%), Eugene Island 355
(Chieftain 33%), Grand Isle 77 (Chieftain 67%) and Ship Shoal 257 (Chieftain
50%); non-operated exploration wells at Brazos 542 (Chieftain 6%) and Grand
Isle 103 (Chieftain 20%); and operated development wells at South Pass 37
(Chieftain 42%) and Eugene Island 189 (Chieftain 75%).
4
<PAGE> 7
VERMILION PARISH, LOUISIANA
NORTHEAST WRIGHT:
<TABLE>
<CAPTION>
Gross Acres Net Acres Average Interest Average Production Average Production
----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C>
3,688 1,841 50% 0.9 mmcf/d 0.7 mmcf/d
</TABLE>
In the Northeast Wright Field, the Broussard #1 well (Chieftain 50%) was
drilled to 18,400 feet to delineate and extend to the south the reserves
encountered by the 1998 D.W. Guidry #1 well. The Guidry well found 150 feet of
natural gas pay below 17,000 feet. The Broussard well found a significant
thickness of natural gas-bearing high quality reservoir sand. At year-end, the
Broussard well was tested and production commenced in January, 2000 at 8.5
mmcf/d (gross). We are participating in drilling the 19,000 foot Langlinais #1
well (Chieftain 50%), which commenced drilling northeast of the Broussard well
early in 2000. Our interest in the Guidry well is subject to a penalty on a
portion of the well costs. The extent of this reservoir could be revealed by
the 18,800 foot Delahoussaye #2 well (Chieftain 1.75%) which commenced drilling
at a location north of the field in February of 2000.
FOUR CORNERS (PARADOX BASIN) AREA, UTAH
ANETH UNIT:
<TABLE>
<CAPTION>
Gross Acres Net Acres Unit Interest Average Production Average Production
----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C>
18,070 3,066 13.4% 0.15 mmcf/d 0.13 mmcf/d
and 640 bbls/d and 557 bbls/d
</TABLE>
RATHERFORD UNIT:
<TABLE>
<CAPTION>
Gross Acres Net Acres Unit Interest Average Production Average Production
----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C>
12,910 2,560 21.4% 0.45 mmcf/d 0.39 mmcf/d
and 1,386 bbls/d and 1,213 bbls/d
</TABLE>
We have interests in two light oil fields where horizontal drilling has improved
the effectiveness of a waterflood enhanced recovery program being employed in
these fields. A pilot tertiary carbon dioxide recovery project in the Aneth
Field has shown favorable results and is continuing. A similar field-wide
project scheduled for 1999 in the Ratherford Unit was delayed due to low oil
prices. The Ratherford project is currently scheduled to proceed in late 2000.
NORTH SEA - UNITED KINGDOM SECTOR
<TABLE>
<CAPTION>
Gross Acres Net Acres Unit Interest Average Production Average Production
----------- --------- ---------------- ------------------ ------------------
(before royalties) (after royalties)
<S> <C> <C> <C> <C>
60,273 9,644 16% 9.8 mmcf/d 9.8 mmcf/d
and 32 bbls/d and 32 bbls/d
</TABLE>
All of our U.K. production comes from our interest in the Galahad Field
(Chieftain 17.8%). It is sold under 30-day contracts and in 1999 obtained an
average price of $0.96 per mcf, net of transportation costs. The U.K.
production is royalty free.
SIRTE BASIN, LIBYA
During 1999, it was concluded with our joint venture partners that an
exploration venture in Libya on a concession covering 3,888,550 (486,068 net)
acres in the Sirte Basin was not commercially viable and the holdings were
relinquished.
5
<PAGE> 8
ACREAGE
The following table summarizes the developed and undeveloped acreage held by
Chieftain as at December 31, 1999. Where applicable, interests which are not
working interests (none of which is material) have been converted to working
interest equivalents.
<TABLE>
<CAPTION>
Developed Acres Undeveloped Acres
Area Gross Net Gross Net
- -------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
United States
Offshore Gulf of Mexico
Louisiana....................... 19,885 6,228 294,766 105,139
Texas........................... 13,240 3,770 328,347 149,622
Texas State..................... 300 22 4,872 1,468
------- ------ ------- -------
Total Offshore Gulf of Mexico........ 33,425 10,020 627,985 256,229
======= ====== ======= =======
Onshore
Louisiana....................... 2,110 1,055 4,400 2,197
Montana......................... -- -- 3,240 3,240
North Dakota.................... 997 226 1,120 189
Pennsylvania.................... 324 36 -- --
Utah............................ 29,860 4,895 1,120 731
------- ------ ------- -------
Total Onshore........................ 33,291 6,212 9,880 6,357
======= ====== ======= =======
Total United States....................... 66,716 16,232 637,865 262,586
======= ====== ======= =======
United Kingdom
North Sea............................ 7,584 1,348 52,689 8,296
======= ====== ======= =======
Total, all areas.......................... 74,300 17,580 690,554 270,882
======= ====== ======= =======
</TABLE>
Chieftain's developed and undeveloped acreage in all areas covered 764,854
(288,462 net) acres at December 31, 1999.
The undeveloped acreage, which has a cost to Chieftain of approximately $34
million, has not been independently evaluated.
GAS AND OIL CAPITAL EXPENDITURES
Reference is made to page 21 hereof for financial information with respect to
our net capital expenditures for the years ended December 31, 1999, 1998 and
1997.
6
<PAGE> 9
DRILLING ACTIVITY
The following table summarizes the results of Chieftain's drilling activities
during the years ended December 31, 1999, 1998 and 1997.
<TABLE>
<CAPTION>
EXPLORATORY WELLS - Year ended December 31,
1999 1998 1997
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Gas .......................... 4 2.10 5 1.89 7 2.82
Oil .......................... -- -- 1 0.33 -- --
Oil/Gas ...................... 4 2.00 -- -- 1 0.50
Evaluating ................... 1 0.50 -- -- -- --
Drilling at end of year ...... 3 0.62 -- -- 3 0.94
Abandoned .................... 5 1.45 8 3.45 9 2.99
-- ---- -- ---- -- ----
17 6.67 14 5.67 20 7.25
== ==== == ==== == ====
</TABLE>
<TABLE>
<CAPTION>
Development Wells - Year ended December 31,
1999 1998 1997
Gross Net Gross Net Gross Net
----- --- ----- --- ----- ----
<S> <C> <C> <C> <C> <C> <C>
Gas .......................... 5 0.77 4 0.32 9 1.77
Oil .......................... -- -- 30 6.01 34 6.15
Oil/Gas ...................... 1 0.50 1 0.25 -- --
Evaluating ................... -- -- -- -- -- --
Drilling at end of year ...... -- -- -- -- 4 0.81
Abandoned .................... 1 0.50 -- -- 1 0.50
-- ---- -- ---- -- ----
7 1.77 35 6.58 48 9.23
== ==== == ==== == ====
</TABLE>
WELLS
Chieftain's productive gas and oil wells as at December 31, 1999 are listed in
the following table. Any interests which are not working interests (none of
which is material) have been converted to working interest equivalents.
<TABLE>
<CAPTION>
Gas Wells Oil Wells
Gross Net Gross Net
----- --- ----- ----
<S> <C> <C> <C> <C>
North Dakota ................. -- -- 2 0.47
Pennsylvania ................. 5 0.93 -- --
Utah ......................... -- -- 265 43.91
Louisiana .................... 2 1.00 -- --
U.S. Gulf of Mexico .......... 88 17.28 20 6.35
United Kingdom ............... 3 0.41 -- --
-- ----- --- -----
98 19.62 287 50.73
== ===== === =====
</TABLE>
RESERVES
Our U.S. natural gas and oil reserves have been evaluated by Netherland, Sewell
& Associates, Inc. ("NS&A") and we have evaluated our U.K. reserves which amount
to 2.2% (2.7% after royalties) of total equivalent reserves.
For estimates of the Company's proved and proved developed reserves see
"Supplementary Financial Information".
7
<PAGE> 10
PRODUCTION VOLUMES, PRICES AND COSTS
Chieftain's net production of gas and oil (computed after royalty deductions
but before production taxes) for the years ended December 31, 1999, 1998 and
1997 is listed below. Also listed are average sales prices and average
production costs during such periods.
<TABLE>
<CAPTION>
Year Ended December 31, 1999 1998 1997
------- ------- -------
<S> <C> <C> <C>
Total Net Production:
Natural gas (mmcf)........................... 25,533 24,504 23,431
Oil and liquids (mbbls)...................... 1,428 1,100 825
Gas equivalent (mmcfe)....................... 34,103 31,102 28,383
Average Daily Net Production:
Natural gas (mmcf)........................... 70.0 67.1 64.2
Oil and liquids (bbls)*...................... 3,913 3,012 2,261
Gas equivalent (mmcfe)....................... 93.4 85.2 77.8
Average Sales Price:
Natural gas (per mcf)........................ $ 2.02 $ 1.99 $ 2.33
Oil and liquids (per bbl).................... $ 17.05 $ 11.74 $ 18.94
Average Production Cost:
Natural gas (per mcf)........................ $ 0.21 $ 0.30 $ 0.27
Oil and liquids (per bbl).................... $ 4.60 $ 5.78 $ 5.81
</TABLE>
* Oil comprised approximately 89% (1998 and 1997 - 82%) of the oil and liquids
production.
EMPLOYEES
At December 31, 1999, Chieftain had 44 full-time equivalent employees. In
addition, Chieftain engages the services of consultants as required.
BUSINESS RISKS
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 U.S. 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.
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 natural 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.
8
<PAGE> 11
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 natural
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 geographic 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 Form 10-K 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
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, 1999, approximately 37% 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 natural 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 natural 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
natural gas operations are subject to the licensing control of the Ministry of
Agriculture, Fisheries and Food. The breach of a license will result in criminal
liability and possible civil liability for the cost of any resulting pollution
clean-up. In the event of a serious incident of pollution, the Ministry may vary
or revoke a license.
9
<PAGE> 12
We may have difficulty competing for oil and natural gas properties or supplies.
We operate in a highly competitive environment, competing with major integrated
and independent energy companies for desirable oil and natural 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.
10
<PAGE> 13
GLOSSARY
The following are defined terms used herein:
BBL means barrel (42 U.S. gallons).
BCF means 1,000,000,000 cubic feet.
BCFE means 1,000,000,000 cubic feet of natural gas equivalent.
BBLS/D means barrels per day.
BLOCK refers to an offshore U.S. Gulf of Mexico gas and oil lease.
DEVELOPED ACREAGE refers to the number of acres assignable to productive wells.
DEVELOPMENT WELLS are wells drilled within the proved area of a natural gas or
oil reservoir to the depth of a stratigraphic horizon known to be productive.
DRY WELLS are wells found to be incapable of producing either natural gas or
oil in sufficient quantities to justify completion as natural gas or oil wells.
EXPLORATORY WELLS are wells drilled to find and produce natural gas or oil in an
unproved area, to find a new reservoir in a field previously found to be
productive of natural gas or oil in another reservoir, or to extend a known
reservoir.
NATURAL GAS reserves are reported at a base pressure of 14.65 psia and a base
temperature of 60 degrees Fahrenheit.
NATURAL GAS EQUIVALENT is determined by using the approximate energy equivalent
ratio of 6 mcf of natural gas to 1 bbl of oil and liquids.
GROSS ACRES means the total number of acres in which an interest is owned by
Chieftain.
GROSS WELLS means the total number of wells in which an interest is owned by
Chieftain.
LIQUIDS means natural gas liquids.
MBBLS means 1,000 barrels.
MCF means 1,000 cubic feet.
MCF/D means 1,000 cubic feet per day.
MMCF means 1,000,000 cubic feet.
MMCF/D means 1,000,000 cubic feet per day.
MMCFE means 1,000,000 cubic feet of natural gas equivalent.
NET ACRES refers to the sum of the fractional interests owned in gross acres.
NET WELLS refers to the sum of the fractional interests owned in gross wells.
NGLS means natural gas liquids.
OIL or OIL AND LIQUIDS means crude oil and natural gas liquids.
PRODUCTIVE WELLS are producing wells and wells capable of producing.
PROVED DEVELOPED PRODUCING RESERVES are those reserves which are expected to be
produced from existing completion intervals now open for production in existing
wells.
PROVED DEVELOPED NON-PRODUCING RESERVES are (1) those reserves expected to be
produced from existing completion intervals in existing wells, but due to
pending pipeline connections or other mechanical or contractual requirements
hydrocarbon sales have not yet commenced, and (2) other non-producing reserves
which exist behind the casing of existing wells, or at minor depths below the
present bottom of such wells, which are expected to be produced through these
wells in the predictable future, where the cost of making such oil and gas
available for production should be relatively small compared to the cost of a
new well.
PROVED RESERVES are the estimated quantities of natural gas, crude oil and
natural gas liquids which geological and engineering data demonstrate with
reasonable certainty to be recoverable in future years from known reservoirs
under existing economic and operating conditions. Proved reserves are limited to
those quantities of natural gas and oil which can be expected, with little
doubt, to be recoverable commercially at current prices and costs under existing
regulatory practices and with existing conventional equipment and operating
methods.
PROVED UNDEVELOPED RESERVES are those reserves which are expected to be
recovered from new wells on undrilled acreage or from existing wells where a
relatively major expenditure is required for recompletion. Proved reserves on
undrilled acreage are limited to those drilling units offsetting productive
units that are reasonably certain of production when drilled.
UNDEVELOPED ACREAGE is acreage on which wells have not been drilled or
completed to a point that would permit the production of commercial
quantities of natural gas and oil regardless of whether or not such acreage
contains proved reserves.
WORKING INTEREST refers to the net interest held by Chieftain in an oil or
natural gas lease or other disposition which interest bears its proportionate
share of the costs of exploration, development and operations and any royalties
or other production burdens.
11
<PAGE> 14
ITEM 2. PROPERTIES
Reference is made to Item 1, "Business", for information concerning the
materially important physical properties of Chieftain. In addition, Chieftain
leases office space.
ITEM 3. LEGAL PROCEEDINGS
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.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
No matters were submitted to a vote of security holders of the Company during
the fourth quarter of 1999.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table lists the name and age of each Executive Officer and all
positions and offices with the Company held by each such person. The officers
are appointed each year at the directors' meeting immediately following the
annual meeting of the shareholders. The next such meeting will be held on May
25, 2000.
<TABLE>
<CAPTION>
Name Age Position/Office
- ---- --- ---------------
<S> <C> <C>
Stanley A. Milner 71 Director, President and Chief Executive Officer
Stephen C. Hurley 50 Director, Senior Vice President and Chief Operating Officer
James B. Lewis 50 Senior Vice President, Operations
Esther S. Ondrack 59 Director, Senior Vice President and Secretary
S. Jay Milner 42 Vice President, Drilling and Production
Ronald J. Stefure 52 Vice President and Controller
Randall P. Boyd 43 Vice President, Investor Relations
</TABLE>
With the following exceptions all of the officers have held positions as
officers of the Company since its incorporation in 1988, such position being his
or her principal occupation. S.C. Hurley joined Chieftain in September, 1995
prior to which time he was the Vice President, Exploration of a U.S. based
integrated oil company. J.B. Lewis joined Chieftain as a consultant in May 1998
and was appointed an officer of the Company in 1999. Prior to 1998, J.B.
Lewis was Vice President and General Manager, Offshore Division of a U.S. based
energy company. S.J. Milner and R.J. Stefure were appointed officers of the
Company in June, 1995 and prior thereto held management positions with the
Company. R.P. Boyd joined Chieftain in 1999 prior to which time he was Chief
Financial Officer and Controller of a Canadian independent oil and gas company.
There are no family relationships among the executive officers and directors
except between S.A. Milner and D.E. Mitchell who are first cousins and between
S.A. Milner and S.J. Milner who are father and son.
12
<PAGE> 15
PART II
ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND RELATED STOCKHOLDER MATTERS
The principal United States market in which the Common Shares of the Company
are traded is the American Stock Exchange. The Common Shares are also traded on
the Toronto Stock Exchange. The high and low prices of the Chieftain
International, Inc. Common Shares (the "Common Shares") during each quarter
since December 31, 1997 are shown below.
<TABLE>
<CAPTION>
Price History of Chieftain International, Inc. Common Shares
American Stock Exchange Toronto Stock Exchange
(U.S. dollars) (Cdn. dollars)
High Low High Low
-------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
1998
First quarter $ 24.75 $ 17.94 $ 35.25 $ 25.60
Second quarter 24.75 20.25 35.35 30.10
Third quarter 23.75 13.94 34.75 21.60
Fourth quarter 20.25 14.38 30.70 22.75
1999
First quarter 15.50 9.56 24.00 14.50
Second quarter 18.63 12.25 26.95 19.25
Third quarter 22.75 17.44 34.00 25.90
Fourth quarter 20.38 14.06 30.25 21.00
2000
January 17.50 15.56 25.00 22.50
February 17.75 13.38 26.00 19.50
March 1 to March 14 17.50 13.81 25.50 20.35
</TABLE>
The Common Shares were held by 97 shareholders of record on December 31, 1999.
The Company estimates that investment dealers and other nominees hold Common
Shares for approximately 2,150 beneficial holders.
At the present time it is not the Company's policy to declare regular dividends
on the Common Shares. This policy is under periodic review by the Board of
Directors and is subject to change at any time depending on the earnings of the
Company and its financial requirements. Dividends may be paid on the Common
Shares provided that all dividends on the preferred shares of Chieftain
International Funding Corp. have been paid. All dividends on the preferred
shares have been paid.
13
<PAGE> 16
ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The selected consolidated financial and operating data for each of the five
years ended December 31, 1999 has been derived from the consolidated financial
statements of the Company included herein and should be read in conjunction with
such consolidated financial statements and the related notes.
SELECTED CONSOLIDATED FINANCIAL AND OPERATING DATA
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARIES
<TABLE>
<CAPTION>
YEAR ENDED DECEMBER 31, 1999 1998 1997 1996 1995
------------ ------------ ------------ ------------ ------------
(in thousands except shares, per share amounts and operating data)
<S> <C> <C> <C> <C> <C>
INCOME STATEMENT DATA:
Revenue ............................................ $ 76,447 $ 64,391 $ 72,055 $ 63,099 $ 31,071
Production costs ................................... 14,320 16,355 13,325 12,220 9,563
General and administrative expenses ................ 4,580 4,796 4,308 3,972 3,346
Interest ........................................... 2,496 437 -- -- --
Depletion and amortization(1) ...................... 51,385 42,081 36,951 30,920 18,779
Additional depletion(2) ............................ 16,186 6,244 -- -- --
Income (loss) from operations, before dividends
on preferred shares of a subsidiary ........... (6,897) (4,113) 10,160 9,784 (775)
Dividends on preferred shares of a subsidiary ...... 4,942 4,942 4,942 4,942 4,942
Net income (loss) applicable to common shares(1) .. (11,839) (9,055) 5,218 4,842 (5,717)
Net income (loss) per common share(1) .............. (0.86) (0.67) 0.38 0.37 (0.54)
Weighted average number of common shares
outstanding ................................... 13,701,419 13,480,067 13,620,728 13,065,414 10,633,142
OTHER DATA:
Cash flow from operations .......................... $ 50,098 $ 37,847 $ 49,473 $ 41,841 $ 13,186
Net natural gas and oil capital expenditures ....... $ 55,021 $ 92,573 $ 69,453 $ 57,673 $ 100,502
BALANCE SHEET DATA (at end of period):
Working capital .................................... $ 13,604 $ 2,392 $ 22,676 $ 42,854 $ 11,216
Total assets(1) .................................... $ 330,758 $ 318,584 $ 285,125 $ 267,442 $ 204,555
Long-term debt ..................................... $ 10,000 $ 40,000 $ -- $ -- $ --
Shareholders' equity(1) ............................ $ 271,101 $ 234,946 $ 249,466 $ 244,122 $ 190,534
OPERATING DATA:
Average Daily Net Production:
Natural gas (mmcf) ............................ 70.0 67.1 64.2 59.8 29.5
Oil and liquids (bbls) ........................ 3,913 3,012 2,261 2,005 1,643
Natural gas equivalent (mmcfe) ................ 93.4 85.2 77.8 71.8 39.3
Average Sales Price:
Natural gas (per mcf) ......................... $ 2.02 $ 1.99 $ 2.33 $ 2.09 $ 1.54
Oil and liquids (per bbl) ..................... 17.05 11.74 18.94 20.99 16.94
Average Production Cost:
Natural gas (per mcf) ......................... $ 0.21 $ 0.30 $ 0.27 $ 0.25 $ 0.35
Oil and liquids (per bbl) ..................... 4.60 5.78 5.81 6.57 7.31
</TABLE>
Notes:
(1) Reference is made to Note 12 of the Notes to Consolidated Financial
Statements which describes the impact of United States accounting
principles.
(2) This amount reflects write-downs in the carrying value of U.K. and
Libyan gas and oil properties in 1999 and 1998 in accordance with full
cost accounting rules under Canadian GAAP.
14
<PAGE> 17
ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS
You should read the following discussion and analysis in conjunction with our
1999 audited consolidated financial statements. The information contains
forward looking statements that are subject to risk factors associated with the
oil and gas business. We believe that the expectations reflected in these
statements are reasonable, but may be affected by a variety of factors
including, but not limited to: price fluctuations, currency fluctuations,
drilling and production results, imprecision of reserve estimates, loss of
market, industry competition, environmental risks and capital restrictions.
Our financial statements and information are reported in U.S. dollars and are
prepared based upon Canadian generally accepted accounting principles.
Substantially all of our revenues and a significant portion of our operating
expenses are realized or incurred in U.S. dollars. For a discussion of the
effect of differences in generally accepted accounting principles in Canada and
the U.S. on our financial statements, see Note 12 to our audited consolidated
financial statements. For purposes of calculating unit costs, oil and ngls are
converted to mcf equivalents using a conversion rate of one bbl of oil equal to
six thousand cubic feet of natural gas.
1999 OVERVIEW
We have achieved a three year record of 10% compounded annual production
growth. Production in 1999 averaged 112.9 mmcfe/d (93.4 mmcfe/d after
royalties) compared to 103.2 mmcfe/d (85.2 mmcfe/d after royalties) in 1998 and
93.4 mmcfe/d (77.8 mmcfe/d after royalties) in 1997. This growth has been
financed by cash flow, modest debt and equity.
Primarily as a result of higher production volumes and recovering commodity
prices, which resulted in increased net production revenues, cash flow from
operations, after preferred share dividends, was $50.1 million in 1999 compared
to $37.8 million in 1998 and $49.5 million in 1997.
Our average natural gas price was $2.02 per mcf in 1999 compared to $1.99 in
1998 and $2.33 in 1997. Our combined average crude oil and ngls price per bbl
was $17.05 in 1999 compared to $11.74 in 1998 and $18.94 in 1997.
Net capital spending was $55.1 million in 1999 compared to $92.7 million in
1998 and $69.8 million in 1997. Proved reserve finding and development costs in
1999 were $0.68 per mcfe ($0.84 per mcfe after royalties) compared to $1.54 per
mcfe ($2.04 per mcfe after royalties) in 1998 and $1.46 per mcfe ($1.80 per
mcfe after royalties) in 1997.
We increased our proved reserves for the sixth consecutive year, adding in
excess of 80 bcfe (65 bcfe after royalties), corresponding to a reserve
replacement rate of 197% (194% after royalties). Total proved reserves
increased to 290.3 bcfe (239.7 bcfe after royalties).
Our proved reserves at December 31, 1999 had a present value of future net cash
flows before income taxes, discounted at 10%, of $266.5 million (1998 - $152.5
million; 1997 - $238.3 million).
PRODUCTION
Our average daily combined natural gas and oil production increased nine
per cent to 112.9 mmcfe/d (93.4 mmcfe/d after royalties) in 1999 from 103.2
mmcfe/d (85.2 mmcfe/d after royalties) in 1998 and 93.4 mmcfe/d (77.8 mmcfe/d
after royalties) in 1997. Natural gas comprised 76% (75% after royalties) of our
production volume in 1999 compared to 80% (79% after royalties) in 1998 and 83%
(before and after royalties) in 1997. In 1999, natural gas production was 31.1
bcf (25.5 bcf after royalties) compared to 30.0 bcf (24.5 bcf after royalties)
in 1998 and 28.3 bcf (23.4 bcf after royalties) in 1997. In 1999, oil and
natural gas liquids production was 1,683 mbbls (1,428 mbbls after royalties)
compared to 1,271 mbbls (1,100 mbbls after royalties) in 1998 and 962 mbbls (825
mbbls after royalties) in 1997.
Eighty-eight per cent of 1999 natural gas production came from our interests in
111 wells in the U.S. Gulf of Mexico region compared to 89% (108 wells) in 1998
and 85% (100 wells) in 1997. In addition, 54% of our 1999 oil and ngls
production came from our interests in these wells (1998 - 28%; 1997 - 25%).
Comparing 1999 and 1998, a significant factor affecting increased production
volumes was the commencement of production at South Marsh Island 39 during the
first quarter of 1999. During 1999, South Marsh Island 39 contributed 1.8 bcf
(1.5 bcf after royalties) to our natural gas production and 456 mbbls (380
mbbls after royalties) to oil production. Initial production at Main Pass 225 D
and Main Pass 250 B contributed 0.3 bcf (0.2 bcf after royalties) and 1.0 bcf
(0.9 bcf after royalties), respectively, to 1999 natural gas production.
Contributing to increased annual production in 1999 was a full year of
production from both East Cameron 34 and High Island 207 B.
15
<PAGE> 18
Comparing 1998 and 1997, the primary contributors to natural gas production
growth were East Cameron 349 and Main Pass 222/223. The Aneth and Ratherford
Units in the Four Corners area of Utah were the primary contributors to
increased oil production. East Cameron 349 commenced production in the fourth
quarter of 1997. In 1998 natural gas production from this field increased 0.9
bcf (0.8 bcf after royalties) to 1.3 bcf (1.1 bcf after royalties) and oil
production, though constrained by repairs to a third party pipeline during the
early part of the year, increased 148 mbbls (124 mbbls after royalties) to 184
mbbls (154 mbbls after royalties). Development drilling in 1998, combined with
increased transportation capacity via the Dauphin Island Gas Gathering System,
increased Main Pass 222/223 natural gas production by 2.7 bcf (2.0 bcf after
royalties) to 4.7 bcf (3.5 bcf after royalties). In 1998, we participated in 30
multi-lateral horizontal development wells in the Aneth and Ratherford Units in
addition to a tertiary carbon dioxide recovery pilot project in the Aneth Unit.
During 1998, combined oil and ngls production from these Units increased by 106
mbbls (93 mbbls after royalties) to 800 mbbls (699 mbbls after royalties).
PRODUCTION SUMMARY
<TABLE>
<CAPTION>
Before royalties After royalties
------------------- ------------------
1999 1998 1997 1999 1998 1997
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Natural gas (mmcf/d)
U.S. 75.5 73.8 66.6 60.2 58.6 53.2
U.K. 9.8 8.5 11.0 9.8 8.5 11.0
----- ----- ----- ----- ----- -----
Total 85.3 82.3 77.6 70.0 67.1 64.2
===== ===== ===== ===== ===== =====
Oil and ngls (bbls/d) 4,611 3,482 2,636 3,913 3,012 2,261
===== ===== ===== ===== ===== =====
Total natural gas equivalent
(mmcfe/d) 112.9 103.2 93.4 93.4 85.2 77.8
===== ===== ===== ===== ===== =====
Total annual equivalent
(bcfe) 41.2 37.7 34.1 34.1 31.1 28.4
===== ===== ===== ===== ===== =====
</TABLE>
GAS AND OIL MARKETING
Most of our natural gas reserves are located in the U.S. Gulf of Mexico region
where ready deliverability through numerous large capacity pipelines and
auxiliary feeder pipelines provides flexibility in marketing our production in
the U.S. spot market. Natural gas prices in the U.S. and in the U.K. are largely
determined by competitive market forces.
Most of the natural gas produced by us has been marketed since 1989 by Highland
Energy Company, an aggregator for several U.S. natural gas producers.
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 U.S. Gulf of Mexico
oil and natural gas liquids production is marketed by Highland Energy Company.
Market prices of oil and natural gas fluctuate and can adversely affect our
operating results. We sell most of our natural gas under short term contractual
arrangements and do not engage in speculative forward selling of volumes that
cannot be physically delivered. 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.
At December 31, 1999, we had entered into natural gas forward contracts through
Highland Energy Company and an oil forward contract with the regional refiner.
The forward contracts, all of which are for 2000 production, are for the
physical delivery of natural gas volumes totaling 6.1 bcf (approximately 15% to
20% of our forecast 2000 volume), at an average price, net of transportation, of
$2.49 per mcf, and for the physical delivery of 90 mbbls (approximately 5% of
our forecast 2000 volume) of oil, at an average price of $19.00 per bbl. Forward
contract volumes at both December 31, 1998 and 1997 were immaterial.
NATURAL GAS
Our composite average natural gas price was $2.02 per mcf in 1999 compared to
$1.99 in 1998 and $2.33 in 1997. The mild North American winter of 1998-1999 had
a significant downward effect on 1998 U.S. natural gas prices, which were 33%
lower in the fourth quarter than in the corresponding period in 1997. Natural
gas prices in the U.S. continued to be extremely weak during the first quarter
of 1999, when we received an average of $1.54 per mcf. Thereafter, prices
increased to an average of $2.39 per mcf in the fourth quarter of 1999. For the
full 1999 year, our average U.S. natural gas price was $2.16 per mcf
(1998-$2.06; 1997-$2.47) and our average U.K. natural gas price was $0.96 per
mcf (1998-$1.40; 1997-$1.49).
16
<PAGE> 19
OIL AND NGLS
Our combined average oil and ngls price per bbl was $17.05 in 1999 compared to
$11.74 in 1998 and $18.94 in 1997. In 1998, the combination of economic
problems in Asia, the mild North American winter and aggressive international
competition for market share caused oil prices to fall sharply. Oil prices
continued to be extremely weak during the first quarter of 1999. We received an
average of $10.94 per bbl during the first quarter of 1999 and the recovery in
prices resulted in an average of $21.67 per bbl during the fourth quarter of
1999.
REVENUE
The 1999 growth in our combined natural gas and oil production volumes was
complemented by the recovery in commodity prices. As a result, 1999 production
revenue increased 22% from 1998 to $91.5 million ($75.4 million after
royalties). 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 11% from 1997 to $74.9 million
($61.6 million after royalties).
INTEREST AND OTHER REVENUE
Interest and other revenue 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.
NET REVENUE
<TABLE>
<CAPTION>
1999 1998 1997
- ---------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Natural gas, after royalties $50,765 $48,501 $ 53,937
Oil and ngls, after royalties 24,601 13,114 15,690
------- ------- --------
Production revenue, after royalties 75,366 61,615 69,627
Interest and other revenue 1,081 2,776 2,428
------- ------- --------
Total net revenue $76,447 $64,391 $ 72,055
======= ======= ========
</TABLE>
PRICE/VOLUME VARIANCES
<TABLE>
<CAPTION>
Natural gas
--------------------------- Oil
U.S. U.K. Total and ngls Total
- ---------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C>
1997 production revenue, after royalties $47,946 $ 5,991 $53,937 $15,690 $ 69,627
------- ------- ------- ------- --------
Price variance (8,706) (277) (8,983) (7,773) (16,756)
Volume variance 4,925 (1,378) 3,547 5,197 8,744
------- ------- ------- ------- --------
1998 production revenue, after royalties 44,165 4,336 48,501 13,114 61,615
------- ------- ------- ------- --------
Price variance 2,064 (1,597) 467 7,626 8,093
Volume variance 1,102 695 1,797 3,861 5,658
------- ------- ------- ------- --------
1999 production revenue, after royalties $47,331 $ 3,434 $50,765 $24,601 $ 75,366
======= ======= ======= ======= ========
</TABLE>
EXPENSES
ROYALTIES
Royalties include payments made to federal and state governments, freehold
land owners and other third parties. Our U.S. Gulf of Mexico properties in U.S.
federal waters generally carry a one-sixth (16-2/3%) royalty rate. Some of
these offshore properties carry overriding royalties ranging from 1.1% to 10%.
In 1999, the effective overriding royalty rate was 2.2% (1998-2.7%; 1997-2.7%).
Production from the Aneth and Ratherford Units is subject to a 12.5% royalty.
The Aneth unit carries an additional royalty burden of approximately 2%. The
Northeast Wright field, in Louisiana, is subject to a royalty rate of 26%.
The U.K. properties carry no royalty obligations. As the U.K. properties
mature, natural production declines will reduce the proportion of this
production in our mix and our composite royalty per mcfe can be expected to
increase.
We pay no overriding royalties to management or staff.
17
<PAGE> 20
ROYALTIES
<TABLE>
<CAPTION>
1999 1998 1997
-----------------------------------------------------------------------------------
(in thousands except per unit
amounts and percentages)
<S> <C> <C> <C>
Natural gas $ 11,699 $ 11,211 $ 12,007
Oil and ngls 4,442 2,035 2,585
-------- -------- --------
Total $ 16,141 $ 13,246 $ 14,592
======== ======== ========
Royalties ($/mcfe) $0.39 $0.35 $0.43
Composite royalty rate 17.6% 17.7% 17.3%
</TABLE>
PRODUCTION COSTS
Our production costs in 1999 decreased 12% from 1998, a result of non-recurring
significant items in 1998 and the termination of the Libyan production test.
Our production costs in 1998 increased 23% from 1997 primarily as a result of
several weather-induced evacuations of manned facilities in the U.S. Gulf of
Mexico during the third quarter of 1998 and significant pipeline repair costs
in the South Pass area.
Production costs for U.S. Gulf of Mexico region properties were $0.25 per mcfe
($0.31 per mcfe after royalties) in 1999 compared to $0.32 per mcfe ($0.41 per
mcfe after royalties) in 1998 and $0.30 per mcfe ($0.37 per mcfe after
royalties) in 1997. Production costs for the Aneth and Ratherford Units, which
are primarily oil producing properties where secondary and tertiary recovery
methods are being used, were $1.15 per mcfe ($1.32 per mcfe after royalties) in
1999 compared to $0.99 per mcfe ($1.13 per mcfe after royalties) in 1998 and
$1.06 per mcfe ($1.21 per mcfe after royalties) in 1997.
PRODUCTION COSTS
<TABLE>
<CAPTION>
1999 1998 1997
-------------------------------------------------------------------------------------
(in thousands except per unit amounts)
<S> <C> <C> <C>
Lifting costs $ 12,929 $14,899 $ 11,569
Production taxes 1,391 1,456 1,756
-------- -------- -------
Production costs $ 14,320 $ 16,355 $ 13,325
======== ======== ========
Production costs ($/mcfe)
Before royalty volumes $0.35 $0.43 $0.39
After royalty volumes $0.42 $0.53 $0.47
</TABLE>
Production from the Aneth and Ratherford Units and the Northeast Wright Field
in Louisiana is subject to production and severance taxes. As a result of the
price dependent methodologies used to calculate these taxes, and the
anticipated additional production from the Broussard #1 well in the Northeast
Wright Field, we expect that our production taxes will nearly double in 2000.
GENERAL AND ADMINISTRATIVE
Our general and administrative costs decreased 5% in 1999 compared to 1998 and
increased 11% for 1998 compared to 1997. Performance-based compensation
payments were lower in 1999 than in 1998 and higher in 1998 than in 1997.
GENERAL AND ADMINISTRATIVE
<TABLE>
<CAPTION>
1999 1998 1997
--------------------------------------------------------------------------------------
(in thousands except per unit
amounts and percentages)
<S> <C> <C> <C>
Gross general and administrative $ 8,527 $ 9,108 $ 7,859
Capitalized (3,947) (4,312) (3,551)
-------- -------- -----
General and administrative expense $ 4,580 $ 4,796 $ 4,308
======== ======== =======
General and administrative ($/mcfe)
Before royalty volumes $0.11 $0.13 $0.13
After royalty volumes $0.13 $0.15 $0.15
Capitalization ratio 46% 47% 45%
</TABLE>
INTEREST
Interest expense increased to $2.5 million in 1999 compared to $0.4 million in
1998 due to greater credit facility utilization. Our weighted average debt
outstanding during 1999 was $42.1 million compared to $12.3 million in 1998.
The effective interest rate on our outstanding debt for 1999 was 5.93% compared
to 6.19% in 1998. The interest rate on our debt at December 31, 1999 was 7.00%.
18
<PAGE> 21
DEPLETION AND AMORTIZATION
Depletion and amortization expense in 1999 increased 22% compared to 1998 as a
result of a 9% increase in production and a 12% increase in the average
depletion rate. The downward revision in our proved reserves at December 31,
1998 that resulted from low oil prices at that date contributed to the increase
in our effective depletion rate. Comparing 1998 and 1997, depletion and
amortization expense increased 14%, the result of an 11% increase in units of
production and a 4% increase in the average depletion rate.
Accounting rules require that we review regularly, on a country-by-country
basis, the carrying value of our oil and gas properties 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.
Full cost accounting rules allow, but do not require, companies to exclude costs
of acquiring and evaluating unproved properties from their depletion cost
centres, but if such costs are excluded, they must be separately assessed for
impairment. Our policy on depletion does not exclude such costs from their
respective depletion cost centres. The scope of our Libyan venture was such that
we did not apply this policy. Libyan costs were excluded and separately assessed
for impairment.
In Libya, we and our partners concluded that the multi-year exploration program,
and the production test which commenced in December 1997, were not commercial
under the terms of the concession and therefore terminated the venture. As a
result, additional depletion of $11.4 million was recorded in the second quarter
of 1999 to eliminate the investment. An impairment provision of $5.1 million was
recorded at December 31, 1998 in respect of one of the Libyan concessions upon
which no further exploration had been planned.
In the U.K. we recorded ceiling test impairments due to very low spot market
prices for natural gas at December 31, 1999, and downward reserve revisions at
December 31, 1998.
TAXES
We have $224.5 million in U.S. tax pools and $34.8 million in Canadian tax pools
to reduce future taxable income. The only current income taxes expected for the
next several years are Canadian federal taxes on capital, the amounts of which
are currently expected to remain comparable with 1999 and 1998.
NETBACK
<TABLE>
<CAPTION>
NETBACK ANALYSIS ($/mcfe) Before royalties After royalties
------------------------ ------------------------
1999 1998 1997 1999 1998 1997
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
Gross production revenue $ 2.22 $ 1.99 $ 2.47
Royalties (0.39) (0.35) (0.43)
------ ------ ------
Production revenue, after royalties 1.83 1.64 2.04 $ 2.21 $ 1.98 $ 2.45
Production costs (0.35) (0.43) (0.39) (0.42) (0.53) (0.47)
------ ------ ------ ------ ------ ------
Gross margin 1.48 1.21 1.65 1.79 1.45 1.98
General and administrative expenses (0.11) (0.13) (0.13) (0.13) (0.15) (0.15)
------ ------ ------ ------ ------ ------
Gross profit 1.37 1.08 1.52 1.66 1.30 1.83
Interest and other (0.03) 0.05 0.07 (0.04) 0.08 0.08
Preferred share dividends (0.12) (0.13) (0.14) (0.15) (0.16) (0.17)
------ ------ ------ ------ ------ ------
Cash flow from operations $ 1.22 $ 1.00 $ 1.45 $ 1.47 $ 1.22 $ 1.74
====== ====== ====== ====== ====== ======
Annual production volume (bcfe) 41.2 37.7 34.1 34.1 31.1 28.4
====== ====== ====== ====== ====== ======
</TABLE>
19
<PAGE> 22
CAPITAL EXPENDITURES
Natural resource capital expenditures were $55.0 million in 1999, compared to
$92.6 million in 1998 and $69.5 million in 1997.
DRILLING RESULTS
In 1999, our exploratory drilling success rate in the U.S. Gulf of Mexico region
was 73% compared to 43% in 1998 and 47% in 1997. Including development wells,
our success rate in the region was 78% in 1999 compared to 58% in 1998 and 63%
in 1997. Drilling in all areas, including extensive development drilling in the
Utah oil producing units in 1998 and 1997, resulted in success rates of 70% in
1999 and 84% in both 1998 and 1997.
<TABLE>
<CAPTION>
DRILLING RESULTS (WELLS) 1999 1998 1997
------------- ------------- -------------
GROSS NET GROSS NET GROSS NET
----- ----- ----- ----- ----- -----
<S> <C> <C> <C> <C> <C> <C>
U.S. - Gulf of Mexico region
Successful 14 5.37 11 2.79 17 5.09
Dry 4 1.70 8 3.45 10 3.49
----- ----- ----- ----- ----- -----
18 7.07 19 6.24 27 8.58
----- ----- ----- ----- ----- -----
U.S. - Other
Successful -- -- 30 6.01 34 6.15
Dry -- -- -- -- -- --
----- ----- ----- ----- ----- -----
-- -- 30 6.01 34 6.15
----- ----- ----- ----- ----- -----
Total U.S.
Successful 14 5.37 41 8.80 51 11.24
Dry 4 1.70 8 3.45 10 3.49
----- ----- ----- ----- ----- -----
18 7.07 49 12.25 61 14.73
----- ----- ----- ----- ----- -----
Foreign
Dry 2 0.25 -- -- -- --
----- ----- ----- ----- ----- -----
Total drilling
Successful 14 5.37 41 8.80 51 11.24
Dry 6 1.95 8 3.45 10 3.49
----- ----- ----- ----- ----- -----
20 7.32 49 12.25 61 14.73
===== ===== ===== ===== ===== =====
Chieftain operated wells 5 2.75 2 2.00 2 1.67
===== ===== ===== ===== ===== =====
</TABLE>
In addition to the wells described above, at December 31, 1999 we had interests
in three (0.62 net) wells which were drilling and one (0.50 net) well which was
being evaluated. No wells were drilling or being evaluated at December 31, 1998;
seven (1.75 net) wells were drilling at December 31, 1997.
Five additional wells were drilled in 1999 on our U.S. Gulf of Mexico region
acreage at no cost to us, one of which resulted in a natural gas well and four
of which were unsuccessful. In 1998, one successful natural gas well was drilled
on our U.S. Gulf of Mexico region acreage at no cost to us. There was no
corresponding activity in 1997.
CAPITAL FIELD DEVELOPMENT ACTIVITY
Our principal development activity in 1999 was at South Marsh Island 39 where
two satellite platforms, a host platform and associated pipelines were
installed. Installation of production facilities at Main Pass 225 D and Main
Pass 250 B were the other significant development activities during the year.
20
<PAGE> 23
<TABLE>
<CAPTION>
CAPITAL EXPENDITURES SUMMARY
1999 1998 1997
------- ------- -------
(in thousands)
<S> <C> <C> <C>
Property acquisition costs:
U.S. $ 5,352 $ 7,903 $ 9,164
U.K. 28 115 137
------- ------- -------
5,380 8,018 9,301
------- ------- -------
Sale of producing properties:
U.S. (155) -- --
------- ------- -------
Purchase of producing properties:
U.S. -- 883 --
------- ------- -------
Exploration costs:
U.S. 28,753 43,317 35,540
U.K. 9 72 115
Other foreign 1,531 606 1,207
------- ------- -------
30,293 43,995 36,862
------- ------- -------
Development costs:
U.S. 19,542 39,606 23,260
U.K. (39) 71 30
------- ------- -------
19,503 39,677 23,290
------- ------- -------
$55,021 $92,573 $69,453
======= ======= =======
</TABLE>
FINDING AND DEVELOPMENT COSTS
COST OF RESERVE ADDITIONS
For 1999, finding and development costs were $0.68 per mcfe ($0.84 after
royalties) based on proved reserves added.
In calculating finding costs, a number of anomalies between periods are created
by the timing of expenditures and the phase of the exploration cycle. This
relates particularly to lease acquisitions and to major facility construction,
as well as to recognition and revision of reserves. Multi-year cumulative
average calculations are a more meaningful reflection of a company's ability to
find and produce reserves effectively. We have included both a three-year
calculation and one year components in the following table.
<TABLE>
<CAPTION>
FINDING COST ANALYSIS
Cumulative
1999 1998 1997 1997-1999
---- ---- ---- ---------
(in thousands except unit and per unit amounts)
<S> <C> <C> <C> <C>
Capital expenditures $55,021 $ 92,573 $ 69,453 $ 217,047
======= ======== ======== =========
Proved, before royalties
Reserve additions (mmcfe) 80,898 59,999 47,469 188,366
Finding costs ($/mcfe) $ 0.68 $ 1.54 $ 1.46 $ 1.15
Proved, after royalties
Reserve additions (mmcfe) 65,796 45,381 38,668 149,845
Finding costs ($/mcfe) $ 0.84 $ 2.04 $ 1.80 $ 1.45
</TABLE>
RESERVE REPLACEMENT
For the sixth consecutive year, we added more proved reserves than we produced,
on an annual all sources basis, with total proved reserves increasing to 290.3
bcfe (239.7 bcfe after royalties).
The success of our strategy of growth through exploration is demonstrated by
the increase in reserves replaced through drilling. Ninety-five per cent (94%
after royalties) of our increase in proved U.S. reserves in 1999 resulted from
extensions, discoveries and other additions, compared to 90% (93% after
royalties) in 1998 and 69% (70% after royalties) in 1997.
21
<PAGE> 24
RESERVES
Reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum
engineers, as to our U.S. reserves and by ourselves as to our U.K. reserves,
contain estimates of our total proved reserves, before and after royalty
deductions, as described below. U.K. reserves comprise 2.2% (2.7% after
royalties) of our total proved reserves on a bcfe basis.
RESERVE RECONCILIATION
<TABLE>
<CAPTION>
Before royalties After royalties
------------------------------- ----------------------------------
Natural gas Oil and ngls Natural gas Oil and ngls
(mmcf) (mbbls) (mmcf) (mbbls)
-------- -------- -------- --------
<S> <C> <C> <C> <C>
December 31, 1997 149,443 13,006 125,097 11,313
-------- -------- -------- --------
Purchase of producing properties 4,745 18 3,512 14
Revision of previous estimates 5,564 (1,502) 2,700 (1,339)
Extensions, discoveries and other additions 29,360 4,872 22,268 4,142
Sale of proved properties -- -- -- --
-------- -------- -------- --------
Net additions 39,669 3,388 28,480 2,817
Production (30,048) (1,167) (24,504) (996)
-------- -------- -------- --------
December 31, 1998 159,064 15,227 129,073 13,134
-------- -------- -------- --------
Purchase of producing properties -- -- -- --
Revision of previous estimates (5,786) 1,607 (4,858) 1,480
Extensions, discoveries and other additions 64,127 2,152 51,251 1,753
Sale of proved properties -- -- -- --
-------- -------- -------- --------
Net additions 58,341 3,759 46,393 3,233
Production (31,119) (1,656) (25,533) (1,401)
-------- -------- -------- --------
December 31, 1999 186,286 17,330 149,933 14,966
======== ======== ======== ========
</TABLE>
PROVED RESERVE LIFE INDEX (years)
<TABLE>
<CAPTION>
Before royalties After royalties
----------------------------------- -----------------------------
1999 1998 1997 1999 1998 1997
-------- ------- --------- -------- ------- -------
<S> <C> <C> <C> <C> <C> <C>
Natural gas 6.0 5.3 5.3 5.9 5.3 5.3
Oil and ngls 10.5 13.0 13.7 10.7 13.2 13.9
Equivalent 7.1 6.8 6.7 7.1 6.8 6.8
</TABLE>
Reserve life indexes are the quotients of year end reserve volumes divided by
the year then ended's associated production volumes.
RESERVES SUMMARY - NATURAL GAS (mmcf)
<TABLE>
<CAPTION>
Before royalties After royalties
------------------------------------ ------------------------------------
1999 1998 1997 1999 1998 1997
---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Developed producing - U.S. 63,822 70,082 55,013 50,531 55,418 43,979
- U.K. 6,376 10,108 18,317 6,376 10,108 18,317
Developed non-producing - U.S. 58,986 41,974 32,660 46,024 33,906 26,843
Undeveloped - U.S. 57,102 36,900 43,453 47,002 29,641 35,958
---------- ---------- ---------- ---------- ---------- ----------
Total proved reserves 186,286 159,064 149,443 149,933 129,073 125,097
========== ========== ========== ========== ========== ==========
</TABLE>
RESERVES SUMMARY - OIL AND NGLs (mbbls)
<TABLE>
<CAPTION>
Before royalties After royalties
------------------------------------ ------------------------------------
1999 1998 1997 1999 1998 1997
- ---------------------------------- ---------- ---------- ---------- ---------- ---------- ----------
<S> <C> <C> <C> <C> <C> <C>
Proved reserves:
Developed producing - U.S. 7,447 5,430 8,209 6,580 4,739 7,241
- U.K. 20 27 59 20 27 59
Developed non-producing - U.S. 1,633 3,329 1,323 1,347 2,768 1,097
Undeveloped - U.S. 8,230 6,441 3,415 7,019 5,600 2,916
---------- ---------- ---------- ---------- ---------- ----------
Total proved reserves 17,330 15,227 13,006 14,966 13,134 11,313
========== ========== ========== ========== ========== ==========
</TABLE>
22
<PAGE> 25
NET FUTURE CAPITAL EXPENDITURES
The reserve reports incorporate future capital expenditures, spanning a period
of approximately 24 years (1998-20 years; 1997-20 years), required to bring
proved undeveloped reserves to production, to maintain proved producing
reserves, and to provide for future abandonment.
<TABLE>
<CAPTION>
NET FUTURE CAPITAL EXPENDITURES
1999 1998 1997
--------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Proved developed $ 28,120 $ 29,131 $ 24,004
Proved undeveloped 56,753 32,532 34,655
-------- -------- --------
Total $ 84,873 $ 61,663 $ 58,659
======== ======== ========
</TABLE>
RESERVE VALUE RECONCILIATION
The present value of our reserves, discounted at 10% and using constant natural
gas and oil prices in effect on the balance sheet date, increased 47% to $224.5
million at December 31, 1999 compared $152.5 million at December 31, 1998 and
$199.6 million at December 31, 1997.
Our reserves are estimated using year-end prices which, at December 31, 1999,
were $20.40 per bbl for oil and $2.51 per mcf for U.S. natural gas. The use of
year end prices imposes a stringent economic limit on estimates of reserves
recoverable in the future. If escalating prices were applied, greater volumes of
reserves would be recoverable.
<TABLE>
<CAPTION>
ESTIMATED PRESENT VALUE OF PROVED RESERVES
1999 1998 1997
-------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Proved developed $193,935 $135,867 $187,697
Proved undeveloped 72,539 16,641 50,615
-------- -------- --------
Total PV-10 value before income taxes $266,474 $152,508 $238,312
======== ======== ========
Standardized measure of discounted estimated future net cash flows after income taxes $224,533 $152,508 $199,573
======== ======== ========
</TABLE>
<TABLE>
<CAPTION>
PRICES USED IN CALCULATING PROVED RESERVES
1999 1998 1997
------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Natural gas (per mcf)
U.S. $ 2.51 $ 2.15 $ 2.74
U.K. $ 0.99 $ 1.74 $ 1.76
Oil and ngls (per bbl) $20.40 $ 9.72 $16.69
</TABLE>
CAPITAL RESOURCES AND LIQUIDITY
Our primary sources of cash are funds generated from 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 $50.1 million in 1999 compared to $37.8 million in
1998 and $49.5 million in 1997. The variances are primarily a function of
fluctuating revenues caused by the volatility of commodity prices.
Our financing activities in 1999 provided $16.2 million of cash, the net result
of:
o the sale of 2,875,000 common shares for $46.3 million net of issue costs;
o the net repayment of $30 million of our revolving credit facility, which
increased the unutilized portion to $90 million; and
o the purchase for cancellation of 7,500 common shares at the cost of $0.1
million under our share repurchase program, which expired on November 1,
1999.
23
<PAGE> 26
Financing activities during 1998 provided $34.5 million of cash, the net result
of:
o the drawdown of $40 million of our revolving credit facility;
o the exercise of employee share options for $0.4 million; and
o the purchase for cancellation of 294,700 common shares at the cost of $5.9
million under our share repurchase program.
Financing activities during 1997 provided $0.1 million of cash, which was the
net result of:
o the exercise of employee share options for $1.0 million; and
o the purchase for cancellation of 36,300 common shares at the cost of $0.9
million under our share repurchase program.
Cash used in natural resource investing activities decreased to $55.0 million
for 1999 compared to $92.6 million and $69.5 million for 1998 and 1997,
respectively. The composition of our natural resource investing activities is
as follows:
<TABLE>
<CAPTION>
COMPOSITION OF NATURAL RESOURCE INVESTING ACTIVITIES
1999 1998 1997
------- ------- -------
(in thousands)
<S> <C> <C> <C>
Leasehold and seismic $ 7,854 $10,757 $15,451
Purchase (sale) of producing properties (155) 883 --
Exploratory drilling 27,819 41,256 30,712
Development drilling 9,775 16,517 15,178
Capital field development 9,728 23,160 8,112
------- ------- -------
Total $55,021 $92,573 $69,453
======= ======= =======
</TABLE>
Our December 31, 1999 cash balance of $19.4 million was up $8.8 million from
1998, which, in turn, was down $16.3 million from 1997. We had outstanding
borrowings of $10 million on our $100 million revolving credit facility at
December 31, 1999 (1998 - $40 million; 1997 - $nil). The weighted average
interest rate on our borrowings for 1999 was 5.93% (1998 - 6.19%).
RISK ASSESSMENT
There are a number of risks facing participants in the oil and gas industry.
Some of the risks are common to all businesses while others are industry
specific. The following review includes our approach to managing various risks.
OPERATIONAL RISKS
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 seek to mitigate the foregoing risks by maintaining prudent levels
of 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.
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 U.S. Gulf of
Mexico where wells normally have steeper rates of decline than onshore wells.
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
rig 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 harm our efforts to replace reserves.
24
<PAGE> 27
We seek to limit our financial and operating risks in some 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 3D 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 timing of drilling.
ENVIRONMENTAL AND SAFETY RISKS
U.S. exploration, production and marketing operations are regulated extensively
at the federal, state and local levels. These regulations affect costs, manner
and feasibility of our operations. Changes in, or additions to, regulations
regarding the protection of the environment could increase our compliance costs
and may negatively impact our business. U.S. offshore oil and gas operations are
subject to regulations of the U.S. Department of the Interior which currently
imposes absolute liability upon the lessee under a federal lease for the cost of
pollution clean-up resulting from the lessee's operations, and could subject the
lessee to possible liability for pollution damage.
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.
At present, we believe that our properties are being operated in compliance
with applicable environmental laws and regulations. We do not anticipate that
we will be required in the foreseeable future to expend amounts that are
unusual, in relation to customary industry experience, by reason of
environmental laws and regulations, but we are unable to quantify the ultimate
cost of compliance.
MARKETING RISKS
There is uncertainty as to the prices at which gas and oil we produce may be
sold, and it is possible that under some market conditions the production of
gas and oil from some of our properties may not be commercially feasible. The
availability of a ready market for gas and oil as produced and the price
obtained for such gas and oil depend upon numerous factors beyond our control,
including market considerations, the proximity and capacity of gas and oil
pipelines and processing equipment and governmental regulation. In recent
years, markets for natural gas in the U.S. have been characterized by periods
of oversupply relative to demand. There have been significant fluctuations in
prices for both gas and oil in recent years and there can be no assurance that
prices for gas or oil would not decrease in the future.
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 76% (75% after royalties) of our 1999 equivalent
production, 80% (79% after royalties) of our 1998 production and 83% (before
and after royalties) of our 1997 production. 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 of the U.K.
assets in 1999 and 1998.
Most of the factors which affect natural 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 the Organization of
Petroleum Exporting Countries ("OPEC").
We could 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 impact our cash flow from operating activities. Once incurred,
these write-downs cannot be reversed at a later date.
YEAR 2000
The Year 2000 Issue arose because many computerized systems used two digits
rather than four to identify a year. Date-sensitive systems may recognize the
year 2000 as 1900 or some other date, resulting in errors when information
using year 2000 dates is processed. In addition, similar problems may have
arisen in some systems which used certain dates in 1999 to represent something
other than the date. Although the change in date has occurred, it is not
possible to conclude that all aspects of the Year 2000 Issue that may affect
us, including those related to customers, suppliers, or other third parties,
have been fully resolved.
We have interests in a substantial number of offshore oil and natural gas
production facilities that are operated by others. 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. As of the date of
this Form 10-K report, no Year 2000 Issue related event has occurred that
materially affects us, including shutdown of production, transportation or
processing facilities. Costs that we incurred in preparation for the Year 2000
Issue were not material.
25
<PAGE> 28
CORPORATE GOVERNANCE
The Board of Directors and management of the Company support the guidelines for
corporate governance set forth by the Toronto Stock Exchange and the Company's
corporate governance practices were developed in accordance with these
guidelines.
THE BOARD'S MANDATE
The Board of Directors exercises overall responsibility for the management and
supervision of the Company's affairs. It has established processes, policies
and practices to guide its stewardship of the Company in the areas of strategic
planning; identification and management of the principal risks of the Company's
business; succession planning and management development; communications; and
internal control and management information. Management is responsible for
providing information and maintaining processes which enable the Board to
discharge its responsibilities. Administrative procedures govern the approval
of transactions, the delegation of authority and the signing of documents.
The Board of Directors is kept informed of the Company's operations through
regularly scheduled meetings of the Board and its committees and through
reports and analyses and discussions with management. During 1999, the
directors met at four regularly scheduled meetings. Five additional meetings
were held by telephone conference. Communications between the directors and
management occur as required in addition to the board and committee meetings.
The Board of Directors annually reviews and approves the Company's corporate
strategy. The Board reviews the Company's budget for the following fiscal year,
including operating and financial targets and approves the capital expenditures
for which management is responsible. As part of that process, the objectives of
the Chief Executive Officer and the Chief Operating Officer are reviewed.
Management performance, succession planning and management development are
regularly reviewed by the Compensation Committee and in turn by the Board of
Directors.
The Company's communications strategy and implementation is regularly reviewed
by the Board of Directors. The Board and appropriate Committees review the
Company's Annual Report to Shareholders, Management's Discussion and Analysis,
Management Information Circular, Annual Information Form, Form 10-K Annual
Report, quarterly financial statements, Interim Reports, Form 10-Q Reports and
news releases on major developments before they are distributed. The Company
provides information on its business and financial results on its internet web
site at www.chieftaininternational.com.
THE BOARD'S COMPOSITION
The Board of Directors is comprised of eight members. Having regard to the size
and complexity of the Company's business, the Board considers that eight is the
minimum number of directors required.
The Board of Directors is constituted with a majority of individuals who are
independent, unrelated directors. Three senior officers of the Company are
members of the Board. The Chairman of the Board is a non-executive Chairman who
has not held another office with the Company. The Board meets at least annually
with only the independent, unrelated members in attendance.
The Board of Directors has five committees, as follows. Each of the committees
has four members and all committees are comprised entirely of independent,
unrelated directors. Committees may engage external resources.
AUDIT COMMITTEE
The primary function of the Audit Committee is to assist the Board of Directors
in providing corporate oversight in the areas of financial reporting, internal
control and the audit process. The Committee regularly meets alone with Company
personnel and with the independent auditors. The independent auditors have
access to the Committee at any time. The Committee recommends to the Board for
its approval the financial statements and the annual appointment of external
auditors.
COMPENSATION COMMITTEE
The primary function of the Compensation Committee is to assist the Board of
Directors in carrying out its responsibilities by reviewing compensation
matters and making recommendations to the Board. It considers and recommends to
the Board for approval directors' compensation, appointment and remuneration of
officers and transactions under the share option plan. This Committee reviews
compensation and benefits policies, plans and budgets, salaries of certain
non-officer employees and succession planning.
NOMINATING AND CORPORATE GOVERNANCE COMMITTEE
The Nominating and Corporate Governance Committee assists the Board by
reviewing corporate governance and Board nomination matters and making
recommendations to the Board as appropriate. The Committee advises the Board on
such matters as
26
<PAGE> 29
the size and composition of the Board of Directors and its committees, nominees
for the election of directors and corporate governance practices.
PENSION COMMITTEE
The Pension Committee reviews generally and makes recommendations to the Board
of Directors with regard to the Company's retirement plans, related agreements
and the appointment and performance of retirement fund investment managers.
RESERVE COMMITTEE
The primary function of the Reserve Committee is to review the Company's
externally disclosed oil and gas reserve estimates. The Committee reviews the
reports of the independent engineers charged with evaluating the Company's
reserves and also reviews the selection of the independent engineers and the
scope of their work.
OUTLOOK AND PROSPECTS FOR FUTURE GROWTH
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:
o Focus on the U.S. Gulf of Mexico region. We focus our operations on the
U.S. Gulf of Mexico region where we have acquired a significant
exploration acreage position and assembled a substantial 3D 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.
o 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 3D seismic and other data and also
review prospects generated by others. Our Board of Directors has approved
a 2000 budget of $86 million for exploration and development capital
expenditures and we expect to use approximately $50 million of this amount
for exploration activities. We are currently drilling or plan to drill
approximately 27 exploratory and development wells in the U.S. Gulf of
Mexico region in 2000. Approximately two-thirds of these will be
exploration wells and the remainder are development wells to follow up the
1999 discoveries.
o Manage drilling risks through joint ventures and the use of advanced
technologies. As described under Operational Risks on page 24.
o 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.
OUR STRENGTHS
We believe that our future performance and historical success are directly
related to the following combination of strengths:
o Substantial inventory of drilling projects in the U.S. Gulf of Mexico
region. In the U.S. Gulf of Mexico region, we have generated an inventory
of over 35 drilling prospects. All of these locations have been evaluated
and defined using 3D 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.
o Proven exploratory expertise. Our ability to define and participate in
successful prospects in the U.S. Gulf of Mexico is demonstrated by our
exploratory drilling success rate in the U.S. Gulf of Mexico region of 73%
for 1999.
o Experienced technical team. Our technical team is comprised of highly
respected industry professionals with an average of more than twenty years
of industry experience. We believe our exploration success is a direct
result of this team's geologic, geophysical, engineering and technical
analysis.
o Financial flexibility. At December 31, 1999, $90 million was available
under our revolving credit facility. We seek to maintain low levels of
debt in order to be able to respond quickly to drilling or acquisition
opportunities.
27
<PAGE> 30
OUR LOOK FORWARD
The fundamentals for U.S. natural gas production remain very positive with the
U.S. Energy Information Administration reporting natural gas demand growing at
an average rate of two per cent annually while domestic natural gas
deliverability is showing a modest decline. Extremely mild weather, which had a
significant impact on natural gas demand in 1998, continues to be a factor.
Temperatures through much of the U.S. were considerably warmer than normal in
the fall and early winter of 1999. Natural gas in storage remains at relatively
high levels and has brought 2000 natural gas prices down somewhat, but
increasing demand and declining deliverability have prevented natural gas
prices from falling to the extremely low levels experienced in the first
quarter of 1999. At year end 1999, the American Gas Association reported that
storage volumes were 20% higher than comparative averages for 1995-1997, but 8%
lower than at year end 1998.
On the natural gas supply side, low commodity prices dramatically reduced
drilling for new supplies which contributed to an estimated 0.5% decline in
domestic production during 1999. The active rig count in the U.S. declined by
25% in 1999 to average 622 rigs from 831 in 1998, according to Baker Hughes. The
rig count was 943 in 1997 and 1,110 in 1990. Reduced demand for drilling rigs
was particularly acute in the U.S. Gulf of Mexico where the average number of
active rigs declined to 127 rigs in 1999 from 156 in 1998 and 168 in 1997. The
Gulf of Mexico Newsletter reported that only 712 wells were drilled in the U.S.
Gulf of Mexico in 1999 compared with 937 in 1998 and 1,124 in 1997. Moreover,
the number of reported discoveries fell to 87 in 1999 from 130 in 1998 and 142
in 1997. As 2000 began, 149 rigs were under contract for a utilization rate of
78% compared with 130 active rigs for a utilization rate of 73% at the end of
1998.
The foregoing supports the conclusion of many industry observers that the
natural gas supply and demand equation is tightening up in the U.S. This
balancing of natural gas supply and demand will confer benefits on properly
poised companies in our industry. We believe that adherence to our strategy
will bring continued growth, and maintain a strong balance sheet which will, in
turn, allow us to be opportunistic and to grow even during periods of low
natural gas and oil prices. We have achieved strong production growth of 10%,
11% and 9% in 1997, 1998 and 1999 respectively. Our planned 2000 exploration
and development program, which we expect to fund from operating cash flow and
our unsecured revolving credit facility, is expected to increase 2000
production volumes by 5 to 10% over 1999 levels. Early in 2000, we will benefit
from new production at the Northeast Wright field in Louisiana and new offshore
facilities will commence production as the year unfolds at High Island
A-510/A-531, High Island A-530, South Timbalier 196, Vermilion 267 and West
Cameron 613. Any delays in initial production from these properties would have
an effect on our 2000 production volumes.
Our capital expenditures can vary significantly as a result of exploration
success, availability of equipment and services and opportunities. We will
continue to monitor capital spending and adjust investment levels in relation
to cash flow projections. If reductions were required to be made to our
budgeted 2000 capital expenditures, economic merit and a longer term view would
be used to make such decisions. Specifically, fewer wildcat wells could be
drilled (either delayed or deleted), bidding at lease sales could be curtailed
and seismic data acquisition could be reduced. If our budgeted 2000 capital
expenditures were to be increased, for reasons other than cost overruns or
expenditures contingent on successful drilling, great care would be taken to
ensure that our associated human resources would be adequate. The nature of
such increased capital expenditures would be dependent upon the opportunities
that arise.
Our long-term growth is dependent upon our ability to effectively reinvest cash
flow. While increased production volumes will improve cash flow, oil and
natural gas prices will have the most significant effect on cash flow levels.
Our view of natural gas prices in the U.S. Gulf of Mexico region is optimistic.
The volatility that can occur in oil prices was clearly demonstrated during
1999. We believe that the control on oil prices that can be exerted by OPEC has
been amply demonstrated. Should OPEC continue to meet its production quota, we
expect that WTI prices in excess of $20 per bbl will prevail. For planning
purposes we have used a more conservative long-term average price of
approximately $18 per bbl. In order to relate the significance of natural gas
and oil prices and volumes to cash flow we have provided sensitivities that
demonstrate the estimated effect of price and volume changes on cash flow.
We expect continued low prices for U.K. production in the near term, largely due
to the excess supply of natural gas.
<TABLE>
<CAPTION>
Impact on 2000 cash flow
SENSITIVITIES $ 000's Per share (basic)
- ----------------------------------------------------------------------------------------------
<S> <C> <C>
Change of $0.10 per mcf in the price of natural gas $2,400 $0.15
Change of $1.00 per bbl in the price of oil 1,500 0.09
Change of 10 mmcf/d 5,900 0.36
Change of 1000 bbls/d $5,300 $0.32
</TABLE>
28
<PAGE> 31
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following consolidated financial statements of Chieftain International,
Inc. and the management's and auditors' reports thereon are included herein. The
financial statements are in U.S. dollars.
Management's Report
Auditors' Report
Consolidated Balance Sheet as at December 31, 1999 and 1998
Consolidated Statement of Income (Loss) and Deficit for the years ended
December 31, 1999, 1998 and 1997
Consolidated Statement of Cash Flows for the years ended December 31,
1999, 1998 and 1997
Notes to Consolidated Financial Statements
Supplementary Financial Information (Unaudited)
29
<PAGE> 32
MANAGEMENT'S REPORT
The accompanying consolidated financial statements and all information in this
annual report are the responsibility of management. The financial statements
have been prepared by management in accordance with Canadian generally accepted
accounting principles. The financial information contained elsewhere in this
annual report is consistent with the consolidated financial statements in all
material respects.
The Company maintains accounting systems and internal controls to provide
reasonable assurance that its financial information is reliable and accurate,
and that its assets are adequately safeguarded. Where necessary, management has
made informed judgments and estimates in the preparation of the financial
statements.
Independent auditors, appointed by the shareholders, have examined the
consolidated financial statements. The Audit Committee of the Board of Directors
meets periodically with management and the independent auditors to review audit,
internal control, accounting policy and financial reporting matters.
The annual consolidated financial statements are approved by the Board of
Directors on the recommendation of the Audit Committee.
/s/ S.A. Milner /s/ R.J. Stefure
S.A. Milner R.J. Stefure
President and Chief Executive Officer Vice President and Controller
February 3, 2000
30
<PAGE> 33
AUDITORS' REPORT
We have audited the consolidated balance sheets of Chieftain International,
Inc. as at December 31, 1999 and 1998 and the consolidated statements of income
(loss) and deficit and cash flows for each of the years in the three-year
period ended December 31, 1999. 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 Canadian 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,
1999 and 1998 and the results of its operations and its cash flows for each of
the years in the three-year period ended December 31, 1999 in accordance with
Canadian generally accepted accounting principles.
/s/ PricewaterhouseCoopers LLP
Chartered Accountants
Edmonton, Alberta
February 3, 2000
31
<PAGE> 34
CONSOLIDATED BALANCE SHEET
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
<TABLE>
<CAPTION>
(Full Cost Method of Accounting) as at December 31, 1999 1998
--------- ---------
(U.S. $ in thousands)
<S> <C> <C>
ASSETS
Current assets:
Cash and short-term deposits $ 19,368 $ 10,613
Accounts receivable 18,855 14,030
Other 750 282
--------- ---------
38,973 24,925
--------- ---------
Capital assets, at cost:
Natural resource properties including exploration and
development thereon (Note 1(e)) 607,401 552,380
Other capital assets 2,157 2,119
--------- ---------
609,558 554,499
Less: Accumulated depletion and amortization 332,409 266,022
--------- ---------
277,149 288,477
Deferred income taxes 14,636 5,182
--------- ---------
$ 330,758 $ 318,584
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued $ 25,369 $ 22,533
Long-term debt (Note 2) 10,000 40,000
Abandonment cost accrual 8,595 7,421
Deferred income taxes 15,693 13,684
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 -
16,224,059 common shares (1998 - 13,355,891) 237,076 189,108
Contributed surplus 26 --
Deficit (29,404) (17,565)
--------- ---------
271,101 234,946
--------- ---------
$ 330,758 $ 318,584
========= =========
</TABLE>
Approved by the Board:
/s/ S.A. Milner /s/ L.G. Munin
S.A. Milner, Director L.G. Munin, Director
32
<PAGE> 35
CONSOLIDATED STATEMENT OF INCOME (LOSS) AND DEFICIT
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
<TABLE>
<CAPTION>
Year ended December 31, 1999 1998 1997
------------ ------------ ------------
(U.S.$ in thousands except shares and per share amounts)
<S> <C> <C> <C>
Production revenue $ 91,507 $ 74,861 $ 84,219
Less: royalties 16,141 13,246 14,592
------------ ------------ ------------
Production revenue, after royalties 75,366 61,615 69,627
Interest and other revenue (Note 5) 1,081 2,776 2,428
------------ ------------ ------------
76,447 64,391 72,055
------------ ------------ ------------
Production costs 14,320 16,355 13,325
General and administrative expenses 4,580 4,796 4,308
Interest 2,496 437 --
Depletion and amortization 51,385 42,081 36,951
Additional depletion: Libyan properties 11,393 5,144 --
U.K. properties 4,793 1,100 --
------------ ------------ ------------
88,967 69,913 54,584
------------ ------------ ------------
Income (loss) before income taxes and dividends
on preferred shares of a subsidiary (12,520) (5,522) 17,471
Income taxes (Note 6):
Current 11 14 7
Deferred (5,634) (1,423) 7,304
------------ ------------ ------------
(5,623) (1,409) 7,311
------------ ------------ ------------
Income (loss) before dividends on preferred shares
of a subsidiary (6,897) (4,113) 10,160
Dividends paid on preferred shares of a subsidiary 4,942 4,942 4,942
------------ ------------ ------------
Net income (loss) applicable to common shares (11,839) (9,055) 5,218
Deficit, beginning of year (17,565) (7,089) (12,307)
Cost of purchase of common shares in excess
of stated capital (Note 4) -- (1,421) --
------------ ------------ ------------
Deficit, end of year $ (29,404) $ (17,565) $ (7,089)
============ ============ ============
Net income (loss) per common share (Note 8) $ (0.86) $ (0.67) $ 0.38
============ ============ ============
Weighted average number of common shares outstanding 13,701,419 13,480,067 13,620,728
============ ============ ============
</TABLE>
33
<PAGE> 36
CONSOLIDATED STATEMENT OF CASH FLOWS
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
<TABLE>
<CAPTION>
Year ended December 31, 1999 1998 1997
- -----------------------------------------------------------------------------------------------
(U.S.$ in thousands)
<S> <C> <C> <C>
Operating activities:
Net income (loss) applicable to common shares $(11,839) $ (9,055) $ 5,218
Items not requiring a current cash outlay:
Depletion and amortization 67,571 48,325 36,951
Deferred income taxes (5,634) (1,423) 7,304
-------- -------- --------
Cash flow from operations 50,098 37,847 49,473
Change in non-cash operating working
capital (Note 7)
Accounts receivable (4,825) (3,168) 337
Other current assets (468) 324 (313)
Accounts payable and accrued 3,830 164 992
-------- -------- --------
48,635 35,167 50,489
-------- -------- --------
Financing activities:
Issue of common shares 50,321 437 975
Purchase of common shares for cancellation (80) (5,902) (849)
Increase in long-term debt 5,000 40,000 --
Decrease in long-term debt (35,000) -- --
Financing costs (4,058) -- --
-------- -------- --------
16,183 34,535 126
-------- -------- --------
Investing activities:
Lease acquisition, exploration and
development costs (55,176) (91,690) (69,453)
Sale of producing properties 155 -- --
Purchase of producing gas and oil properties -- (883) --
-------- -------- --------
(55,021) (92,573) (69,453)
Purchase of other capital assets (48) (93) (324)
Change in investing accounts payable and
accrued (994) 6,652 3,638
-------- -------- --------
(56,063) (86,014) (66,139)
-------- -------- --------
Change in cash and short-term deposits 8,755 (16,312) (15,524)
Cash and short-term deposits, beginning of year 10,613 26,925 42,449
-------- -------- --------
Cash and short-term deposits, end of year $ 19,368 $ 10,613 $ 26,925
======== ======== ========
</TABLE>
34
<PAGE> 37
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(December 31, 1999, 1998 and 1997)
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
The Company is engaged in natural gas and oil exploration, development and
production primarily in the United States ("U.S.") and also in the United
Kingdom ("U.K.") sector of the North Sea. The Consolidated Financial Statements
are expressed in U.S. currency as most of the Company's assets and operations
are denominated in U.S. 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 U.S.
accounting principles that affect the Company are referred to in
Note 12, 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
U.S. 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 (Loss) and Deficit.
(c) FOREIGN CURRENCY TRANSLATION
Canadian and other foreign currency amounts have been translated
into U.S. 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 (Loss) and Deficit.
(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.
35
<PAGE> 38
(e) NATURAL RESOURCE PROPERTIES
The Company accounts for natural gas and oil properties in
accordance with Canadian guidelines on full cost accounting.
Under this method, all costs associated with the acquisition,
exploration and development of 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 U.S. 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 $6,310,000 (1998 -
$2,849,000), after providing for tax recoveries of $5,083,000
(1998 - $2,295,000), was recorded in respect of the Libyan
concessions which resulted in all Libyan costs being written off
as at December 31, 1999. A write-down of $2,654,000 (1998 -
$609,000), after providing for tax recoveries of $2,139,000 (1998
- $491,000), was recorded in respect of the U.K. properties.
The following weighted average field prices were used in the
determination of the Company's U.S. future net revenues for
purposes of the ceiling test:
<TABLE>
<CAPTION>
As at December 31, 1999 1998 1997
-----------------------------------------------------------
<S> <C> <C> <C>
Oil (per bbl) $ 20.30 $ 12.35 $ 16.92
Ngls (per bbl) $ 21.67 $ 10.19 $ 15.14
Oil and ngls (per bbl) $ 20.40 $ 12.27 $ 16.69
Natural gas (per mcf) $ 2.51 $ 2.15 $ 2.74
</TABLE>
A field price of $0.99 (1998 - $1.74; 1997 - $1.76) per mcf was
used in the determination of the Company's U.K. future net
revenues for purposes of the ceiling test.
36
<PAGE> 39
Depletion rates per physical unit of U.S. production are as
follows:
<TABLE>
<CAPTION>
Natural Gas Oil and ngls
(per mcf) (per bbl)
----------- ------------
<S> <C> <C>
Year ended December 31, 1997 $ 1.11 $ 6.68
Year ended December 31, 1998 $ 1.16 $ 6.97
YEAR ENDED DECEMBER 31, 1999 $ 1.25 $ 7.50
</TABLE>
The depletion rate per physical unit of U.K. natural gas
production was $1.24 per mcf for the year ended December 31, 1999
(1998 - $0.81; 1997 - $0.81).
General and administrative costs relating directly to lease
acquisitions, exploration and development activities have been
capitalized as follows:
<TABLE>
<CAPTION>
Year ended December 31, 1999 1998 1997
----------------------- ------ ------ ------
(in thousands)
<S> <C> <C> <C>
Lease acquisition $ 765 $ 857 $ 694
Exploration 1,581 1,740 1,470
Development 1,601 1,715 1,387
------ ------ ------
$3,947 $4,312 $3,551
====== ====== ======
</TABLE>
At December 31, 1998, Libyan property carrying costs of $9.9
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 (Loss) and Deficit as
depletion and amortization.
37
<PAGE> 40
(g) INCOME TAXES
Effective with the fourth quarter of 1999, the Company
retroactively adopted the liability method of accounting for
income taxes, such method being required to be adopted no later
than 2000 under Canadian generally accepted accounting
principles. Applying this method, deferred income taxes are
recognized, using applicable, enacted income tax rates, for the
future income tax consequences attributable to differences
between the financial statement carrying values and their
respective income tax bases. The effect on deferred income tax
assets and liabilities of a change in tax rates is included in
income in the period that includes the enactment date. Deferred
income tax assets are evaluated and if realization is considered
"more likely than not", no valuation allowance is provided.
The retroactive application of this policy had no material effect
on the Company and therefore no restatement of prior periods has
been made.
2. REVOLVING CREDIT AND LONG-TERM DEBT
In 1997 the Company arranged an unsecured revolving credit facility
with a syndicate of banks. The facility, in the amount of $100 million
or the Canadian dollar equivalent, is fully revolving for 364 day
periods with extensions at the option of the lenders upon notice from
the Company. If not extended, the facility converts to term loans
repayable over a period not exceeding four years. Advances under the
facility bear interest at Canadian prime or U.S. base rate, or at
Bankers' Acceptance rates or LIBOR plus applicable margins. Certain
financial tests are required to be met quarterly. Under this facility,
$10 million was utilized at December 31, 1999 (1998 - $40 million),
carrying a weighted average interest rate of 7.00% (1998 - 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 U.S. The preferred shares are
redeemable, at the option of Funding, at $25.4028 per share during
2000, $25.2014 per share during 2001 and $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.
38
<PAGE> 41
4. SHARE CAPITAL
(a) COMMON SHARES
<TABLE>
Year ended December 31, 1999 1998 1997
--------------------- --------------------- ----------------------
<S> <C> <C> <C> <C> <C> <C>
Number Share Number Share Number Share
of Capital of Capital of Capital
Shares Account Shares Account Shares Account
---------- --------- ---------- --------- ---------- ---------
(in thousands except number of shares)
Balance, beginning of year 13,355,891 $ 189,108 13,622,375 $ 192,845 13,591,763 $ 192,381
Share options exercised 668 9 28,216 437 66,912 975
Share purchased and cancelled* (7,500) (106) (294,700) (4,174) (36,300) (511)
Shares issued for cash** 2,875,000 48,065 - - - -
---------- --------- ---------- --------- ---------- ---------
Balance, end of year 16,224,059 $ 237,076 13,355,891 $ 189,108 13,622,375 $ 192,845
========== ========= ========== ========= ========== ==========
</TABLE>
* Pursuant to normal course issuer bid.
** Reduced by costs of issue of $4,058, less related deferred taxes of $1,811.
In the fourth quarter of 1999, the Company sold 2,875,000 common
shares, by way of a public offering in the U.S., at $17.50
per share.
(b) COMMON SHARES RESERVED
At December 31, 1999, 1,130,207 (1998 - 1,130,875; 1997 -
1,159,091) of the authorized but unissued common shares
of the Company were reserved for issuance under the Share
Option Plan. See Note 4(d).
The Company has reserved 3,408,375 common shares for
issuance pursuant to the conversion provisions of the
preferred shares of a subsidiary. See Note 3.
(c) CONTRIBUTED SURPLUS
Contributed surplus represents the excess of original net
issue price over purchase price of shares purchased and
cancelled pursuant to successive issuer bids, the most
recent of which expired November 1, 1999.
(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. 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 and, therefore, no compensation expense is recognized.
Proceeds arising from the exercise of share options are
credited to share capital. At December 31, 1999 options
were outstanding to 46 participants in the Plan.
39
<PAGE> 42
The following is a summary of activity related to the Plan for the
years ended December 31, 1999, 1998 and 1997.
<TABLE>
Year ended December 31, 1999 1998 1997
--------------------- ---------------------- ---------------------
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 1,083,857 $16.74 1,057,673 $16.47 909,253 $15.10
Granted 180,000 13.44 65,000 21.08 228,000 21.35
Exercised (668) 13.63 (28,216) 15.49 (66,912) 14.47
Forfeited (4,000) 22.54 (10,600) 20.07 (12,668) 16.06
Expired (140,000) 13.61 -- -- -- --
--------- --------- ---------
Outstanding at end of year 1,119,189 16.58 1,083,857 16.74 1,057,673 16.47
========= ========= =========
Options exercisable at year end 824,521 869,858 707,738
========= ========= =========
</TABLE>
The following table summarizes information about options outstanding
at December 31, 1999.
<TABLE>
Options Outstanding Options Exercisable
------------------------------------------------------ -------------------------
Weighted Weighted Weighted
Range of Number Average Average Number Average
Option of Remaining Option of Option
Price Shares Contractual Life Price Shares Price
- -------------- ---------- ---------------- -------- -------- ---------
<S> <C> <C> <C> <C> <C>
$11.43 - 15.63 718,855 6.0 years $14.20 553,855 $14.56
18.00 - 20.87 133,334 4.3 years 19.06 101,667 19.35
21.23 - 23.75 267,000 7.5 years 21.74 168,999 21.69
--------- -------
1,119,189 824,521
========= =======
</TABLE>
5. INTEREST AND OTHER REVENUE
Interest and other revenue for 1998 included $1.6 million awarded by
the courts pursuant to a successful claim for recovery of excess
transportation charges incurred from 1990 through 1997. The award
comprises transportation charges, legal fees and judgement interest in
the amounts of $1,129,000, $282,000 and $189,000, respectively.
40
<PAGE> 43
6. INCOME TAXES
Income tax expense is made up of the following components:
<TABLE>
<CAPTION>
Year ended December 31, 1999 1998 1997
CANADA U.S. CANADA U.S. CANADA U.S.
- ---------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income (loss) before income taxes and dividends
on preferred shares of a subsidiary $ (18,254) $ 5,734 $ (6,829) $ 1,307 $ 2,072 $ 15,399
========= ======= ======== ======= ======= ========
Income taxes (recovery)
Current $ 11 $ -- $ 14 $ -- $ 7 $ --
Deferred (7,643) 2,009 (1,740) 317 2,007 5,297
--------- ------- -------- ------- ------- --------
$ (7,632) $ 2,009 $ (1,726) $ 317 $ 2,014 $ 5,297
========= ======= ======== ======= ======= ========
</TABLE>
The actual tax rate differs from the expected tax rate for the
following reasons:
<TABLE>
<CAPTION>
Year ended December 31, 1999 1998 1997
---------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Tax at statutory rate of 44.62%
(Combined Canadian federal and
provincial rate) $ (5,587) $ (2,465) $ 7,796
Add (deduct) the effect of:
Lower income tax rate on
earnings of U.S. subsidiaries (496) (81) (1,373)
Canadian income tax on exchange
loss which is eliminated
upon consolidation 909 631 429
Other (449) 506 459
-------- -------- --------
Tax at effective rate $ (5,623) $ (1,409) $ 7,311
======== ======== ========
Effective tax rate 44.9% 25.5% 41.8%
======== ======== ========
</TABLE>
Temporary differences comprising the deferred tax assets (liabilities)
are as follows:
<TABLE>
<CAPTION>
As at December 31, 1999 1998
----------------------------------------------------------------------
(in thousands)
<S> <C> <C>
Deferred tax assets
Depletion and amortization $ 10,679 $ 3,468
Financing costs 2,005 390
Loss carryforwards 28,106 20,593
Other 495 382
--------- ---------
41,285 24,833
--------- ---------
Deferred tax liabilities
Depletion and amortization (42,342) (33,232)
Other -- (103)
--------- ---------
(42,342) (33,335)
--------- ---------
Net deferred tax liabilities $ (1,057) $ (8,502)
========= =========
</TABLE>
41
<PAGE> 44
At December 31, 1999 the Company's U.S. net operating tax losses
carried forward amounted to $75,056,000 of which $6,119,000,
$2,835,000, $6,139,000, $18,007,000, $3,773,000, $2,090,000,
$16,088,000 and $20,005,000 expire in the years 2005, 2007, 2009,
2010, 2011, 2012, 2018 and 2019, respectively. Canadian net operating
tax losses carried forward amounted to $3,277,000 of which $2,108,000,
$248,000 and $921,000, expire in the years 2003, 2005 and 2006,
respectively. The Company is of the opinion that the tax benefit of
these tax losses will be realized.
7. SUPPLEMENTAL CASH FLOW INFORMATION
Net cash outflows for (inflows from) income taxes were $(12,000),
$14,000 and $141,000 for the years 1999, 1998 and 1997, respectively.
Cash outflows for long-term debt interest were $2,601,000 and $628,000
in 1999 and 1998, respectively.
8. 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 preferred
share dividends and the amount of imputed interest on share option
proceeds. Earnings were not diluted during the periods shown.
9. PENSION COSTS AND OBLIGATIONS
The Company contributed $145,418, $145,300 and $144,254 for 1999, 1998
and 1997, respectively, to defined contribution plans. Under a
supplementary defined contribution plan established in 1991, costs of
$216,401, $198,294 and $162,384 for 1999, 1998 and 1997, respectively,
and the related liability are recorded in the accounts.
The Company has established no other retirement benefit plans.
10. 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 U.S. gas, oil and ngls produced by the Company are marketed by a
single aggregator. Production revenues, net of royalties, associated
with the aggregator were $59,665,000 (1998-$46,340,000;
1997-$50,250,000). 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
$9,710,000 (1998-$8,207,000; 1997-$10,880,000). The Company believes
that alternative marketing arrangements would be readily available for
its gas, oil and liquids.
42
<PAGE> 45
<TABLE>
<CAPTION>
1999 1998 1997
-------- -------- --------
(in thousands)
<S> <C> <C> <C>
Production revenue, net of royalties
U.S. $ 71,487 $ 56,199 $ 63,227
U.K. 3,582 4,411 6,231
Libya 297 1,005 169
-------- -------- --------
Total production revenue, net of
royalties 75,366 61,615 69,627
Interest and other revenue 1,081 2,776 2,428
-------- -------- --------
Total revenue $ 76,447 $ 64,391 $ 72,055
======== ======== ========
Net capital assets
U.S. $274,904 $267,020 $213,856
U.K. 1,994 11,337 14,733
Canada and other 251 285 328
Libya -- 9,835 14,373
-------- -------- --------
$277,149 $288,477 $243,290
======== ======== ========
</TABLE>
As at December 31, 1999, the Company had entered into natural gas
forward contracts with the aggregator and an oil forward contract with
the regional refiner. The forward contracts, which are only for 2000
production, are for the physical delivery of natural gas volumes
totalling 6.1 bcf, at an average price of $2.49 per mcf, and for the
physical delivery of oil volumes of 90 mbbls, at an average price of
$19.00 per bbl. The value of these contracts would not be materially
different using December 31, 1999 prices.
11. UNCERTAINTY DUE TO THE YEAR 2000
The Year 2000 Issue arises because many computerized systems use two
digits rather than four to identify a year. Date-sensitive systems may
recognize the year 2000 as 1900 or some other date, resulting in errors
when information using year 2000 dates is processed. In addition,
similar problems may arise in some systems which use certain dates in
1999 to represent something other than a date. Although the change in
date has occurred, it is not possible to conclude that all aspects of
the Year 2000 Issue that may affect the Company, including those
related to customers, suppliers, or other third parties, have been
fully resolved.
12. U.S. ACCOUNTING PRINCIPLES
(a) FULL COST ACCOUNTING
U.S. full cost accounting rules differ materially from the Canadian
full cost accounting guidelines followed by the Company. In
determining the limitation on carrying values, U.S. 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 1999 and 1998 impairment adjustments would have been
required under U.S. accounting rules. The quarterly test required
by U.S. accounting rules, using a March 31, 1999 U.K. natural gas
price of $0.84 per mcf to determine future net revenues, would have
43
<PAGE> 46
resulted in a write-down of U.K. 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 December 31, 1998 U.S. natural gas and oil prices of $2.15
per mcf and $9.72 per bbl, and June 30, 1998 U.S. natural gas and
oil prices of $2.09 per mcf and $12.40 per bbl to determine
future net revenues, would have resulted in a write-down of U.S.
property carrying costs of $65.5 million and, after providing for
tax recoveries of $22.9 million, a net charge to operations of
$42.6 million, at December 31, 1998; and $24.7 million and, after
providing for tax recoveries of $8.6 million, a net charge to
operations of $16.1 million, at June 30, 1998. Such write-downs
will result in reduced depletion expense, under U.S. rules, for
subsequent periods. Under Canadian guidelines the test resulted
in a write-down of U.K. property carrying costs of $4.8 million
(1998 - $1.1 million) and, after providing for tax recoveries of
$2.1 million (1998 - $0.5 million), a net charge to operations of
$2.7 million (1998 - $0.6 million) at December 31; no
corresponding write-downs were required under U.S. accounting
rules.
(b) EARNINGS PER SHARE
U.S. 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.
(c) EFFECT ON EARNINGS
The effect on consolidated earnings of the differences between
Canadian and U.S. accounting principles is summarized as follows:
<TABLE>
<CAPTION>
Year ended December 31, 1999 1998 1997
- -------------------------------------------------------------------------------------
(in thousands except shares and per share amounts)
<S> <C> <C> <C>
Net income (loss) applicable to common
shares, as reported $ (11,839) $ (9,055) $ 5,218
Additional depletion difference (2,311) (89,153) --
----------- ----------- -----------
(14,150) (98,208) 5,218
Reduction in depletion expense 17,623 4,235 3,177
Reduction (increase) in deferred tax
provision (5,440) 30,010 (885)
----------- ----------- -----------
Net income (loss) applicable to common
shares under U.S. accounting principles $ (1,967) $ (63,963) $ 7,510
=========== =========== ===========
Net income (loss) per common share
under U.S. accounting principles:
Basic $ (0.14) $ (4.75) $ 0.55
=========== =========== ===========
Fully diluted $ (0.14) $ (4.75) $ 0.54
=========== =========== ===========
Fully diluted common shares outstanding 13,701,419 13,480,067 13,858,593
=========== =========== ===========
</TABLE>
44
<PAGE> 47
(d) EFFECT ON BALANCE SHEET
The effect on the Consolidated Balance Sheet of the differences
between Canadian and U.S. accounting principles is as follows:
<TABLE>
<CAPTION>
As at December 31, 1999 1998
---------------------- ---------------------
Under U.S. Under U.S.
As Accounting As Accounting
Reported Principles Reported Principles
-------- ---------- -------- ----------
(in thousands)
<S> <C> <C> <C> <C>
Net capital assets $ 277,149 $ 189,501 $ 288,477 $ 185,517
Deferred tax - asset 14,636 30,238 5,182 28,233
Deferred tax - liability 15,693 - 13,684 -
Deficit (29,404) (85,757) (17,565) (83,790)
</TABLE>
Additionally for U.S. reporting purposes, the preferred shares
shown as shareholders' equity in these consolidated financial
statements would be shown outside the equity section.
(e) INCOME TAX DISCLOSURES
Temporary differences comprising the deferred tax assets
(liabilities) are as follows:
<TABLE>
<CAPTION>
As at December 31, 1999 1998
------------------ ---- ----
(in thousands)
<S> <C> <C>
Deferred tax assets
Depletion and amortization $ 11,561 $ 6,971
Financing costs 2,005 390
Loss carryforwards 28,106 20,593
Other 495 382
-------- -------
42,167 28,336
-------- -------
Deferred tax liabilities
Depletion and amortization (11,929) -
Other - (103)
-------- -------
(11,929) (103)
-------- -------
Net deferred tax assets $ 30,238 $ 28,233
======== ========
</TABLE>
45
<PAGE> 48
Provisions for deferred income taxes are as follows:
<TABLE>
<CAPTION>
Year ended December 31, 1999 1998 1997
---------------------- ---------------------- ---------------------
Canada U.S. Canada U.S. Canada U.S.
----------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C> <C> <C> <C>
Income (loss) before income taxes and
dividends on preferred shares of
a subsidiary $ (17,492) $ 20,284 $ (5,002) $(85,440) $ 3,019 $ 17,629
========= ======== ========= ======== ======== ========
Provision for deferred income taxes $ (7,248) $ 7,054 $ (921) $(30,512) $ 2,122 $ 6,067
========= ======== ========= ======== ======== ========
</TABLE>
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, 1999 1998 1997
- ----------------------------------------------------------------------------------------------------------------------------------
(in thousands)
<S> <C> <C> <C>
Tax at statutory Canadian rate of 44.62% $ 1,247 $ (40,355) $ 9,213
Lower income tax rate on earnings of U.S. subsidiaries (1,823) 7,830 (1,617)
Canadian income tax on exchange loss which is eliminated
upon consolidation 909 631 429
Exchange revaluation of Canadian deferred tax assets (553) 280 194
Other 37 195 (23)
--------- -------- ---------
Tax at effective rate $ (183) $(31,419) $ 8,196
========= ======== =========
Effective tax rate (6.6)% 34.7% 39.7%
========= ======== =========
</TABLE>
(f) 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. U.S. 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
$7.75, $10.61 and $11.49, applying risk-free interest rates of
5.68%, 5.64% and 6.85% for options granted in 1999, 1998 and
1997, respectively, and assuming ten year expected option lives,
no dividend yields and expected volatilities of 28%, 25% and 24%
on a weighted average basis, would amount to a net of tax charge
to income (loss) of $1,255,000 (1998 - $1,502,000; 1997 -
$1,348,000). After reflecting this charge, pro forma net income
(loss) applicable to common shares under U.S. accounting
principles would be $(3,222,000), (1998 - $(65,465,000); 1997 -
$6,162,000); pro forma net income (loss) per common share under
U.S. accounting principles would be $(0.24), (1998 - $(4.86);
1997 - $0.45); and pro forma fully diluted earnings (loss) per
common share under U.S. accounting principles would be $(0.24),
(1998 - $(4.86); 1997 - $0.45). These effects are not necessarily
indicative of those to be expected in future years.
46
<PAGE> 49
SUPPLEMENTARY FINANCIAL INFORMATION
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
DECEMBER 31, 1999
(Unaudited)
RESERVE INFORMATION
Reports prepared by Netherland, Sewell & Associates, Inc. as to the
Company's U.S. reserves and by the Company as to the U.K. reserves,
estimate the total proved reserves owned by the Company, before and
after royalty deductions, as follows:
TOTAL PROVED RESERVES-
BEFORE ROYALTY DEDUCTIONS:
<TABLE>
<CAPTION>
Natural Gas-mmcf Oil and ngls-mbbls*
U.S. U.K. Total U.S.
------- ------ ------- ------
<S> <C> <C> <C> <C>
December 31, 1997 131,126 18,317 149,443 12,947
Purchase of producing properties 4,745 -- 4,745 18
Revision of previous estimates 10,683 (5,119) 5,564 (1,478)
Extensions, discoveries and other additions 29,360 -- 29,360 4,871
Sale of proved properties -- -- -- --
Production (26,960) (3,088) (30,048) (1,158)
------- ------ ------- ------
December 31, 1998 148,954 10,110 159,064 15,200
PURCHASE OF PRODUCING PROPERTIES -- -- -- --
REVISION OF PREVIOUS ESTIMATES (5,635) (151) (5,786) 1,602
EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS 64,127 -- 64,127 2,152
SALE OF PROVED PROPERTIES -- -- -- --
PRODUCTION (27,536) (3,583) (31,119) (1,644)
------- ------ ------- ------
DECEMBER 31, 1999 179,910 6,376 186,286 17,310
======= ====== ======= ======
</TABLE>
TOTAL PROVED RESERVES-
AFTER ROYALTY DEDUCTIONS:
<TABLE>
<CAPTION>
Natural Gas-mmcf Oil and ngls-mbbls*
U.S. U.K. Total U.S.
------- ------ ------- ------
<S> <C> <C> <C> <C>
December 31, 1997 106,780 18,317 125,097 11,253
Purchase of producing properties 3,512 -- 3,512 14
Revision of previous estimates 7,819 (5,119) 2,700 (1,316)
Extensions, discoveries and other additions 22,268 -- 22,268 4,142
Sale of proved properties -- -- -- --
Production (21,416) (3,088) (24,504) (986)
------- ------ ------- ------
December 31, 1998 118,963 10,110 129,073 13,107
PURCHASE OF PRODUCING PROPERTIES -- -- -- --
REVISION OF PREVIOUS ESTIMATES (4,707) (151) (4,858) 1,475
EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS 51,251 -- 51,251 1,753
SALE OF PROVED PROPERTIES -- -- -- --
PRODUCTION (21,950) (3,583) (25,533) (1,389)
------- ------ ------- ------
DECEMBER 31, 1999 143,557 6,376 149,933 14,946
======= ====== ======= ======
</TABLE>
* 20,100 (1998-26,800) barrels of natural gas liquids, before and after royalty
deductions, associated with the U.K. gas reserves are not included in this
table.
47
<PAGE> 50
(Unaudited)
PROVED DEVELOPED PRODUCING RESERVES -
BEFORE ROYALTY DEDUCTIONS:
<TABLE>
<CAPTION>
Natural Gas - mmcf Oil and ngls - mbbls
-------------------------------
U.S. U.K. Total U.S.
------ ------ ------ --------------------
<S> <C> <C> <C> <C>
December 31, 1997 55,013 18,317 73,330 8,209
December 31, 1998 70,082 10,108 80,190 5,430
DECEMBER 31, 1999 63,822 6,376 70,198 7,447
</TABLE>
PROVED DEVELOPED PRODUCING RESERVES -
AFTER ROYALTY DEDUCTIONS:
<TABLE>
<CAPTION>
Natural Gas - mmcf Oil and ngls - mbbls
-------------------------------
U.S. U.K. Total U.S.
------ ------ ------ --------------------
<S> <C> <C> <C> <C>
December 31, 1997 43,979 18,317 62,296 7,241
December 31, 1998 55,418 10,108 65,526 4,739
DECEMBER 31, 1999 50,531 6,376 56,907 6,580
</TABLE>
48
<PAGE> 51
(Unaudited)
RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES
<TABLE>
<CAPTION>
Year ended December 31, 1999 1998 1997
- ------------------------------ -------- -------- --------
(in thousands)
<S> <C> <C> <C>
U.S.
Revenue - net of royalties $ 71,487 $ 56,199 $ 63,227
Production costs (18,128) (15,675) (14,901)
Depletion and amortization (46,796) (39,460) (33,414)
-------- -------- --------
Results of operations before
income taxes 6,563 1,064 14,912
Income tax (expense) recovery (2,300) (333) (5,223)
-------- -------- --------
Results of operations after
income taxes $ 4,263 $ 731 $ 9,689
======== ======== ========
U.K.
Revenue - net of royalties $ 3,582 $ 4,411 $ 6,231
Production costs (338) (964) (1,064)
Depletion and amortization (9,304) (3,646) (3,319)
-------- -------- --------
Results of operations before
income taxes (6,060) (199) 1,848
Income tax (expense) recovery 2,624 117 (787)
-------- -------- --------
Results of operations after
income taxes $ (3,436) $ (82) $ 1,061
======== ======== ========
Libya
Revenue - net of royalties $ 297 $ 1,005 $ 169
Production costs 631 (1,041) (38)
Depletion and amortization (11,393) (5,144) (131)
-------- -------- --------
Results of operations before
income taxes (11,727) (5,180) --
Income tax (expense) recovery 5,233 2,312 --
-------- -------- --------
Results of operations after
income taxes $ (6,494) $ (2,868) $ --
======== ======== ========
Total
Revenue - net of royalties $ 75,366 $ 61,615 $ 69,627
Production costs (19,097) (17,680) (16,003)
Depletion and amortization (67,493) (48,250) (36,864)
-------- -------- --------
Results of operations before
income taxes (11,224) (4,315) 16,760
Income tax (expense) recovery 5,557 2,096 (6,010)
-------- -------- --------
Results of operations after
income taxes $ (5,667) $ (2,219) $ 10,750
======== ======== ========
</TABLE>
49
<PAGE> 52
(Unaudited)
CAPITALIZED COSTS RELATING TO GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES
<TABLE>
<CAPTION>
December 31, 1999 1998 1997
- ------------ --------- --------- ---------
(in thousands)
<S> <C> <C> <C>
Proved gas and oil properties $ 550,097 $ 475,902 $ 402,885
Unproved gas and oil properties 57,304 76,478 56,922
--------- --------- ---------
607,401 552,380 459,807
Accumulated depletion (339,786) (266,066) (224,154)
--------- --------- ---------
Net capitalized costs $ 267,615 $ 286,314 $ 235,653
========= ========= =========
</TABLE>
COSTS INCURRED IN GAS AND OIL PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
<TABLE>
<CAPTION>
Year ended December 31, 1999 1998 1997
- ----------------------- -------- -------- --------
(in thousands)
<S> <C> <C> <C>
Property acquisition costs: U.S. $ 5,352 $ 7,903 $ 9,164
U.K. 28 115 137
-------- -------- --------
5,380 8,018 9,301
-------- -------- --------
Purchase of producing properties: U.S. -- 883 --
-------- -------- --------
Sale of producing properties: U.S. (155) -- --
-------- -------- --------
Exploration costs: U.S. 28,753 43,317 35,540
U.K. 9 72 115
Other foreign 1,531 606 1,207
-------- -------- --------
30,293 43,995 36,862
-------- -------- --------
Development costs: U.S. 19,542 39,606 23,260
U.K. (39) 71 30
-------- -------- --------
19,503 39,677 23,290
-------- -------- --------
$ 55,021 $ 92,573 $ 69,453
======== ======== ========
</TABLE>
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.
50
<PAGE> 53
(Unaudited)
<TABLE>
<CAPTION>
December 31, 1999 1998 1997
------------ -------- -------- --------
(in thousands)
<S> <C> <C> <C>
U.S.
Future cash inflows $665,306 $382,771 $480,669
Future production costs (180,948) (116,976) (121,380)
Future development costs (83,476) (60,203) (57,208)
Future income tax expense (63,590) -- (46,742)
-------- -------- --------
Future net cash flows 337,292 205,592 255,339
Ten percent annual discount for
estimated timing of cash flows (114,871) (62,089) (70,844)
-------- -------- --------
Standardized measure of
discounted future net cash flows 222,421 143,503 184,495
-------- -------- --------
U.K.
Future cash inflows 11,826 19,349 32,774
Future production costs (8,261) (7,483) (5,734)
Future development costs (1,397) (1,457) (1,450)
Future income tax expense -- -- (6,340)
-------- -------- --------
Future net cash flows 2,168 10,409 19,250
Ten percent annual discount for
estimated timing of cash flows (56) (1,404) (4,172)
-------- -------- --------
Standardized measure of
discounted future net cash flows 2,112 9,005 15,078
-------- -------- --------
Total
Future cash inflows 677,132 402,120 513,443
Future production costs (189,209) (124,459) (127,114)
Future development costs (84,873) (61,660) (58,658)
Future income tax expense (63,590) -- (53,082)
-------- -------- --------
Future net cash flows 339,460 216,001 274,589
Ten percent annual discount for
estimated timing of cash flows (114,927) (63,493) (75,016)
-------- -------- --------
Standardized measure of
discounted future net cash flows $224,533 $152,508 $199,573
======== ======== ========
</TABLE>
51
<PAGE> 54
(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, 1999 1998 1997
- ---------------------- ---- ---- ----
(in thousands)
<S> <C> <C> <C>
Sales of oil, ngls and natural gas
produced, net of production costs $(61,192) $(45,231) $(56,061)
Net change in prices and production costs 83,559 (79,471) (73,047)
Extensions and discoveries, less related costs 83,248 30,159 28,219
Purchase of producing properties -- 2,793 --
Sales of producing properties -- -- --
Development costs incurred during the period 9,734 23,131 10,096
Revisions of previous quantity estimates (8,441) (17,191) 22,388
Accretion of discount 15,251 19,958 23,902
Net change in income taxes (41,941) 38,739 26,534
Changes in estimated future development costs (23,126) (16,421) (12,551)
Other 14,933 (3,531) (8,930)
-------- -------- --------
Net increase (decrease) 72,025 (47,065) (39,450)
Beginning of year 152,508 199,573 239,023
-------- -------- --------
End of year $224,533 $152,508 $199,573
======== ======== ========
</TABLE>
52
<PAGE> 55
(Unaudited)
QUARTERLY INFORMATION
<TABLE>
<CAPTION>
1999 QUARTER ENDED 1998 QUARTER ENDED
MAR 31 JUN 30 SEP 30 DEC 31 MAR 31 JUN 30 SEP 30 DEC 31
-------- -------- -------- -------- -------- -------- -------- --------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
FINANCIAL DATA
Revenue(000's) $ 13,218 $ 17,543 $ 22,763 $ 22,923 $ 18,718 $ 14,804 $ 13,943 $ 16,926
Gross Profit (000's) (4,169) (12,491) 3,874 266 2,884 (342) (1,345) (6,719)
Income (loss) (000's) (3,860) (8,507) 1,282 (754) 556 (1,735) (2,472) (5,404)
Per common share (0.29) (0.64) 0.10 (0.03) 0.04 (0.13) (0.18) (0.40)
Capital expenditures(000's) $ 10,385 $ 9,317 $ 16,485 $ 18,834 $ 24,015 $ 19,611 $ 22,572 $ 26,375
COMMON SHARE INFORMATION
American Stock Exchange
High $ 15.50 $ 18.63 $ 22.75 $ 20.38 $ 24.75 $ 24.75 $ 23.75 $ 20.25
Low 9.56 12.25 17.44 14.06 17.94 20.25 13.94 14.38
Close $ 12.25 $ 17.50 $ 19.00 $ 17.25 $ 23.75 $ 23.69 $ 17.06 $ 14.38
Volume (000's) 3,703 2,959 1,872 5,551 2,383 1,897 3,297 2,213
Toronto Stock Exchange
High C$ 24.00 C$ 26.95 C$ 34.00 C$ 30.25 C$ 35.25 C$ 35.35 C$ 34.75 C$ 30.70
Low 14.50 19.25 25.90 21.00 25.60 30.10 21.60 22.75
Close C$ 18.90 C$ 25.25 C$ 27.60 C$ 25.00 C$ 34.05 C$ 34.40 C$ 25.70 C$ 23.05
Volume(000's) 911 720 413 345 525 266 1,158 1,066
</TABLE>
53
<PAGE> 56
(Unaudited)
<TABLE>
<CAPTION>
1999 QUARTER ENDED 1998 QUARTER ENDED
MAR 31 JUN 30 SEP 30 DEC 31 MAR 31 JUN 30 SEP 30 DEC 31
--------- --------- --------- --------- --------- --------- --------- ---------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
PRODUCTION DATA
Daily volumes, before royalties
Natural gas (mmcf)
U.S 76.1 74.4 76.7 74.6 67.7 72.0 72.2 83.3
U.K 11.0 7.7 10.5 10.1 15.3 6.6 1.8 10.3
--------- --------- --------- --------- --------- --------- --------- ---------
Total 87.1 82.1 87.2 84.7 83.0 78.6 74.0 93.6
========= ========= ========= ========= ========= ========= ========= =========
Oil and ngls (bbls) 3,679 5,222 5,200 4,329 3,269 3,495 3,261 3,899
Equivalent (mmcfe) 109.2 113.4 118.4 110.7 102.7 99.5 93.6 117.0
Daily volumes, after royalties
Natural gas (mmcf)
U.S 60.1 59.1 61.4 59.8 53.9 57.1 57.4 66.2
U.K 11.0 7.7 10.5 10.1 15.3 6.6 1.8 10.3
--------- --------- --------- --------- --------- --------- --------- ---------
Total 71.1 66.8 71.9 69.9 69.2 63.7 59.2 76.5
========= ========= ========= ========= ========= ========= ========= =========
Oil and ngls (bbls) 3,156 4,421 4,394 3,671 2,857 3,022 2,823 3,344
Equivalent (mmcfe) 90.1 93.3 98.3 92.0 86.3 81.8 76.2 96.5
Pricing
Natural gas ($/mcf)
U.S $ 1.60 $ 1.97 $ 2.46 $ 2.58 $ 2.24 $ 2.07 $ 1.97 $ 1.99
U.K 1.13 0.82 0.81 1.03 1.55 0.81 1.19 1.55
Composite 1.54 1.86 2.26 2.39 2.12 1.96 1.96 1.94
Oil and ngls ($/bbl) $ 10.94 $ 15.17 $ 19.31 $ 21.67 $ 13.84 $ 11.54 $ 11.86 $ 10.11
</TABLE>
54
<PAGE> 57
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There have been no disagreements between Chieftain and Chieftain's auditors on
accounting or financial disclosure matters.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
Additional information relating to directors of the Company is incorporated
herein by reference from page 4 of the Company's Information Circular date
March 15, 2000 for the annual meeting of shareholders on May 25, 2000.
ITEM 11. EXECUTIVE COMPENSATION
"Executive Compensation" on pages 5 to 9 of the Company's Information Circular
dated March 15, 2000 for the annual meeting of shareholders on May 25, 2000 is
incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
"Voting Shares" and "Share Ownership" on pages 2 and 3 of the Company's
Information Circular dated March 15, 2000 for the annual meeting of shareholders
on May 25, 2000 is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
None.
PART IV
ITEM 14. EXHIBITS AND REPORTS ON FORM 8-K
The following is a listing of the financial statements and financial statement
schedules which are included in this Form 10-K report.
FINANCIAL STATEMENTS
Reference is made to the list of financial statements on page 29 of this report.
EXHIBITS
Reference is made to the Index to Exhibits on page 56 on this report.
55
<PAGE> 58
EXHIBITS
<TABLE>
<CAPTION>
Exhibit
Number Exhibit
------- -------
<S> <C>
* 3 (a) Articles of Incorporation of the Company.
* 3 (b) Articles of Amendment of the Company.
* 3 (c) Articles of Amalgamation of the Company.
* 3 (d) By-laws number 1 and number 2 of the Company.
** 4 (a) Form of Subordinated Guarantee Agreement of the Company.
*** 4 (b) Shareholder Rights Plan adopted April 23, 1994.
**** 10 (a)(i) Chieftain International, Inc. Retirement Plan as amended May 15, 1997.
**** 10 (a)(ii) Chieftain International, Inc. Supplementary Retirement Plan as amended March 20, 1997.
**** 10 (b) Chieftain International, Inc. Share Option Plan as amended March 15, 1996.
* 10 (c) Chieftain International, Inc. Savings Plan.
* 10 (d) Form of indemnification agreement between the Company and each of the officers and directors of the Company.
***** 21 Information Circular dated March 15, 2000 relating to the Company's annual meeting of shareholders to be held
on May 25, 2000.
****** 22 Subsidiaries of the Company.
***** 24 (a) Consent of Netherland, Sewell & Associates, Inc.
***** 24 (b) Consent of PricewaterhouseCoopers LLP.
***** 27 Financial Data Schedule
</TABLE>
* Previously filed as an exhibit to the Registration Statement on Form S-1
File No. 33-27254.
** Previously filed as an exhibit to the Registration Statement on Form
S-1/S-3, File No. 33-51630.
*** Previously filed as an exhibit to Form 8-K dated March 1, 1994.
**** Previously filed as an exhibit to Form 10-K dated March 20, 1998.
***** Filed herewith.
****** Previously filed as an exhibit to Form 10-K dated March 17, 1994.
56
<PAGE> 59
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange
Act of 1934, the registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.
CHIEFTAIN INTERNATIONAL, INC.
BY: /s/ STANLEY A. MILNER
-------------------------------------
Stanley A. Milner, A.O.E., LL.D.
President and Chief Executive Officer
Principal Executive and Financial Officer
Dated: March 15, 2000
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities and on the date indicated.
/s/ D.E. MITCHELL Director March 15, 2000
- ------------------------------
D.E. Mitchell O.C.
/s/ S.A. MILNER President, Chief Executive March 15, 2000
- ------------------------------ Officer and Director;
S.A. Milner, A.O.E., LL.D. Principal Executive and
Financial Officer
/s/ S.C. HURLEY Director March 15, 2000
- ------------------------------
S.C. Hurley
/s/ H.J. KELLY Director March 15, 2000
- ------------------------------
H.J. Kelly
/s/ J.E. MAYBIN Director March 15, 2000
- ------------------------------
J.E. Maybin
/s/ L.G. MUNIN Director March 15, 2000
- ------------------------------
L.G. Munin
/s/ E.S. ONDRACK Director March 15, 2000
- ------------------------------
E.S. Ondrack
/s/ S.T. PEELER Director March 15, 2000
- ------------------------------
S.T. Peeler
/s/ R.J. STEFURE Vice President and March 15, 2000
- ------------------------------ Controller Principal
R.J. Stefure Accounting Officer
57
<PAGE> 60
INDEX TO EXHIBITS
<TABLE>
<S> <C>
* 3 (a) Articles of Incorporation of the Company.
* 3 (b) Articles of Amendment of the Company.
* 3 (c) Articles of Amalgamation of the Company.
* 3 (d) By-laws number 1 and number 2 of the Company.
** 4 (a) Form of Subordinated Guarantee Agreement of the Company.
*** 4 (b) Shareholder Rights Plan adopted April 23, 1994.
**** 10 (a)(i) Chieftain International, Inc. Retirement Plan as amended May 15, 1997.
**** 10 (a)(ii) Chieftain International, Inc. Supplementary Retirement Plan as amended March 20, 1997.
**** 10 (b) Chieftain International, Inc. Share Option Plan as amended March 15, 1996.
* 10 (c) Chieftain International, Inc. Savings Plan.
* 10 (d) Form of indemnification agreement between the Company and each of the officers and directors of the Company.
***** 21 Information Circular dated March 15, 2000 relating to the Company's annual meeting of shareholders to be held
on May 25, 2000.
****** 22 Subsidiaries of the Company.
***** 24 (a) Consent of Netherland, Sewell & Associates, Inc.
***** 24 (b) Consent of PricewaterhouseCoopers LLP.
***** 27 Financial Data Schedule
</TABLE>
* Previously filed as an exhibit to the Registration Statement on Form S-1
File No. 33-27254.
** Previously filed as an exhibit to the Registration Statement on Form
S-1/S-3, File No. 33-51630.
*** Previously filed as an exhibit to Form 8-K dated March 1, 1994.
**** Previously filed as an exhibit to Form 10-K dated March 20, 1998.
***** Filed herewith.
****** Previously filed as an exhibit to Form 10-K dated March 17, 1994.
<PAGE> 1
EXHIBIT 21
[CHIEFTAIN INTERNATIONAL, INC. LETTERHEAD]
NOTICE OF ANNUAL MEETING OF SHAREHOLDERS
TO BE HELD ON THURSDAY, MAY 25, 2000
The annual meeting of the shareholders of Chieftain International, Inc. ("the
Company") will be held in the Marlboro Room of The Westin Hotel, 10135 - 100
Street, Edmonton, Alberta, Canada on Thursday, May 25, 2000 at 10:30 a.m.
(Edmonton time) to receive and consider the annual report for the year ended
December 31, 1999, the financial statements as at and for the year ended
December 31, 1999, and the report of the auditors on the financial statements,
and in addition for the following purposes:
1. to elect three directors;
2. to appoint auditors of the Company until the close of the next annual
meeting;
3. to approve an amendment to the Share Option Plan; and
4. to transact all such other business as may properly come before the
meeting or any adjournment thereof.
The Board of Directors has fixed the close of business on the 27th day of March,
2000 as the record date for the determination of shareholders who are entitled
to notice of and to vote at the annual meeting. The share transfer books will
not be closed.
If you are unable to attend the meeting in person, please complete, date and
sign the enclosed form of proxy and mail it promptly in the enclosed
postage-paid envelope.
By order of the Board of Directors
/s/ ESTHER S. ONDRACK
- ------------------------------------
Esther S. Ondrack
Senior Vice President and Secretary
March 15, 2000
<PAGE> 2
[CHIEFTAIN INTERNATIONAL, INC. LETTERHEAD]
INFORMATION CIRCULAR
SOLICITATION OF PROXIES
This Information Circular and the accompanying Notice of Meeting and form of
proxy are being mailed to shareholders on or about March 30, 2000 in connection
with the solicitation of proxies by the management of Chieftain International,
Inc. (hereinafter called the "Company") to be voted at the annual meeting of
shareholders (the "meeting") to be held at 10:30 a.m., Edmonton time, in the
Marlboro Room of The Westin Hotel 10135 - 100 Street, Edmonton, Alberta, Canada
on Thursday, May 25, 2000. The Directors have fixed the close of business on
March 27, 2000 as the record date for the determination of shareholders who are
entitled to notice of and to vote at the meeting.
The solicitation will be primarily by mail and electronic means and the cost
will be borne by the Company. In addition, the Company will reimburse banks,
brokerage houses and other custodians, nominees or fiduciaries for reasonable
expenses incurred by them in forwarding proxy material to their principals to
obtain authorization for the execution of proxies.
All shares represented by proxy will be voted, provided that instruments of
proxy are received by CIBC Mellon Trust Company, registrar and transfer agent,
at its office at 600, 333 - 7th Avenue S.W., Calgary, Alberta, T2P 2Z1, Canada,
or by the Company at its principal office at 1201 TD Tower, 10088 - 102 Avenue,
Edmonton, Alberta, T5J 2Z1, Canada, no later than 10:30 a.m., May 24, 2000.
The Company's accounts are maintained, and all dollar amounts herein are stated,
in United States dollars. The average rates of exchange for Canadian dollars per
U.S.$1.00 during 1998, 1999 and during the period January 1 to February 29,
2000, were $1.4831, $1.4860 and $1.4500, respectively. The rates on December 31,
1998, December 31, 1999, and February 29, 2000 were $1.5305, $1.4433 and
$1.4488, respectively.
APPOINTMENT AND REVOCATION OF PROXIES
THE ENCLOSED PROXY IS SOLICITED BY AND ON BEHALF OF THE MANAGEMENT OF THE
COMPANY. THE PERSONS DESIGNATED IN THE ACCOMPANYING FORM OF PROXY ARE DIRECTORS
AND OFFICERS OF THE COMPANY. A SHAREHOLDER HAS THE RIGHT TO APPOINT SOME OTHER
PERSON, WHO NEED NOT BE A SHAREHOLDER, TO REPRESENT HIM OR HER AT THE MEETING
AND HE OR SHE MAY EXERCISE THIS RIGHT BY INSERTING SUCH OTHER PERSON'S NAME IN
THE BLANK SPACE PROVIDED IN THE FORM OF PROXY.
The instrument appointing a proxy shall be in writing and signed by the
shareholder or the shareholder's attorney authorized in writing. If the
shareholder is a corporation, the document must carry the signature of a duly
authorized officer or attorney thereof.
A registered shareholder who has deposited a proxy has the power to revoke it. A
proxy may be revoked by instrument in writing executed by the shareholder or by
his or her attorney authorized in writing or, if the shareholder is a
corporation, by a duly authorized officer or attorney thereof, and deposited
either at the head office of the Company at any time up to and including the
last business day preceding the day of the meeting, or any adjournment thereof,
at which the proxy is to be used, or with the chairman of such meeting on the
day of the meeting or adjournment thereof, and upon either of such deposits the
proxy is revoked. In addition, a proxy may be revoked in any other manner
permitted by law.
1
<PAGE> 3
EXERCISE OF DISCRETION BY PROXY
The person named in the enclosed proxy will vote the shares in respect of which
he or she is appointed in accordance with the direction of the shareholder
appointing him or her. IN THE ABSENCE OF SPECIFIC DIRECTION, SUCH SHARES WILL BE
VOTED IN FAVOR OF THE ELECTION OF THE DIRECTORS AND THE APPOINTMENT OF THE
AUDITORS NAMED IN THIS INFORMATION CIRCULAR AND IN FAVOR OF THE RESOLUTION TO
AMEND THE SHARE OPTION PLAN. If any amendments or variations in the matters
identified in the notice of meeting or if any other matters properly come before
the meeting or any adjournment or adjournments thereof, the proxy confers
discretionary authority upon the shareholder's nominee to vote on such
amendments or variations or such other matters in accordance with his or her
best judgment. Proxies will not be voted with respect to any material amendment
or any material variation of the matters which come before the meeting. At the
date of the notice of meeting, management knows of no such amendment or
variation or other matter to come before the meeting.
VOTING SHARES
The registered holders of the outstanding common shares of the Company of
record at the close of business on March 27, 2000 are entitled to notice of and
to vote at the meeting. The number of common shares outstanding on December 31,
1999 and on February 29, 2000 was 16,224,059. Each common share entitles the
registered holder thereof to one vote, which may be given in person or by
proxy. Approval of each matter to come before the meeting requires an
affirmative vote by the holders of a majority of the shares voted at the
meeting, whether in person or by proxy. The quorum for the meeting is two
persons present and holding or representing by proxy at least one-third of the
issued shares of the Company for the time being having voting rights.
SHARE OWNERSHIP
The following table describes, to the knowledge of the Company, shareholders
owning beneficially, as at February 29, 2000, more than five percent of the
outstanding common shares of the Company.
<TABLE>
<CAPTION>
===================================================================================================
Amount and Nature of
Name and Address Beneficial Ownership of
of Beneficial Owner Common Shares Percent of Class
<S> <C> <C>
- ---------------------------------------------------------------------------------------------------
OppenheimerFunds Inc.
Two World Trade Center, Suite 3400 1,515,200(1) 9.3
New York, New York 10048-0203
- ---------------------------------------------------------------------------------------------------
T. Rowe Price Associates, Inc.
100 East Pratt Street 1,471,300(2) 9.1
Baltimore, Maryland 21202
- ---------------------------------------------------------------------------------------------------
Scudder Kemper Investments, Inc.
345 Park Avenue 952,000(3) 5.9
New York, New York 10154
- ---------------------------------------------------------------------------------------------------
Strong Capital Management, Inc.
100 Heritage Reserve 885,200(4) 5.5
Menomonee Falls, Wisconsin 53051
===================================================================================================
</TABLE>
(1) The information is based on filings with the Securities and Exchange
Commission ("SEC") on Schedule 13-G according to which the beneficial owner
has sole voting power and shared dispositive power with respect to 1,515,200
shares.
(2) These securities are owned by various individual and institutional
investors which T. Rowe Price Associates, Inc. ("Price Associates") serves
as investment advisor with power to direct investments and/or sole power to
vote securities. For purposes of the reporting requirements of the
Securities Exchange Act of 1934, Price Associates is deemed to be a
beneficial owner of such securities; however, Price Associates expressly
disclaims that it is, in fact, the beneficial owner of such securities. The
information is based on filings with the SEC on Schedule 13-G and results of
the Company's inquiries according to which Price Associates has sole voting
power with respect to 407,500 shares and sole dispositive power with respect
to 1,417,800 shares.
(3) The information is based on filings with the SEC on Schedule 13-G and
results of the Company's inquiries according to which Scudder Kemper
Investments, Inc. ("Scudder Kemper") has sole voting power with respect to
674,500 shares, shared voting power with respect to 15,100 shares and sole
dispositive power with respect to 952,000 shares. Although these shares are
attributable to Scudder Kemper pursuant to SEC regulations, Scudder Kemper
disclaims "beneficial ownership".
(4) The information is based on filings with the SEC on Schedule 13-G
according to which the beneficial owner has sole voting power with respect
to 294,800 shares and sole dispositive power with respect to 885,200 shares.
2
<PAGE> 4
The table below indicates the number of the Company's common shares and the
number of Chieftain International Funding Corp. $1.8125 Convertible Redeemable
Preferred Shares ("the preferred shares") owned by (i) the directors (including
those nominated for election); (ii) the Named Executive Officers as defined on
page 5; and (iii) all directors and officers as a group. The common shares shown
as issuable upon exercise of options are issuable within 60 days. Each preferred
share is convertible into 1.25 common shares of the Company.
<TABLE>
<CAPTION>
====================================================================================================================================
Shares Beneficially Owned as at February 29, 2000
<S> <C> <C> <C> <C>
Common Shares Percent of Class(1) Preferred Shares Percent of Class(1)
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C>
Stephen C. Hurley 107,221(2) - - -
- ------------------------------------------------------------------------------------------------------------------------------------
Hugh J. Kelly 37,666(3) - 10,000 -
- ------------------------------------------------------------------------------------------------------------------------------------
John E. Maybin 37,666(4) - - -
- ------------------------------------------------------------------------------------------------------------------------------------
Stanley A. Milner 676,991(5) 4.1 39,000 1.4
- ------------------------------------------------------------------------------------------------------------------------------------
David E. Mitchell 46,666(3) - - -
- ------------------------------------------------------------------------------------------------------------------------------------
Louis G. Munin 40,666(3) - 2,000 -
- ------------------------------------------------------------------------------------------------------------------------------------
Esther S. Ondrack 100,110(6) - - -
- ------------------------------------------------------------------------------------------------------------------------------------
Stuart T. Peeler 19,466(7) - 30,000 1.1
- ------------------------------------------------------------------------------------------------------------------------------------
Edward L. Hahn(8) 46,286(9) - - -
- ------------------------------------------------------------------------------------------------------------------------------------
Ronald J. Stefure(10) 24,618(11) - - -
- ------------------------------------------------------------------------------------------------------------------------------------
All directors and
officers as a group 1,206,243 (12) 7.2 81,000 3.0
====================================================================================================================================
</TABLE>
(1) Percentages of less than one are omitted.
(2) Includes 103,331 shares issuable upon exercise of options.
(3) Includes 36,666 shares issuable upon exercise of options.
(4) Includes 36,166 shares issuable upon exercise of options.
(5) Includes 128,332 shares issuable upon exercise of options.
In addition an associate of S.A. Milner owns 3,000 shares.
(6) Includes 77,498 shares issuable upon exercise of options.
In addition an associate of E.S. Ondrack owns 500 shares.
(7) Shares issuable upon exercise of options.
(8) E.L. Hahn retired as Senior Vice President, Finance and Treasurer of the
Company effective December 31, 1999.
(9) Includes 37,500 shares issuable upon exercise of options.
(10) R.J. Stefure is Vice President and Controller of the Company.
(11) Includes 23,334 shares issuable upon exercise of options.
(12) Includes 563,960 shares issuable upon exercise of options.
COMMITTEES AND MEETINGS OF THE BOARD OF DIRECTORS
The Board of Directors held four regularly scheduled and six additional meetings
during the year ended December 31, 1999. With the exception of one director's
unavoidable absence from one meeting held by telephone, each member of the Board
of Directors including those nominated for election attended all of the meetings
of the Board of Directors and all of the meetings of the committees on which the
member served during 1999. The Company has standing Audit, Compensation,
Nominating and Corporate Governance, Pension and Reserve Committees of the Board
of Directors. The members of the committees are appointed by the full Board upon
recommendation of the Nominating and Corporate Governance Committee. All of the
members of all of the committees are independent unrelated directors. Mr.
Mitchell serves as non-executive Chairman of the Board.
AUDIT COMMITTEE
The Audit Committee, which during 1999 consisted of L.G. Munin as Chairman and
J.E. Maybin, D.E. Mitchell and S.T. Peeler, held five meetings during 1999. The
primary function of the Audit Committee is to assist the Board of Directors in
providing corporate oversight in the areas of financial reporting, internal
control and the audit process. The Committee regularly meets alone with Company
personnel and with the independent auditors. The independent auditors have
access to the Committee at any time. The Committee recommends to the Board for
its approval the financial statements and the annual appointment of external
auditors.
COMPENSATION COMMITTEE
The Compensation Committee is comprised of S.T. Peeler as Chairman and H.J.
Kelly, J.E. Maybin, and D.E. Mitchell. The primary function of the Compensation
Committee is to assist the Board of Directors in carrying out its
responsibilities by reviewing compensation matters and making recommendations to
the Board. This Committee considers and recommends to the Board for approval
directors compensation, appointment and remuneration of officers and
transactions under the Company's share option plan. It also reviews compensation
and benefits budgets, plans and policies, salaries of certain non-officer
employees and succession planning. The Compensation Committee met twice in 1999.
3
<PAGE> 5
NOMINATING AND CORPORATE GOVERNANCE COMMITTEE
The Nominating and Corporate Governance Committee is comprised of J.E. Maybin as
Chairman and D.E. Mitchell, L.G. Munin and S.T. Peeler. This Committee assists
the Board by reviewing corporate governance and Board nomination matters and
making recommendations to the Board as appropriate. The Committee met once
during 1999 to consider the size and composition of the Board of Directors,
nominees for the election of directors at the 1999 annual meeting and corporate
governance practices.
PENSION COMMITTEE
The Pension Committee is comprised of H.J. Kelly as Chairman, J.E. Maybin, D.E.
Mitchell and S.T. Peeler. E.L. Hahn was a member of the Committee until his
retirement at year-end. This Committee reviews generally and makes
recommendations to the Board of Directors with regard to the Company's
retirement plans, related agreements and the appointment and performance of
retirement fund investment managers. This committee met once during 1999.
RESERVE COMMITTEE
The Reserve Committee is comprised of D.E. Mitchell as Chairman, H.J. Kelly,
J.E. Maybin and S.T. Peeler. The committee acts in an advisory capacity to the
Board. Its primary function is to review the externally disclosed oil and gas
reserve estimates of the Company. The committee reviews the reports of the
independent engineers charged with evaluating the Company's reserves and also
reviews the selection of the independent engineers and the scope of their work.
ELECTION OF DIRECTORS
The Articles of the Company provide that directors are elected and retire in
rotation. Directors are elected to hold office until the close of the third
ensuing annual meeting. At each annual meeting approximately one-third of the
board is elected. Effective upon the termination of the forthcoming annual
meeting, the terms of Stephen C. Hurley, John E. Maybin and Esther S. Ondrack
will expire. It is proposed that three directors be elected for the ensuing
three years. Management will place before the annual meeting as nominees Stephen
C. Hurley, John E. Maybin and Esther S. Ondrack and PROXIES GIVEN PURSUANT TO
THIS SOLICITATION BY MANAGEMENT WILL BE VOTED FOR THE ELECTION OF SAID NOMINEES
UNLESS INDICATED OTHERWISE. While management knows of no reason why the said
nominees will be unable or unwilling to serve as directors, if for any reason
they shall be unable or unwilling to serve, it is intended that proxies given
pursuant to this solicitation by management will be voted for substitute
nominees selected by management.
Information is given below with respect to the nominees and the directors whose
terms of office as directors will continue after the meeting.
<TABLE>
<CAPTION>
=================================================================================================================
NAME AND PRINCIPAL OCCUPATION SERVED AS DIRECTOR SINCE TERM EXPIRES
- -----------------------------------------------------------------------------------------------------------------
<S> <C> <C>
STEPHEN C. HURLEY, Dallas, Texas
Senior Vice President and Chief Operating Officer of the Company(1) 1997 2003(2)
- -----------------------------------------------------------------------------------------------------------------
HUGH J. KELLY, Mandeville, Louisiana
Corporate Director and Consultant(3) 1989 2002
- -----------------------------------------------------------------------------------------------------------------
JOHN E. MAYBIN, Calgary, Alberta
Corporate Director 1991 2003(2)
- -----------------------------------------------------------------------------------------------------------------
STANLEY A. MILNER, A.O.E., L.L.D., Edmonton, Alberta
President and Chief Executive Officer of the Company(4) 1988 2001
- -----------------------------------------------------------------------------------------------------------------
DAVID E. MITCHELL, O.C., Calgary, Alberta
Chairman Emeritus of Alberta Energy Company Ltd. 1989 2001
- -----------------------------------------------------------------------------------------------------------------
LOUIS G. MUNIN, Dallas, Texas
Corporate Director and Financial Consultant(5) 1989 2002
- -----------------------------------------------------------------------------------------------------------------
ESTHER S. ONDRACK, Spruce Grove, Alberta
Senior Vice President and Secretary of the Company(6) 1988 2003(2)
- -----------------------------------------------------------------------------------------------------------------
STUART T. PEELER, Tucson, Arizona
Corporate Director and Petroleum Industry Consultant(7) 1989 2002
=================================================================================================================
</TABLE>
(1) S.C. Hurley joined the Company as Senior Vice President and Chief Operating
Officer in September, 1995. From 1991 to 1995 he was Vice President
Exploration of Murphy Exploration and Production Company.
(2) Date when proposed term of office will expire.
(3) H.J. Kelly is a director of Gulf Island Fabrication Inc. and Tidewater Inc.
(4) S.A. Milner is Chairman of the Board of Alberta Energy Company Ltd.
(5) L.G. Munin is a director of Lafarge Canada Inc. and Walden Residential
Properties, Inc.
(6) E.S. Ondrack was Vice President and Secretary of the Company until June,
1995.
(7) S.T. Peeler is a director of Homestake Mining Company.
4
<PAGE> 6
EXECUTIVE COMPENSATION
The following table sets forth certain information regarding the compensation
paid, during each of the Company's three most recently completed fiscal years,
to the Chief Executive Officer and the Company's next four most highly
compensated executive officers (collectively "Named Executive Officers").
<TABLE>
<CAPTION>
====================================================================================================================================
SUMMARY COMPENSATION TABLE (U.S.$)
- ------------------------------------------------------------------------------------------------------------------------------------
Annual Compensation Long-Term Compensation
------------------------------------- --------------------------------------
Awards
-------------------------
Securities Restricted
Under Shares Payouts
Name and Other Options or -------
Principal Annual and SARs Restricted LTIP All Other
Position Year Salary Bonus Compensation Granted Share Units Payouts Compensation(1)
($) ($) ($) (#) ($) ($) ($)
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C>
Stanley A. Milner 1999 365,803 375,000 (2) 45,000 - - 95,073
President and 1998 355,000 100,000 (2) 5,000 - - 88,561
Chief Executive Officer 1997 320,273 250,000 (2) 25,000 - - 83,568
- ------------------------------------------------------------------------------------------------------------------------------------
Stephen C. Hurley 1999 293,124 275,000 (2) 5,000 - - 67,765
Senior Vice President and 1998 283,875 70,000 (2) 30,000 - - 64,085
Chief Operating Officer 1997 245,946 185,000 (2) 25,000 - - 52,317
- ------------------------------------------------------------------------------------------------------------------------------------
Edward L. Hahn(3) 1999 110,325 76,000 (2) 2,500 - - 36,191
Senior Vice President 1998 142,655 21,500 (2) - - - 44,258
Finance and Treasurer 1997 136,176 40,000 (2) 10,000 - - 34,755
- ------------------------------------------------------------------------------------------------------------------------------------
Esther S. Ondrack 1999 133,166 66,000 (2) 32,500 - - 42,233
Senior Vice President 1998 129,231 19,500 (2) 5,000 - - 40,142
and Secretary 1997 122,157 40,000 (2) 15,000 - - 30,517
- ------------------------------------------------------------------------------------------------------------------------------------
Ronald J. Stefure 1999 98,708 43,000 (2) 15,000 - - 62,034
Vice President 1998 95,790 14,500 (2) - - - 25,364
and Controller 1997 95,570 35,000 (2) 9,000(4) - - 21,063
====================================================================================================================================
</TABLE>
(1) The amounts in this column represent Company contributions to the defined
contribution retirement plans, the savings plan and the life insurance plan
in which plans the Named Executive Officers participate on the same basis as
all other employees. Such amounts do not include directors fees paid to each
of S.A. Milner and E.S. Ondrack, ($24,000 in 1997 and $25,000 in 1998 and
1999), and S.C. Hurley ($9,423 in 1997 and $25,000 in each of 1998 and
1999).
(2) The value of perquisites and benefits for each of the Named Executive
Officers is not greater than the lesser of C$50,000 and 10% of total
annual salary and bonus.
(3) E.L. Hahn served on a part-time basis for a portion of the year and retired
on December 31, 1999.
(4) Includes 4,000 Share Appreciation Rights ("SARs") and 5,000 share options.
The following table sets forth information regarding grants of share options to
the Named Executive Officers during the financial year ended December 31, 1999.
<TABLE>
<CAPTION>
OPTION GRANTS DURING 1999
====================================================================================================================================
Number of Shares % of Total Options Exercise Grant Date
Name Under Options Granted Granted in 1999 Price(1) Present Value(2) Expiration Date
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C>
Stanley A. Milner 5,000 2.8 $11.43 $ 29,650 Mar. 10, 2009
40,000(3) 22.2 13.50 284,400 Apr. 12, 2009
Stephen C. Hurley 5,000 2.8 11.43 29,650 Mar. 10, 2009
Edward L. Hahn 2,500(3) 1.4 13.50 17,775 Apr. 12, 2009
Esther S. Ondrack 5,000 2.8 11.43 29,650 Mar. 10, 2009
27,500(3) 15.3 13.50 195,525 Apr. 12, 2009
Ronald J. Stefure 15,000(3) 8.3 18.31 153,000 Nov. 9, 2009
====================================================================================================================================
</TABLE>
(1) Not less than closing market value of shares underlying options on trading
day prior to date of grant.
(2) The grant date present values were calculated using the Black-Scholes option
pricing model using an expected volatility of 28%, a risk free rate of
5.81%, no dividend yields and ten year option lives, all on a weighted
average basis.
(3) Option granted following the expiry of unexercised option granted in 1989 on
the same number of shares.
The options are exercisable as to one-third of the granted amount on and after
each of the first three anniversaries of the date of grant. Exercisability of
options accelerates in certain events, including death, disability, retirement
and a change in control of the Company. The exercisability of options is
contingent upon continued service except that options exercisable on the date of
termination of employment may be exercised thereafter under certain conditions.
5
<PAGE> 7
No options were exercised by the Named Executive Officers in 1999. The
following table shows the value, on December 31, 1999, of the unexercised
options held by the Named Executive Officers.
<TABLE>
<CAPTION>
====================================================================================================================================
SHARE OPTION EXERCISES IN 1999 AND YEAR-END 1999 SHARE OPTION VALUES
- ------------------------------------------------------------------------------------------------------------------------------------
Unexercised Options held on Value of Unexercised in-the-Money
December 31, 1999 Options on December 31, 1999
Securities Acquired Aggregate Value ----------------------------- --------------------------------
Name on Exercise Realized ($) Exercisable Unexercisable Exercisable Unexercisable
- ----------------- ------------------- --------------- ----------- ------------- ----------- -------------
<S> <C> <C> <C> <C> <C> <C>
Stanley A. Milner -- -- 113,332 56,668 $ 263,950 $ 179,100
Stephen C. Hurley -- -- 100,165 33,335 150,000 29,100
Edward L. Hahn -- -- 31,666 5,834 64,250 9,375
Esther S. Ondrack -- -- 66,666 40,834 119,150 132,225
Ronald J. Stefure -- -- 23,334 16,666 54,900 --
====================================================================================================================================
</TABLE>
CHANGE IN CONTROL AGREEMENTS
The Company has agreements with certain employees, including the Named
Executive Officers, requiring that if, under certain circumstances, following a
change in control of the Company, employment is terminated, the employee will
receive a severance payment equal to two times the employee's average annual
base salary during the previous three years and certain benefits for a two year
period following termination of employment.
COMPENSATION COMMITTEE REPORT
The Compensation Committee of the Board of Directors is responsible for
reviewing compensation policies and practices of the Company, both generally
and in specific relation to the appointment and compensation of the officers
and certain members of senior management, as described under "Committees and
Meetings of the Board of Directors."
Compensation of the Company's employees, including officers and senior
management is comprised of salary, performance bonuses, various benefit plans,
including a retirement plan and a savings plan and stock options. Compensation
plans are designed to provide competitive levels of compensation which will
attract and retain competent, motivated personnel who will perform to their
potential to increase the value of the Company for the benefit of the
shareholders.
Salaries are reviewed annually in relation to the achievement of both corporate
and individual performance objectives and with a view to achieving and
maintaining external competitiveness and internal equity. Grants are made
under the Share Option Plan in the discretion of the Board of Directors on the
advice of the Compensation Committee and vary as to timing and amount with the
responsibilities and performance of the individual.
The compensation of the President and Chief Executive Officer of the Company,
Mr. Stanley A. Milner, is comprised of the same components and is determined in
the same manner as that of the other executive officers.
Submitted on behalf of the Compensation Committee: Stuart T. Peeler, Chairman
Hugh J. Kelly
John E. Maybin
David E. Mitchell
The Board of Directors has accepted all recommendations of the Compensation
Committee.
6
<PAGE> 8
PERFORMANCE GRAPHS(1)
The graphs which follow assume that C$100 was invested (A) on April 30, 1989,
when the Company ("CII") commenced operations, in the Company's common shares
and in The Toronto Stock Exchange ("TSE") Oil and Gas Producers Index, and (B)
on December 31, 1994 in the Company's common shares, the TSE Oil and Gas
Producers Index and the TSE 300 Composite Index.
(A) CUMULATIVE VALUE OF C$100 INVESTED ON APRIL 30, 1989
[GRAPH]
<TABLE>
<CAPTION>
- ----------------------------------------------------------------------------------------------------------------------------
Apr. 30, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31,
1989 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
- ----------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CII C$ 100 144 137 101 137 135 91 149 224 189 143 155
- ----------------------------------------------------------------------------------------------------------------------------
TSE C&GP 100 113 102 87 93 129 117 136 187 167 117 143
- ----------------------------------------------------------------------------------------------------------------------------
</TABLE>
(B) CUMULATIVE VALUE OF C$100 INVESTED ON DECEMBER 31, 1994
[GRAPH]
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
Dec. 31, 1994 Dec. 31, 1995 Dec. 31, 1996 Dec. 31, 1997 Dec. 31, 1998 Dec. 31, 1999
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
CII C$ 100 164 246 208 158 171
- --------------------------------------------------------------------------------------------------------------------------------
TSE O&GP 100 116 160 143 100 122
- --------------------------------------------------------------------------------------------------------------------------------
TSE 300 100 115 147 169 166 219
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(1) Reinvestment of dividends is assumed in all cases. The graphs were plotted
using the data shown below each graph.
7
<PAGE> 9
The following graphs assume that U.S.$100 was invested (C) on April 30, 1989,
when the Company ("CII") commenced operations, in the Company's common shares
and in the American Stock Exchange ("AMEX") Natural Resources Index and (D) on
December 31, 1994 in the Company's common shares, the AMEX Natural Resources
Index and the AMEX Total Return Index. The AMEX Natural Resources Index was
reconfigured effective December 31, 1995.
(C) CUMULATIVE VALUE OF U.S.$100 INVESTED ON APRIL 30, 1989
[GRAPH]
<TABLE>
<CAPTION>
- ------------------------------------------------------------------------------------------------------------------------------------
Apr. 30, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31, Dec. 31,
1989 1989 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999
- ------------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C> <C>
CII U.S.$ 100 150 140 105 129 122 75 131 193 157 106 128
- ------------------------------------------------------------------------------------------------------------------------------------
AMEX Nat. Res. 100 115 96 84 73 91 90 100 123 132 86 116
- ------------------------------------------------------------------------------------------------------------------------------------
</TABLE>
(D) CUMULATIVE VALUE OF U.S.$100 INVESTED ON DECEMBER 31, 1994
[GRAPH]
<TABLE>
<CAPTION>
- --------------------------------------------------------------------------------------------------------------------------------
Dec. 31, 1994 Dec. 31, 1995 Dec. 31, 1996 Dec. 31, 1997 Dec. 31, 1998 Dec. 31, 1999
- --------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C> <C> <C> <C>
CII U.S.$ 100 175 257 210 142 170
- --------------------------------------------------------------------------------------------------------------------------------
AMEX Nat. Res. 100 101 124 133 87 117
- --------------------------------------------------------------------------------------------------------------------------------
AMEX Total Return 100 129 131 163 175 224
- --------------------------------------------------------------------------------------------------------------------------------
</TABLE>
8
<PAGE> 10
COMPENSATION OF DIRECTORS
With effect from January 1, 1998, each Director receives an annual retainer of
$25,000, which is paid in quarterly installments. Each non-executive Director
is also paid at the rate of $1,000 for each Board meeting and committee meeting
attended. In addition, the Chairman of the Board and the Chairman of each
committee receives a chairman's retainer in the amount of $4,000 per year, paid
in quarterly installments. Directors receive no compensation for the time
required to prepare for or travel to or from Board or committee meetings. The
Company reimburses reasonable out-of-pocket expenses incurred by Directors. On
March 11, 1999, each of the Directors was granted an option on 5,000 common
shares at the exercise price of $11.43 per share.
APPOINTMENT OF AUDITORS
As set forth in the notice, action will be taken at the meeting to provide for
the appointment of auditors until the close of the next annual meeting. THE
PROXIES HEREBY SOLICITED WILL BE EXERCISED IN FAVOR OF THE APPOINTMENT OF
PRICEWATERHOUSECOOPERS LLP which firm and its predecessor, Price Waterhouse,
have been the Company's auditors since the Company's inception. A
representative of PricewaterhouseCoopers LLP is expected to be present at the
meeting.
APPROVAL OF AMENDMENT TO SHARE OPTION PLAN
DESCRIPTION OF THE PLAN
The Share Option Plan (the "Plan") provides for the granting of share options
to such employees and directors of and consultants to the Company and its
subsidiaries as are designated by the Board of Directors upon the advice of
the Compensation Committee. All employees (including officers), consultants
and directors are eligible.
The amount of any option granted is determined by the Board of Directors upon
the advice of the Compensation Committee. There are no limitations as to the
number of shares with respect to which an option may be granted to any one
optionee except that no optionee is permitted to hold options to purchase more
than 5% of the issued and outstanding common shares of the Company. Shares in
respect of which options have terminated without exercise are available for the
granting of options.
Options granted under the Plan expire no later than the tenth anniversary of
the date of grant and are cumulatively exercisable as to one-third of the
shares subject thereto on and after each of the first three anniversary dates
of the date of grant. The exercise price must be no less than the market price,
as defined in the Plan, at the time the option is granted.
The exercise of an option is contingent upon continued employment with
exceptions in certain events including death, disability or retirement and in
any such event the option is fully exercisable. The exercisability of options
is also accelerated in the event an offer is made which would, if successful,
result, in the opinion of the Board, in a change of control of the Company; or
in any event which, in the opinion of the Board, warrants acceleration. Options
are not transferable.
Note 4 of the Notes to Financial Statements of the Company for the year ended
December 31, 1999 contains information on activity in the Plan.
PROPOSED PLAN AMENDMENT
On March 15, 2000, the Board of Directors approved an amendment to the
Company's Share Option Plan, subject to approval of the shareholders, fixing
the number of shares reserved for issuance under the Plan at 1,500,000. The
number of shares reserved for issuance under the Plan was last fixed at
1,300,000 in 1996.
The Plan requires that the number of shares reserved for issuance shall not
exceed 10% of the total number of issued and outstanding shares of the Company.
The following table shows the number of Common Shares reserved for the Plan,
before and after the proposed amendment, as at February 29, 2000, as of which
date the number of Common Shares issued and outstanding was 16,224,059.
9
<PAGE> 11
<TABLE>
<CAPTION>
- -----------------------------------------------------------------------------------------------------------------------------------
COMMON SHARES RESERVED COMMON SHARES RESERVED FOR MAXIMUM COMMON SHARES
FOR OUTSTANDING OPTIONS FUTURE EVENTS OF OPTIONS RESERVED FOR OPTIONS
- -----------------------------------------------------------------------------------------------------------------------------------
<S> <C> <C> <C>
Currently approved 1,119,189 11,018 1,130,207
- -----------------------------------------------------------------------------------------------------------------------------------
Proposed Increase - 369,793 369,793
- -----------------------------------------------------------------------------------------------------------------------------------
Total 1,119,189 380,811 1,500,000
- -----------------------------------------------------------------------------------------------------------------------------------
% of Outstanding Common Shares 6.9% 2.3% 9.2%
- -----------------------------------------------------------------------------------------------------------------------------------
</TABLE>
The Board of Directors believes it is in the interest of the Company to provide
incentives to the employees, consultants and directors in the form of options on
Common Shares of the Company. The Board recommends that the shareholders approve
the following resolution:
RESOLVED THAT:
1. An amendment to the Chieftain International, Inc. Share Option Plan
(the "Plan"), as described in the Information Circular dated March 15,
2000, be and is hereby approved; and
2. Any offer of the Company be and is hereby authorized, for and on
behalf of the Company, to execute and deliver such documents and
instruments and to take such actions as such officer may determine to
be necessary or advisable to implement this resolution and the matters
authorized hereby, such determination to be conclusively evidenced by
the execution and delivery of any such document or instrument and the
taking of any such action.
OTHER MATTERS
To the knowledge of the directors and management of the Company, there is no
business to be presented for action by the shareholders at the meeting to which
this Information Circular relates other than that mentioned herein or in the
Notice of Meeting.
The date by which shareholder proposals must be received by the Company for
inclusion in the information circular and proxy form relating to the 2001 annual
meeting is December 1, 2000.
ADDITIONAL INFORMATION
Shareholders may obtain copies of the Company's latest Annual Information Form
and any documents incorporated therein by reference; the Company's latest Annual
Report on Form 10-K and any documents incorporated therein by reference; the
Company's audited Consolidated Financial Statements for the year ended December
31, 1999 and any interim financial statements issued subsequent thereto, and
this Information Circular from the Secretary of the Company at 1201 TD Tower,
10088-102 Avenue, Edmonton, Alberta, T5J 2Z1, Canada.
CERTIFICATE
The foregoing contains no untrue statement of a material fact and does not omit
to state a material fact that is required to be stated or that is necessary to
make a statement not misleading in light of the circumstances in which it was
made.
/s/ S.A. Milner
- ---------------------------------------
S.A. Milner, A.O.E., LL.D.
President and Chief Executive Officer
and Chief Financial Officer
Edmonton, Alberta
March 15, 2000
10
<PAGE> 1
EXHIBIT 24(a)
[NETHERLAND, SEWELL & ASSOCIATES, INC. LETTERHEAD]
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the references to our firm and our report and to the
use of our report in the Annual Report of Chieftain International, Inc. on Form
10-K for the fiscal year ended December 31, 1999, filed with the Securities and
Exchange Commission in Washington, D.C. pursuant to the Securities Exchange Act
of 1934.
NETHERLAND, SEWELL & ASSOCIATES, INC.
By: /s/ FREDERIC D. SEWELL
--------------------------
Frederic D. Sewell
President
Dallas, Texas
March 15, 2000
<PAGE> 1
EXHIBIT 24(b)
CONSENT OF INDEPENDENT ACCOUNTANTS
We hereby consent to the incorporation by reference in the Registration
Statement on Form S-3 (No. 333-88661) of Chieftain International Inc. of our
report dated February 3, 2000 relating to the consolidated financial statements
which appears in this Form 10-K.
/s/ PRICEWATERHOUSECOOPERS LLP
Chartered Accountants
Edmonton, Alberta, Canada
March 20, 2000
<TABLE> <S> <C>
<ARTICLE> 5
<LEGEND>
THIS SCHEDULE CONTAINS SUMMARY FINANCIAL INFORMATION EXTRACTED FROM THE DECEMBER
31, 1999 BALANCE SHEET AND THE STATEMENT OF INCOME (LOSS) FOR THE YEAR ENDED
DECEMBER 31, 1999 INCLUDED IN THE COMPANY'S DECEMBER 31, 1999 10-K AND IS
QUALIFIED IN ITS ENTIRETY BY REFERENCE TO SUCH 10-K.
</LEGEND>
<MULTIPLIER> 1,000
<S> <C>
<PERIOD-TYPE> YEAR
<FISCAL-YEAR-END> DEC-31-1999
<PERIOD-START> JAN-01-1999
<PERIOD-END> DEC-31-1999
<CASH> 19,368
<SECURITIES> 0
<RECEIVABLES> 18,855
<ALLOWANCES> 0
<INVENTORY> 0
<CURRENT-ASSETS> 38,973
<PP&E> 609,558<F1>
<DEPRECIATION> 332,409
<TOTAL-ASSETS> 330,758<F2>
<CURRENT-LIABILITIES> 25,369
<BONDS> 10,000<F3>
0
0
<COMMON> 237,076
<OTHER-SE> 34,025<F4>
<TOTAL-LIABILITY-AND-EQUITY> 330,758<F5>
<SALES> 75,366
<TOTAL-REVENUES> 76,447
<CGS> 0
<TOTAL-COSTS> 86,471<F6>
<OTHER-EXPENSES> 0
<LOSS-PROVISION> 0
<INTEREST-EXPENSE> 2,496
<INCOME-PRETAX> (12,520)
<INCOME-TAX> (5,623)
<INCOME-CONTINUING> (6,897)
<DISCONTINUED> 0
<EXTRAORDINARY> 0
<CHANGES> 0
<NET-INCOME> (6,897)
<EPS-BASIC> (0.86)
<EPS-DILUTED> (0.86)
<FN>
<F1>The Company accounts for gas and oil properties in accordance with Canadian
guidelines on full cost accounting.
<F2>Deferred income taxes of $14,636 have been included in total assets.
<F3>Unsecured revolving credit facility with a syndicate of banks, in the amount
of US $100 million, fully revolving for 364 day periods with extensions at the
option of the lenders upon notice from the Company. If not extended, the
facility converts to term loans repayable over a period not exceeding four
years. Advances under the facility bear interest at Canadian prime or U.S.
base rate, or at Bankers' Acceptance rates or LIBOR plus applicable
margins.
<F4>Preferred shares of a subsidiary of $63,403, contributed surplus of $26
(attributable to common shares), and retained earnings (deficit) of $(29,404),
have been combined in calculating other stockholders' equity.
<F5>Abandonment cost accrual of $8,595 and deferred income taxes of $15,693 have
been included in total liabilities and stockholders' equity.
<F6>Production costs of $14,320 general and administrative expenses of
$4,580, depletion and amortization of $51,385, and additional depletion of
$16,186 have been combined in calculating total costs.
</FN>
</TABLE>
