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FORM 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
[x] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended DECEMBER 31, 2000
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, 2001 was US$408,903,378.
The number of shares outstanding of the common stock of Chieftain International,
Inc. on March 14, 2001 was 16,034,477.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Chieftain International, Inc. Information Circular dated April
4, 2001 for its annual and special meeting of shareholders to be held on May 17,
2001, are incorporated by reference into Part III hereof, to the extent
indicated herein. The Exhibits Index can be found on page 55 of this document.
This report contains forward-looking statements that are subject to risk factors
associated with the oil and gas business. The Company believes that the
expectations reflected in these statements are reasonable, but may be affected
by a variety of factors including, but not limited to: price fluctuations,
currency fluctuations, drilling and production results, imprecision of reserve
estimates, loss of market, industry competition, environmental risks, political
risks and capital restrictions.
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CHIEFTAIN INTERNATIONAL, INC.
2000 FORM 10-K ANNUAL REPORT
Table of Contents
Page
----
PART I
Item 1. Business ...................................................................... 1
Segment Information ......................................................... 1
Properties .................................................................. 2
Acreage ..................................................................... 7
Gas and Oil Capital Expenditures ............................................ 7
Drilling Activity ........................................................... 8
Wells ....................................................................... 8
Reserves .................................................................... 8
Production Volumes, Prices and Costs ........................................ 9
Employees ................................................................... 9
Business Risks .............................................................. 9
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 ................................... 30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure..................................................................... 54
PART III
Item 10. Directors and Executive Officers .............................................. 54
Item 11. Executive Compensation ........................................................ 54
Item 12. Security Ownership of Certain Beneficial Owners and Management ................ 54
Item 13. Certain Relationships and Related Transactions ................................ 54
PART IV
Item 14. Exhibits and Reports on Form 8-K .............................................. 54
Signatures ................................................................................. 56
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PART I
ITEM 1. BUSINESS
We are 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 offshore US Gulf of Mexico. We also have
properties located onshore in Louisiana, in the Four Corners area of southeast
Utah and in the UK 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 in April, 1989.
We have a large natural gas and oil lease acreage position in the US Gulf of
Mexico region. Our lease interests in the Gulf of Mexico region 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 natural gas and oil
reserves, to relatively lower risk development and exploitation projects with
lower reserve potential. Our exploration efforts are supported by an extensive
3D 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 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 141 lease blocks located on the continental shelf of the US
Gulf of Mexico. We also have interests in 11 deep-water blocks. Of these lease
blocks, 99 are held as exploratory acreage and 53 are held by production. We are
operator of 45 of these blocks. Our average working interest in our US Gulf of
Mexico leases is approximately 40%. In 2000 our production was 100.5 mmcfe per
day (82.9 mmcfe per day after royalties) of which 78%, or 78.8 mmcfe per day
(63.9 mmcfe per day after royalties), was in the US Gulf of Mexico.
In addition to our US Gulf of Mexico properties, we own various interests in two
large light oil producing units in the Four Corners area of southeast Utah where
our production averaged 1,793 barrels per day (1,566 barrels per day after
royalties) in 2000. We own an interest in approximately 8,300 net acres in the
UK sector of the North Sea where our production averaged 5.4 mmcfe per day
(before and after royalties) in 2000. We are also engaged in exploratory
activities onshore in Louisiana.
At December 31, 2000, we had estimated proved reserves of 326 bcfe (266 bcfe
after royalties). These reserves had a present value of net cash flows before
income taxes, discounted at 10%, of $1.2 billion using constant natural gas and
oil prices in effect on December 31, 2000, which averaged $9.68 per mcf for US
natural gas, $3.65 per mcf for UK natural gas and $24.60 per barrel for oil. At
December 31, 2000, approximately 72% of our proved reserves were natural gas and
approximately 59% of our proved reserves were developed. Our total proved
reserves at December 31, 2000 had a reserve life index of approximately 8.9
years.
SEGMENT INFORMATION
Reference is made to pages 42 and 43 hereof for financial information with
respect to our geographic segments for the years ended December 31, 2000, 1999
and 1998.
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* Unless the context indicates another meaning, the terms "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".
Our accounts are maintained, and all dollar amounts herein are stated, in
United States Dollars unless otherwise indicated.
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PROPERTIES
Our principal natural gas and oil properties are in the US Gulf of Mexico and
onshore Louisiana, Utah and other parts of the US and in the UK 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, 2000. The estimated present
values reflect the US Securities and Exchange Commission required use of
year-end prices, which at December 31, 2000 were $9.68 per mcf for US natural
gas and $24.60 per barrel of oil.
Proved reserves (before royalties)
------------------------------------------
Estimated
present value before
Natural Oil and income taxes of
gas ngls Total proved reserves
(mmcf) (mbbls) (mmcfe) (US$ in thousands)
---------- ---------- ---------- --------------------
Gulf of Mexico 154,404 4,808 183,252 $ 904,082
Onshore Louisiana 71,858 229 73,232 262,126
Utah and Other Onshore 1,589 10,277 63,251 46,864
------- ------ ------- ----------
Total US 227,851 15,314 319,735 1,213,072
UK (North Sea) 5,985 19 6,099 13,887
------- ------ ------- ----------
Total 233,836 15,333 325,834 $1,226,959
======= ====== ======= ==========
US GULF OF MEXICO
We concentrate our exploration and production activities in, and devote
substantial managerial and financial resources to, the offshore US 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. Our exploration and development activities are
focused primarily on 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 US Gulf of Mexico. With an average
interest of 40% in 152 blocks, we rank as one of the top ten independent
leaseholders in the US Gulf of Mexico. Of these lease blocks, 141 are shallow
water blocks and 11 are deep-water blocks. We acquired 11 blocks covering 55,696
acres at the March 2000 Central Gulf of Mexico lease sale. We acquired 3 blocks,
covering 17,280 acres, at the Western Gulf of Mexico lease sale in late August
2000. Our acreage in the Gulf of Mexico covered 719,798 (285,598 net) acres at
December 31, 2000. Of the 152 US Gulf of Mexico blocks in which we hold an
interest, we are the designated operator of 45.
Described below are the areas of our current exploration and development
activity in the US Gulf of Mexico.
WESTERN GULF (OFFSHORE TEXAS)
MUSTANG ISLAND:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
5 21,818 10,549 48.3% 7.7 mmcf per day 6.4 mmcf per day
Most of our production in this area comes from our 50% working interest in Block
784. No significant exploration or development work is currently planned for
2001.
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MATAGORDA ISLAND:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
8 41,849 13,279 31.7% 8.1 mmcf per day 6.4 mmcf per day
In 2000, we participated in one successful exploratory well and one successful
development well on Block 704, in which we have a 25% working interest.
Production commenced from these wells late in the fourth quarter. Numerous
wireline, coiled tubing and rig recompletions are planned for the Matagorda
Island area during 2001. We also expect to drill an exploratory well on Block
634 where we have a 24.1% working interest.
HIGH ISLAND/EAST ADDITION/SOUTH EXTENSION:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
13 74,880 29,378 39.2% 8.6 mmcf per day and 7.0 mmcf per day and
95 barrels per day 77 barrels per day
During 2000, we participated in two unsuccessful exploratory wells in this area,
both on Block 206. We had a 33.3% working interest in one well and a 25% working
interest in the other. In 2001, we expect to participate in an exploratory well
on each of Block 163, where we have a 30% working interest, Block 166, where we
have a 33.3% working interest, and Block 348, where we have a 33.3% working
interest.
HIGH ISLAND SOUTH ADDITION:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
12 64,800 33,821 52.2% 0.6 mmcf per day 0.5 mmcf per day
During 2000, we participated in two successful exploratory wells, one successful
development well and one unsuccessful exploratory well in this area. Late in the
fourth quarter, a successful exploratory well was drilled from an existing
production facility on Block A-467, where we have a 50% working interest.
Production commenced in the first quarter of 2001. An exploratory well on Block
A-554, where we have a 41.7% working interest, was drilled successfully in the
fourth quarter and this natural gas discovery is expected to commence production
during 2001. We are operator of Block A-531 where a development well encountered
a commercial natural gas reservoir. The A-531Block, in which we have a 50%
working interest, is expected to commence production during 2001 through a
facility on the adjoining Block A-510, which we also operate and have a 50%
working interest in. An exploratory well on Block A-567, where we have a 50%
working interest, was junked and abandoned prior to reaching its geological
objective and the drilling contractor did not earn there turnkey contract fee.
In the second half of 2001, we expect to drill an exploratory well on Block
A-567.
GARDEN BANKS:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
4 23,040 7,200 31.3% 2.8 mmcf per day 2.4 mmcf per day
All of our production in this area currently comes from our 25% working interest
in Block 224. We will be participating in an exploratory well in this deep water
area during 2001. With a planned target depth of approximately 18,000 feet, the
well could be drilled as early as the second quarter of 2001. It will test the
Antigua prospect, located on Blocks 397 and 441. The water depth in the drilling
area is approximately 2,500 feet. We have a 25% working interest in the project.
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CENTRAL GULF (OFFSHORE LOUISIANA)
EAST CAMERON:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
7 32,500 11,250 34.6% 2.2 mmcf per day and 1.8 mmcf per day and
284 barrels per day 236 barrels per day
In 2000, we participated in three successful exploratory wells in this area.
Late in the fourth quarter, a natural gas well was drilled on Block 83, where we
have a 25% working interest. Two natural gas wells were drilled on Block 104,
where we have a 40% working interest. The Block 83 and Block 104 wells are
expected to commence production during 2001. An exploratory well on Block 255,
where we have a 60% working interest, and another on Block 369, where we have a
40% working interest, are planned for the second half and first half,
respectively, of 2001.
VERMILION:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
5 15,267 7,908 51.8% 10.1 mmcf per day and 8.4 mmcf per day and
325 barrels per day 271 barrels per day
During 2000, we participated in three exploratory wells in this area. Two
successful wells, drilled on Block 267 where we have a 60% working interest,
produce through a facility installed for a well drilled in 1999. A fourth
quarter well on Block 263, where we have a 33.3% interest, was unsuccessful.
An exploratory well on each of Block 16, where we have a 40% working interest,
Block 23, where we have a 25% working interest, and Block 72, where we have a
100% working interest, are planned for the second half of 2001.
SOUTH MARSH ISLAND:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
6 27,852 18,926 68% 2.5 mmcf per day and 2.1 mmcf per day and
897 barrels per day 747 barrels per day
In 2000, we participated in one exploratory well on Block 111, where we have a
25% working interest. The well did not find commercial reserves.
During 2001, we expect to participate in three exploratory wells, all of which
we will operate, and one development well. Two exploratory wells on Block 51,
where we have a 60% working interest, and one exploratory well on Block 139,
where we have a 100% working interest, will be drilled at approximately
mid-year. The development well will be drilled on Block 39, where we have a 50%
working interest.
EUGENE ISLAND:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
7 31,250 10,417 33.3% -- --
In 2000, our partner in Block 189 exchanged a 25% working interest for a 4%
overriding royalty, bringing our working interest to 100%. A development well,
which we began drilling early in 2001, if successful, will be produced along
with two successful wells drilled previously from production facilities
installed late in the fourth quarter of 2000. Production is expected to commence
in 2001. In mid-2001, an exploratory well is planned for Block 355 where we have
a 33.3% working interest.
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SOUTH TIMBALIER:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
8 36,561 16,030 43.8% 0.9 mmcf per day 0.7 mmcf per day
In 2000, we participated in two exploratory wells in this area. A successful
natural gas well was drilled on Block 250, where we have a 50% working interest,
and production is expected to commence during 2001. Late in the year, a well
drilled on Block 251, where we have a 50% working interest, did not find
commercial reserves.
WEST CAMERON:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
11 49,410 17,159 34.7% 2.6 mmcf per day 2.2 mmcf per day
In 2000, we participated in nine exploratory wells in this area, seven of which
were successful. In the fourth quarter, a successful well on Block 192, where we
have a 25% working interest, was drilled from an existing production facility
and production began before year-end. We operate Block 300, where we have a 35%
working interest, and where one of two wells drilled was successful. Block 300
commenced production in the fourth quarter. During the second half of the year,
four successful natural gas wells were drilled on Block 370, where we have a 40%
working interest. The Block 370 wells are expected to commence production during
2001. On Block 614, where we have a 25% working interest, a successful natural
gas well was drilled and began producing late in the year along with the 1999
discovery on Block 613. On Block 386, where we have an 80% working interest, a
second quarter well did not find commercial reserves.
During 2001, we expect to participate in four exploratory wells, three of which
we will operate, and three development wells. We will operate an exploratory
well on each of Block 135 and Block 497, where we have 50% working interests. An
exploratory well and two development wells will be drilled on Block 192, where
we have a 25% working interest. A successful exploratory well was drilled in the
first quarter of 2001, and a development well will be drilled in the second half
of 2001, on Block 300, where we have a 35% working interest. The 2001 Block 300
exploratory well is expected to commence production in mid-2000.
MAIN PASS:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
6 21,695 2,453 11.3% 11.3 mmcf per day and 8.8 mmcf per day and
274 barrels per day 210 barrels per day
In 2000, the Main Pass area continued to be one of the most significant
contributors to our natural gas production. One development well on Block 223,
where we have a 10% working interest, is currently planned for 2001.
MISSISSIPPI CANYON:
Blocks Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ------ ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
4 23,040 7,104 30.1% 0.04 mmcf per day 0.04 mmcf per day
We will participate in two exploratory wells in this deep-water area during
2001. The first well is planned for the west half of Block 29, where we have a
27% working interest. It will test the Schellhorn prospect at a planned target
depth of approximately 10,000 to 12,500 feet in a water depth of approximately
2,000 feet. Drilling operations will utilize BP's Pompano subsea template.
Should the well be successful, we expect to be able to complete it for
production in 2001. The other exploratory well, with a planned depth of
approximately 15,000 feet, will be drilled on Block 489, where we will have a
20% working interest. Drilling is expected to commence mid- year in a water
depth of approximately 1,900 feet.
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VERMILION PARISH, LOUISIANA
NORTHEAST WRIGHT:
Gross Acres Net Acres Average Interest Average 2000 Production Average 2000 Production
- ----------- --------- ---------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
3,709 1,852 49.9% 3.9 mmcf per day 2.9 mmcf per day
During 2000, we participated in one successful exploratory well and one
successful development well in the Northeast Wright Field. Both the Langlinais
#1 development well, in which we have a 50% working interest, and the
Delahoussaye #2 exploratory well, in which we have a 1.8% working interest,
commenced production during the summer of 2000.
We expect to begin the drilling of a development well, Trahan #1, during the
second half of 2001.
FOUR CORNERS (PARADOX BASIN) AREA, UTAH
ANETH UNIT:
Gross Acres Net Acres Unit Interest Average 2000 Production Average 2000 Production
- ----------- --------- ------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
18,070 3,066 13.4% 0.15 mmcf per day and 0.13 mmcf per day and
644 barrels per day 560 barrels per day
RATHERFORD UNIT:
Gross Acres Net Acres Unit Interest Average 2000 Production Average 2000 Production
- ----------- --------- ------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
12,910 2,560 21.4% 0.35 mmcf per day and 0.31 mmcf per day and
1,149 barrels per day 1,006 barrels per day
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 project in the
Ratherford Unit is under consideration for late 2001.
NORTH SEA - UNITED KINGDOM SECTOR
Gross Acres Net Acres Unit Interest Average 2000 Production Average 2000 Production
- ----------- --------- ------------- ---------------------------- ----------------------------
(our share, before royalties) (our share, after royalties)
46,553 8,272 17.8% 5.3 mmcf per day and 5.3 mmcf per day and
21 barrels per day 21 barrels per day
All of our UK production comes from our interests in the Galahad Field, where we
have a 17.8% working interest, and in the Mordred Field, where we have a 5.3%
working interest. It is sold under 30-day contracts and in 2000 obtained an
average price of $1.96 per mcf, net of transportation costs. The UK production
is royalty free. Seismic work is planned to evaluate exploration ideas on our
acreage in 2001.
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ACREAGE
The following table summarizes the developed and undeveloped acreage held by us
as at December 31, 2000. Where applicable, interests which are not working
interests (none of which is material) have been converted to working interest
equivalents.
Developed Acres Undeveloped Acres
-------------------- --------------------
Area Gross Net Gross Net
- -------------------------------- ------- ------- ------- -------
United States
Offshore Gulf of Mexico
Louisiana 21,419 6,867 323,090 120,024
Texas 13,942 4,161 356,175 153,056
Texas State 300 22 4,872 1,468
------ ------ ------- -------
Total Offshore Gulf of Mexico 35,661 11,050 684,137 274,548
====== ====== ======= =======
Onshore
Louisiana 2,691 1,346 1,867 930
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 33,872 6,503 7,347 5,090
====== ====== ======= =======
Total United States 69,533 17,553 691,484 279,638
====== ====== ======= =======
United Kingdom
North Sea 7,584 1,348 38,969 6,924
------ ------ ------- -------
Total, all areas 77,117 18,901 730,453 286,562
====== ====== ======= =======
Our developed and undeveloped acreage in all areas covered 807,570 (305,463 net)
acres at December 31, 2000.
The undeveloped acreage, which has a cost to us of approximately $37 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, 2000, 1999 and
1998.
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DRILLING ACTIVITY
The following table summarizes the results of our drilling activities during the
years ended December 31, 2000, 1999 and 1998.
EXPLORATORY WELLS - Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------------ ---------------- ----------------
GROSS NET Gross Net Gross Net
----- ----- ----- ----- ----- -----
Gas 19 7.13 4 2.10 5 1.89
Oil -- -- -- -- 1 0.33
Oil/Gas -- -- 4 2.00 -- --
Evaluating -- -- 1 0.50 -- --
Drilling at end of year 1 0.67 3 0.62 -- --
Abandoned 13 4.80 5 1.45 8 3.45
-- ----- -- ---- -- ----
33 12.60 17 6.67 14 5.67
== ===== == ==== == ====
DEVELOPMENT WELLS - Year ended December 31, 2000 1999 1998
- ---------------------------------------------------------------- --------------- --------------
GROSS NET Gross Net Gross Net
----- ---- ----- ---- ----- ----
Gas 3 1.25 5 0.77 4 0.32
Oil -- -- -- -- 30 6.01
Oil/Gas -- -- 1 0.50 1 0.25
Evaluating -- -- -- -- -- --
Drilling at end of year -- -- -- -- -- --
Abandoned -- -- 1 0.50 -- --
-- ---- -- ---- -- ----
3 1.25 7 1.77 35 6.58
== ==== == ==== == ====
WELLS
Our productive gas and oil wells as at December 31, 2000 are listed in the
following table. Any interests which are not working interests (none of which is
material) have been converted to working interest equivalents.
Gas Wells Oil Wells
---------------- ----------------
Gross Net Gross Net
----- ----- ----- -----
North Dakota -- -- 2 0.47
Pennsylvania 5 0.93 -- --
Utah -- -- 263 43.56
Louisiana 6 2.52 -- --
US Gulf of Mexico 95 20.61 20 6.59
United Kingdom 3 0.41 -- --
--- ----- --- -----
109 24.47 285 50.62
=== ===== === =====
RESERVES
Our US natural gas and oil reserves have been evaluated by Netherland, Sewell &
Associates, Inc. ("NS&A") and we have evaluated our UK reserves which amount to
1.9% (2.3% after royalties) of total equivalent reserves.
For estimates of our proved and proved developed reserves see "Supplementary
Financial Information".
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PRODUCTION VOLUMES, PRICES AND COSTS
Our net production of gas and oil (computed after royalty deductions but before
production taxes) for the years ended December 31, 2000, 1999 and 1998 is listed
below. Also listed are average sales prices and average production costs during
such periods.
Year ended December 31, 2000 1999 1998
- ------------------------------- ---------- ---------- ----------
Total Net Production:
Natural gas (mmcf) 22,871 25,533 24,504
Oil and liquids (mbbls) 1,243 1,428 1,100
Gas equivalent (mmcfe) 30,329 34,103 31,102
Average Daily Net Production:
Natural gas (mmcf) 62.5 70.0 67.1
Oil and liquids (barrels)* 3,396 3,913 3,012
Gas equivalent (mmcfe) 82.9 93.4 85.2
Average Sales Price:
Natural gas (per mcf) $ 3.63 $ 2.02 $ 1.99
Oil and liquids (per barrel) $ 27.72 $ 17.05 $ 11.74
Average Production Cost:
Natural gas (per mcf) $ 0.23 $ 0.21 $ 0.30
Oil and liquids (per barrel) $ 5.17 $ 4.60 $ 5.78
- ---------------
* Oil comprised approximately 82% (1999 - 89%; 1998 - 82%) of our oil and
liquids production.
EMPLOYEES
At December 31, 2000, we had 44 full-time equivalent employees. In addition, we
engage 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 US 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.
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 US Gulf of Mexico (offshore Texas and
Louisiana), we may pursue acquisitions or properties located in other geographic
areas, which would decrease our geographic concentration.
9
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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, 2000, approximately 41% 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 workers' 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.
Compliance with governmental regulations is costly and complex, especially
regulations relating to environmental protection.
Our US 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.
US 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 UK, 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.
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.
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GLOSSARY
The following are defined terms used herein:
BCF means 1,000,000,000 cubic feet.
BCFE means 1,000,000,000 cubic feet of natural gas equivalent.
BLOCK refers to an offshore US Gulf of Mexico natural 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.
GROSS ACRES means the total number of acres in which we own an interest.
GROSS WELLS means the total number of wells in which we own an interest.
LIQUIDS means natural gas liquids.
MBBLS means 1,000 barrels.
MCF means 1,000 cubic feet.
MMCF means 1,000,000 cubic feet.
MMCFE means 1,000,000 cubic feet of natural gas equivalent.
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 barrel of oil and liquids.
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 natural
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 us 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.
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ITEM 2. PROPERTIES
Reference is made to Item 1, "Business", for information concerning our
materially important physical properties. In addition, we lease 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 our security holders during the fourth
quarter of 2000.
EXECUTIVE OFFICERS OF THE REGISTRANT
The following table lists the name and age of each Executive Officer and all
positions and offices held with us 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 17, 2001.
NAME AGE POSITION/OFFICE
- ---- --- ---------------
Stanley A. Milner 72 Director, President and Chief Executive Officer
Stephen C. Hurley 51 Director, Senior Vice President and Chief Operating Officer
Esther S. Ondrack 60 Director, Senior Vice President and Secretary
S. Jay Milner 43 Vice President, Drilling and Production
Ronald J. Stefure 53 Vice President and Controller
Randall P. Boyd 44 Vice President, Investor Relations
With the following exceptions, all of the officers have held their positions as
officers since our incorporation in 1988, such position being his or her
principal occupation. S.C. Hurley joined us in September, 1995 prior to which
time he was the Vice President, Exploration of a US based integrated oil
company. S.J. Milner and R.J. Stefure were appointed officers in June, 1995 and
prior thereto held management positions with us. R.P. Boyd joined us in 1999
prior to which time he was Chief Financial Officer 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.
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PART II
ITEM 5. MARKET FOR THE REGISTRANT'S SECURITIES AND RELATED STOCKHOLDER MATTERS
The principal United States market in which our Common Shares are traded is the
American Stock Exchange. The Common Shares are also traded on the Toronto Stock
Exchange. The high and low prices of our Common Shares (the "Common Shares")
during each quarter since December 31, 1998 are shown below.
Price History of Chieftain
International, Inc. Common Shares
--------------------------------------------------
American Stock Exchange Toronto Stock Exchange
(US dollars) (Cdn. dollars)
---------------------- ----------------------
High Low High Low
-------- -------- -------- --------
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
First quarter 20.38 13.38 27.85 19.50
Second quarter 22.25 17.63 33.20 25.45
Third quarter 22.50 15.88 33.50 23.60
Fourth quarter 27.75 19.31 41.90 29.20
2001
January 27.75 22.25 41.50 33.45
February 25.16 22.02 38.90 34.00
March 1 to March 14 45.50 34.20 29.65 22.00
The Common Shares were held by 116 Shareholders of record on December 31, 2000.
We estimate that investment dealers and other nominees hold Common Shares for
approximately 2,200 beneficial holders.
At the present time it is not our 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 our earnings and our 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.
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ITEM 6. SELECTED CONSOLIDATED FINANCIAL DATA
The selected consolidated financial and operating data for each of the five
years ended December 31, 2000 has been derived from our consolidated financial
statements 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
Year ended December 31, 2000 1999 1998 1997 1996
- -------------------------------------------------- --------- --------- --------- --------- ---------
(in thousands except per share amounts and operating data)
INCOME STATEMENT DATA:
Revenue $ 119,873 $ 76,447 $ 64,391 $ 72,055 $ 63,099
Production costs 14,092 14,320 16,355 13,325 12,220
General and administrative expenses 5,984 4,580 4,796 4,308 3,972
Interest 1,131 2,496 437 -- --
Depletion and amortization(1) 43,770 51,385 42,081 36,951 30,920
Additional depletion(2) -- 16,186 6,244 -- --
Write-down of marketable securities 1,079 -- -- -- --
Income (loss) from operations, before dividends
on preferred shares of a subsidiary 32,290 (6,897) (4,113) 10,160 9,784
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) 27,348 (11,839) (9,055) 5,218 4,842
Net income (loss) per common share:(1)
Basic 1.69 (0.86) (0.67) 0.38 0.37
Diluted 1.64 (0.86) (0.67) 0.38 0.36
Weighted average number of common shares outstanding 16,183 13,701 13,480 13,621 13,065
OTHER DATA:
Cash flow from operations $ 93,631 $ 50,098 $ 37,847 $ 49,473 $ 41,841
Net natural gas and oil capital expenditures $ 102,701 $ 55,021 $ 92,573 $ 69,453 $ 57,673
BALANCE SHEET DATA (at end of period):
Working capital $ 9,962 $ 13,604 $ 2,392 $ 22,676 $ 42,854
Total assets(1) $ 395,460 $ 330,758 $ 318,584 $ 285,125 $ 267,442
Long-term debt $ 20,000 $ 10,000 $ 40,000 $ -- $ --
Shareholders' equity(1) $ 295,146 $ 271,101 $ 234,946 $ 249,466 $ 244,122
OPERATING DATA:
Average Daily Net Production:
Natural gas (mmcf) 62.5 70.0 67.1 64.2 59.8
Oil and liquids (barrels) 3,396 3,913 3,012 2,261 2,005
Natural gas equivalent (mmcfe) 82.9 93.4 85.2 77.8 71.8
Average Sales Price:
Natural gas (per mcf) $ 3.63 $ 2.02 $ 1.99 $ 2.33 $ 2.09
Oil and liquids (per barrel) 27.72 17.05 11.74 18.94 20.99
Average Production Cost:
Natural gas (per mcf) $ 0.23 $ 0.21 $ 0.30 $ 0.27 $ 0.25
Oil and liquids (per barrel) 5.17 4.60 5.78 5.81 6.57
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Notes:
(1) The use of US generally accepted accounting principles results in the
following:
Year ended December 31, 2000 1999 1998 1997 1996
- --------------------------------------------- --------- --------- --------- --------- ---------
(in thousands except per share amounts)
Depletion and amortization $ 32,728 $ 33,762 $ 37,846 $ 33,774 $ 28,539
Additional depletion -- 18,497 95,397 -- --
Net income (loss) applicable to common shares 35,733 (1,967) (63,963) 7,510 6,202
Net income (loss) per common share:
Basic 2.21 (0.14) (4.75) 0.55 0.47
Diluted 2.06 (0.14) (4.75) 0.54 0.46
Total assets 320,783 258,712 238,675 269,178 245,763
Shareholder's equity 183,775 151,345 105,318 174,746 167,110
(2) This amount reflects write-downs in the carrying value of UK and Libyan
gas and oil properties in 1999 and 1998 in accordance with full cost
accounting rules under Canadian GAAP.
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
2000 audited consolidated financial statements. The information contains
forward-looking statements that are subject to risk factors associated with the
oil and gas business. Forward-looking statements typically contain words such as
"anticipate", "believe", "expect", "plan" or similar words suggesting future
outcomes. 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 and currency fluctuations, drilling and production results,
imprecision of reserve estimates, loss of market, industry competition,
environmental risks, political risks and capital restrictions.
Our financial statements and information are reported in US 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 US dollars. For a discussion of the effect
of differences in generally accepted accounting principles in Canada and the US
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 at the rate of one barrel of oil per six thousand cubic feet
of natural gas.
Contents - Management's Discussion and Analysis
- -----------------------------------------------
2000 Overview 15
Production 16
Natural Gas and Oil Marketing 17
Revenue 17
Expenses 18
Net Income (Loss) Applicable to Common Shares 20
Capital Expenditures 21
Finding and Development Costs 22
Reserves 23
Capital Resources and Liquidity 24
Risk Assessment 26
Corporate Governance 27
Outlook and Prospects for Future Growth 28
2000 OVERVIEW
Strong natural gas and oil prices contributed to our record financial results in
2000. Revenues were $145.3 million ($119.9 million after royalties), net income
applicable to common shares was $27.3 million, and cash flow from operations,
after preferred share dividends, was $93.6 million. These amounts compare to
revenues of $92.6 million ($76.4 million after royalties) in 1999 and $77.6
million ($64.4 million after royalties) in 1998, losses applicable to common
shares of $11.8 million in 1999 and $ 9.1 million in 1998 and cash flow from
operations of $50.1 million in 1999 and $37.8 million in 1998.
Basic net income per common share was $1.69 in 2000 compared to losses of $0.86
per share in 1999 and $0.67 per share in 1998.
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Our average natural gas price was $3.63 per mcf in 2000 compared to $2.02 per
mcf in 1999 and $1.99 in 1998. Our combined average crude oil and ngls price was
$27.72 per barrel in 2000 compared to $17.05 in 1999 and $11.74 in 1998.
Net capital spending was $102.9 million in 2000 compared to $55.1 million in
1999 and $92.7 million in 1998. Three year finding and development costs for
proved reserves were $1.17 per mcfe ($1.50 per mcfe after royalties) in 2000
compared to $1.15 per mcfe ($1.45 per mcfe after royalties) in 1999 and $1.51
per mcfe ($1.89 per mcfe after royalties) in 1998.
We increased our proved reserves for the seventh consecutive year, adding 72.4
bcfe (56.2 bcfe after royalties), a reserve replacement rate of 197% (185% after
royalties). Total proved reserves increased to 326 bcfe (266 bcfe after
royalties).
At December 31, 2000, our proved reserves had a present value of future net cash
flows before income taxes, discounted at 10%, of $1.2 billion (1999 - $267
million; 1998 - $153 million). These values reflect the required use of year-end
prices, which at December 31, 2000 were $9.68 per mcf for US natural gas and
$24.60 per barrel of oil.
Production in 2000 averaged 100.5 mmcfe per day (82.9 mmcfe per day after
royalties) compared to 112.9 mmcfe per day (93.4 mmcfe per day after royalties)
in 1999 and 103.2 mmcfe per day (85.2 mmcfe per day after royalties) in 1998.
New production from eight properties was added during 2000, primarily during the
second half of the year. Production commenced from three of these properties in
December. As a result of this additional production, our exit rate at December
31, 2000 was 121.6 mmcfe per day (99.5 mmcfe per day after royalties).
PRODUCTION
Before royalties After royalties
--------------------------------- ---------------------------------
PRODUCTION SUMMARY 2000 1999 1998 2000 1999 1998
- ------------------------------ ------- ------- ------- ------- ------- -------
Natural gas (mmcf per day)
US 71.1 75.5 73.8 57.2 60.2 58.6
UK 5.3 9.8 8.5 5.3 9.8 8.5
------- ------- ------- ------- ------- -------
Total 76.4 85.3 82.3 62.5 70.0 67.1
======= ======= ======= ======= ======== =======
Oil and ngls (barrels per day) 4,022 4,611 3,482 3,396 3,913 3,012
======= ======= ======= ======= ======= =======
Total natural gas equivalent
(mmcfe per day) 100.5 112.9 103.2 82.9 93.4 85.2
======= ======= ======= ======= ======= =======
Total annual equivalent (bcfe) 36.8 41.2 37.7 30.3 34.1 31.1
======= ======= ======= ======= ======= =======
Our average combined natural gas and oil production rate decreased by 11% to
100.5 mmcfe per day (82.9 mmcfe per day after royalties) in 2000 from 112.9
mmcfe per day (93.4 mmcfe per day after royalties) in 1999 and 103.2 mmcfe per
day (85.2 mmcfe per day after royalties) in 1998. Natural gas comprised 76% (75%
after royalties) of our production volumes in both 2000 and 1999, and 80% (79%
after royalties) in 1998. In 2000, natural gas production was 28.0 bcf (22.9 bcf
after royalties) compared to 31.1 bcf (25.5 bcf after royalties) in 1999 and
30.0 bcf (24.5 bcf after royalties) in 1998. In 2000, oil and natural gas
liquids production was 1.5 mmbbls (1.2 mmbbls after royalties) compared to 1.7
mmbbls (1.4 mmbbls after royalties) in 1999 and 1.3 mmbbls (1.1 mmbbls after
royalties) in 1998.
Comparing 2000 and 1999, average production rates decreased 7.4 mmcfe per day
(5.5 mmcfe per day after royalties) in the US and 4.6 mmcfe per day (before and
after royalties) in the UK. During 2000, US production volumes decreased
compared to 1999 as a result of the concentration of production from new
properties in the second half of the year. The majority of the successful wells
drilled in 1999 and scheduled for development in 2000 experienced delays in both
follow-up drilling and facilities design and installation, causing a greater
than expected time lag in production additions. The decline in production was
halted in the second quarter, and production grew through the remainder of the
year. In the UK, where no further exploration and development is currently
planned, production is subject to normal decline.
Comparing 1999 and 1998, production growth was primarily from properties in the
US Gulf of Mexico region which produced for the first time in 1999.
Ninety-two percent of 2000 natural gas production came from our interests in 121
wells in the US Gulf of Mexico region compared to 88% (111 wells) in 1999 and
89% (108 wells) in 1998. Fifty-four percent of our 2000 and 1999 oil and ngls
production came from our holdings in the US Gulf of Mexico region (1998 - 28%).
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NATURAL GAS AND OIL MARKETING
Ninety-six percent of our natural gas reserves are located in the US Gulf of
Mexico region where ready deliverability through numerous large capacity
pipelines and auxiliary feeder pipelines provides flexibility in marketing our
production. Natural gas prices in the US and in the UK are largely determined by
competitive market forces. Most of the natural gas produced by us, as well as
our US Gulf of Mexico region oil and natural gas liquids production, has been
marketed since 1989 by Highland Energy Company, an aggregator for several
natural gas producers.
Our 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 since
1989. Due to its quantity and quality, we have obtained premiums over locally
posted prices for this production.
Market prices of oil and natural gas fluctuate and can materially 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 price risk, we may
enter into forward sales 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, 2000, we had entered into forward sales for the physical
delivery, during the first nine months of 2001, of natural gas production
totaling 7.1 bcf (approximately 15% of our forecast 2001 equivalent volume), at
an average price, net of transportation, of $4.86 per mcf. At the 1999 year-end,
we had entered into forward sales for the physical delivery of 2000 natural gas
production of 6.1 bcf (approximately 17% of our 2000 equivalent volume) at an
average price of $2.49 per mcf. Forward sales of natural gas at December 31,
1998 were immaterial. Also at December 31, 1999, we had entered into oil forward
sales for the physical delivery of 90 mbbls of 2000 production at an average
price of $19.00 per barrel. We had not entered into oil forward sales at either
December 31, 2000 or 1998.
NATURAL GAS
Our composite average natural gas price was $3.63 per mcf in 2000 compared to
$2.02 in 1999 and $1.99 in 1998. The mild North American winter of 1998-1999 had
a downward effect on 1998 US natural gas prices. During the first quarter of
1999, we received an average of $1.54 per mcf for our US natural gas.
Thereafter, prices increased to an average of $2.39 per mcf in the fourth
quarter of 1999. Strong demand for electricity, as well as the demand associated
with replenishing storage for the forthcoming 2000-2001 winter, pulled our US
natural gas price from $2.51 per mcf in the first quarter of 2000 to $3.18 per
mcf and $3.84 per mcf in the second and third quarters, respectively. During the
fourth quarter of 2000, the benchmark New York Mercantile Exchange natural gas
futures experienced significant volatility. This is reflected in the $5.20 per
mcf price realized in the fourth quarter of 2000 for our US production. For the
full year 2000, our average US natural gas price was $3.76 per mcf (1999 - $2.16
per mcf; 1998 - $2.06 per mcf) and our average UK natural gas price was $1.96
per mcf (1999 - $0.96 per mcf; 1998 - $1.40 per mcf).
OIL AND NGLS
Our average oil and ngls price per barrel was $27.72 in 2000 compared to $17.05
in 1999 and $11.74 in 1998. In 1998, the combination of economic problems in
Asia, the mild North American winter and international competition for market
share caused oil prices to fall. Oil prices began to recover when, in the second
quarter of 1999, Organization of Petroleum Exporting Countries' ("OPEC")
production quotas became effective. Starting with the first quarter of 1999, we
experienced seven consecutive quarters of increasing oil and ngls prices before
they leveled out at a price of $30.32 per barrel in the fourth quarter of 2000.
REVENUE
In 2000, an 80% increase in natural gas prices was complemented by a 63%
increase in oil prices. Increased prices more than offset decreased production
with the result that our 2000 production revenue increased 56% from 1999 to
$142.4 million ($117.0 million after royalties). In 1999, growth in our combined
natural gas and oil production volumes was accompanied by a recovery in
commodity prices. As a result, 1999 production revenues increased 22% from 1998
to $91.5 million ($75.4 million after royalties).
NET REVENUE 2000 1999 1998
- ----------------------------------- -------- -------- --------
(in thousands)
Natural gas, after royalties $ 82,577 $ 50,765 $ 48,501
Oil and ngls, after royalties 34,415 24,601 13,114
-------- -------- --------
Production revenue, after royalties 116,992 75,366 61,615
Interest and other revenue 2,881 1,081 2,776
-------- -------- --------
Total net revenue $119,873 $ 76,447 $ 64,391
======== ======== ========
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Natural gas
----------------------------------------- Oil
PRICE/VOLUME VARIANCES, AFTER ROYALTIES US UK Total and ngls Total
- ---------------------------------------- --------- --------- --------- --------- ---------
(in thousands)
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
--------- --------- --------- --------- ---------
PRICE VARIANCE 33,639 1,945 35,584 13,010 48,594
VOLUME VARIANCE (2,197) (1,575) (3,772) (3,196) (6,968)
--------- --------- --------- --------- ---------
2000 PRODUCTION REVENUE, AFTER ROYALTIES $ 78,773 $ 3,804 $ 82,577 $ 34,415 $ 116,992
========= ========= ========= ========= =========
ROYALTIES
Royalties include payments made to federal and state governments, freehold land
owners and other third parties. Our US Gulf of Mexico properties in US federal
waters generally carry a 16-2/3% royalty rate. Some of these properties carry
overriding royalties ranging from 1.1% to 10%. In 2000, the effective average
overriding royalty rate was 1.9% (1999 - 2.2%; 1998 - 2.7%).
Production from the Aneth and Ratherford Units is subject to production taxes
and 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 26%
royalty.
The UK properties carry no royalty obligations. As the UK 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.
ROYALTIES 2000 1999 1998
- ----------------------------- ------- ------- -------
(in thousands except per unit
amounts and percentages)
Natural gas $19,006 $11,699 $11,211
Oil and ngls 6,393 4,442 2,035
------- ------- -------
Total $25,399 $16,141 $13,246
======= ======= =======
Royalties ($ per mcfe) $ 0.69 $ 0.39 $ 0.35
Composite royalty rate 17.8% 17.6% 17.7%
INTEREST AND OTHER REVENUE
Interest and other revenue for 2000 included non-recurring revenue of $1.3
million arising from the Libyan venture which was terminated in the second
quarter of 1999. Under the terms of the concession, the Libyan National Oil
Company ("NOC") reimbursed us and our partners in kind for NOC's share of
production test expenditures. The non-recurring revenue resulted from the
increase in oil prices between the time when production test expenditures were
incurred and the time when reimbursement was effected.
In 1998, interest and other revenue 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.
EXPENSES
PRODUCTION COSTS
Our aggregate production costs in 2000 decreased 2% compared to 1999. However,
because production taxes increased 43% to $2.0 million and production volumes
were lower, our per unit production costs increased. Our production costs in
1999 decreased 12% from 1998, a result of non-recurring items in 1998 and the
termination of the Libyan production test in mid-1999.
Production costs for US Gulf of Mexico region properties were $0.28 per mcfe
($0.35 per mcfe after royalties) in 2000 compared to $0.25 per mcfe ($0.31 per
mcfe after royalties) in 1999 and $0.32 per mcfe ($0.41 per mcfe after
royalties) in 1998. Production costs for the Aneth and Ratherford Units, which
are primarily oil producing properties where secondary and tertiary recovery
methods are being used, were $1.28 per mcfe ($1.47 per mcfe after royalties) in
2000 compared to $1.15 per mcfe ($1.32 per mcfe after royalties) in 1999 and
$0.99 per mcfe ($1.13 per mcfe after royalties) in 1998.
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PRODUCTION COSTS 2000 1999 1998
- -------------------------------------- ------- ------- -------
(in thousands except per unit amounts)
Lifting costs $12,109 $12,929 $14,899
Production taxes 1,983 1,391 1,456
------- ------- -------
Production costs $14,092 $14,320 $16,355
======= ======= =======
Production costs ($ per mcfe)
Before royalty volumes $ 0.38 $ 0.35 $ 0.43
After royalty volumes $ 0.46 $ 0.42 $ 0.53
Production from the Aneth and Ratherford Units and the Northeast Wright and
Chacahoula Fields 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 D. W. Guidry # 1 well in the
Northeast Wright Field, we expect that our production taxes will increase in
2001.
GENERAL AND ADMINISTRATIVE
Our general and administrative costs increased 31% in 2000 compared to 1999 and
decreased 5% in 1999 compared to 1998. Performance-based compensation payments
were higher in 2000 than in 1999 and lower in 1999 than in 1998. Also
contributing to higher costs in 2000 were the hiring of three professional
employees required in support of our larger role as an operator, non-recurring
legal fees and increased office costs.
GENERAL AND ADMINISTRATIVE 2000 1999 1998
- --------------------------------------- -------- -------- --------
(in thousands except per unit
amounts and percentages)
Gross general and administrative $ 12,040 $ 8,527 $ 9,108
Capitalized (6,056) (3,947) (4,312)
-------- -------- --------
General and administrative expense $ 5,984 $ 4,580 $ 4,796
======== ======== ========
General and administrative ($ per mcfe)
Before royalty volumes $ 0.16 $ 0.11 $ 0.13
After royalty volumes $ 0.20 $ 0.13 $ 0.15
Capitalization ratio 50% 46% 47%
INTEREST
Interest expense decreased to $1.1 million in 2000 from $2.5 million in 1999 and
$0.4 million in 1998. The fluctuations were largely due to varying credit
facility utilization. Our weighted average debt outstanding during 2000 was
$15.2 million compared to $42.1 million in 1999 and $12.3 million in 1998. The
effective interest rate on our outstanding debt for 2000 was 7.32% compared to
5.93% in 1999 and 6.19% in 1998. The interest rate on our debt at December 31,
2000 was 7.63%.
DEPLETION AND AMORTIZATION
Depletion and amortization expense in 2000 decreased by $7.6 million, compared
to 1999, of which $5.5 million related to the decrease in production and $2.1
million related to the decrease in the average depletion rate to $1.19 per mcfe
($1.44 per mcfe after royalties). Our lower finding and development costs for
proved reserves in 1999, the oil price induced upward revision in our proved
reserves and the ceiling test write-down of UK properties contributed to the
decrease in our depletion rate in 2000.
Comparing 1999 to 1998, depletion and amortization expense increased $9.3
million, of which $4.0 million related to the increase in production and $5.3
million related to the increase in the average depletion rate to $1.25 per mcfe
($1.51 per mcfe after royalties). The downward revision in our proved reserves
at December 31, 1998, the result of low oil prices at that date, contributed to
the increase in our 1999 depletion rate.
We expect that our depletion rate will be approximately $1.35 per mcfe ($1.64
per mcfe after royalties) in the first quarter of 2001. The depletion rate is
reviewed quarterly.
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22
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 are not
allowed to exceed the value of estimated future net revenues from those proved
reserves (the "ceiling test"). Full cost accounting rules allow, but do not
require, companies to exclude costs of acquiring and evaluating unproved
properties from their depletion cost centers, 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 centers.
The Canadian full cost accounting guideline was revised during 2000 to require
that a ceiling test must be conducted on a quarterly basis. We will
prospectively apply this policy effective with the first quarter of 2001.
In Libya, we and our partners concluded that the multi-year exploration program,
and the production test which commenced in December 1997, were not commercially
viable 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 was then planned.
In respect of the UK properties, we recorded ceiling test impairments at
December 31, 1999 and 1998 due to very low spot market prices for natural gas
and downward reserve revisions, respectively.
TAXES
We have available $230.3 million in US tax pools and $29.1 million in Canadian
tax pools to reduce future taxable income. Should natural gas and oil prices
remain at recent levels, we will be required to pay current income taxes in 2001
as follows:
- - US Alternative Minimum Tax ("AMT"), the amounts of which are, for us,
dependent upon tax loss utilization, and which can be carried forward
and credited against regular tax in future years; and
- - UK corporate income taxes, the amounts of which will depend primarily on
UK natural gas prices, and for which we receive limited double-taxation
relief both in Canada and the US.
During 2000, both the Canadian Federal and Alberta Provincial governments
proposed corporate income tax rate reductions. As our deferred tax asset arises
in Canada, lower corporate income tax rates reduce the future value of the tax
asset. If the proposed rate reductions are all enacted the tax rate for our
Canadian taxable income would fall to 30.12% in 2005, a reduction of about
one-third compared to the 44.62% rate in 2000.
The Canadian Federal rate reductions were substantially enacted in 2000 and we
have recorded the effect, a $1.3 million expense, in 2000. The proposed Alberta
rate reductions did not satisfy the requirements for recognition in 2000. We
expect that the Alberta rate reductions will be substantially enacted in 2001,
at which time we will record their effect, an estimated expense of $1.3 million,
thereby reducing the carrying amount of the deferred tax asset.
NET INCOME (LOSS) APPLICABLE TO COMMON SHARES
In 2000, income before provision for dividends on preferred shares of a
subsidiary increased $39.2 million to $32.3 million compared to 1999. After
provision of $4.9 million for dividends on preferred shares of a subsidiary, net
income applicable to common shares for 2000 was $27.3 million, an improvement of
$39.2 million compared to 1999. The most significant factors responsible for the
improvement were the increased natural gas and oil prices in 2000 and the
non-recurring nature of the 1999 write-off of the Libyan investment.
In 1999, the loss applicable to common shares, after provision of $4.9 million
for dividends on preferred shares of a subsidiary, in 1999 was $11.8 million,
$2.7 million more than in 1998. Improved prices and increased production volumes
realized in 1999 were more than offset by regular and additional depletion
charges.
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CAPITAL EXPENDITURES
Natural resource capital expenditures were $102.7 million in 2000 compared to
$55.0 million in 1999 and $92.6 million in 1998.
CAPITAL EXPENDITURES SUMMARY 2000 1999 1998
- ---------------------------------------- -------- -------- --------
(in thousands)
Property acquisition costs:
US $ 7,789 $ 5,352 $ 7,903
UK 33 28 115
-------- -------- --------
7,822 5,380 8,018
-------- -------- --------
Purchase (sale) of producing properties:
US -- (155) 883
-------- -------- --------
Exploration costs:
US 57,926 28,753 43,317
UK 9 9 72
Other foreign -- 1,531 606
-------- -------- --------
57,935 30,293 43,995
-------- -------- --------
Development costs:
US 36,943 19,542 39,606
UK 1 (39) 71
-------- -------- --------
36,944 19,503 39,677
-------- -------- --------
Total $102,701 $ 55,021 $ 92,573
======== ======== ========
LAND AND LEASE HOLDINGS
We acquired leases in two lease sales during 2000. We participated in high bids
for 14 blocks, 5 as operator, covering 72,890 acres (33,684 net acres). Our
share of the bids on the blocks, all of which have been awarded, was $4.3
million. At December 31, 2000, we had an average working interest of 40% in 152
offshore blocks covering 719,798 gross acres compared to an average working
interest of 40% in 139 blocks covering 661,410 gross acres a year earlier.
DRILLING RESULTS
Drilling in all areas, including extensive development drilling in the Utah oil
producing units in 1998, resulted in success rates of 63% in 2000, 70% in 1999
and 84% in 1998. In 2000, our exploratory drilling success rate in the US Gulf
of Mexico region was 59% compared to 73% in 1999 and 43% in 1998. Including
development wells, our success rate in the region was 63% in 2000 compared to
78% in 1999 and 58% in 1998.
2000 1999 1998
---------------- ---------------- ----------------
DRILLING RESULTS (wells) GROSS NET Gross Net Gross Net
- -------------------------- ----- ----- ----- ----- ----- -----
US - Gulf of Mexico region
Successful 22 8.38 14 5.37 11 2.79
Dry 13 4.80 4 1.70 8 3.45
----- ----- ----- ----- ----- -----
35 13.18 18 7.07 19 6.24
----- ----- ----- ----- ----- -----
US - Other
Successful -- -- -- -- 30 6.01
Dry -- -- -- -- -- --
----- ----- ----- ----- ----- -----
-- -- -- -- 30 6.01
----- ----- ----- ----- ----- -----
Total US
Successful 22 8.38 14 5.37 41 8.80
Dry 13 4.80 4 1.70 8 3.45
----- ----- ----- ----- ----- -----
35 13.18 18 7.07 49 12.25
----- ----- ----- ----- ----- -----
Foreign
Dry -- -- 2 0.25 -- --
----- ----- ----- ----- ----- -----
Total wells drilled
Successful 22 8.38 14 5.37 41 8.80
Dry 13 4.80 6 1.95 8 3.45
----- ----- ----- ----- ----- -----
35 13.18 20 7.32 49 12.25
===== ===== ===== ===== ===== =====
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In addition to the wells described above, at December 31, 2000 we had an
interest in one (0.67 net) well which was drilling. 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 being drilled or evaluated at December
31, 1998.
Three wells were drilled in 2000 on our leases in the US Gulf of Mexico region
at no cost to us; two are natural gas wells and one was being evaluated at
year-end. In 1999, five wells were drilled on our acreage in the region at no
cost to us; one resulted in a natural gas well and four were unsuccessful. In
1998, one successful natural gas well was drilled on our acreage at no cost to
us.
CAPITAL FIELD DEVELOPMENT ACTIVITY
During 2000, design, construction and/or installation of production facilities
and pipelines, which are the components of our capital field development,
totaled $25.9 million and were principally at Eugene Island 189, High Island
A-510/A-531, High Island A-530, Matagorda Island 704, South Timbalier 196,
Vermilion 267, West Cameron 300 and West Cameron 613/614 where production
facilities and, except at Eugene Island 189 and High Island A-510/A-531,
pipelines, were installed. Onshore, facilities were completed for the Langlinais
#1 well in the Northeast Wright Field and at Chacahoula.
FINDING AND DEVELOPMENT COSTS
COST OF RESERVE ADDITIONS
Three year finding and development costs of proved reserves were $1.17 per mcfe
($1.50 per mcfe after royalties). The upward pressure on exploration service and
supply costs is the primary reason for the increase from the 1999 three year
finding and development cost of $1.15 per mcfe ($1.45 per mcfe after royalties).
The 1998 three year finding and development costs were $1.51 per mcfe ($1.89 per
mcfe after royalties).
In calculating finding costs, a number of anomalies between periods are created
by the timing of expenditures and the phase of the exploration and production
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. Finding costs are calculated by dividing
capital expenditures for a period by proved reserve additions (before
production) for the same period. Both a three-year calculation and one year
components are included in the following table.
Cumulative
FINDING COST ANALYSIS 2000 1999 1998 1998 - 2000
- ----------------------------- -------- -------- -------- -----------
(in thousands except unit
and per unit amounts)
Capital expenditures $102,701 $ 55,021 $ 92,573 $250,295
======== ======== ======== ========
Proved, before royalties
Reserve additions (mmcfe) 72,354 80,898 59,999 213,251
Finding costs ($ per mcfe) $ 1.42 $ 0.68 $ 1.54 $ 1.17
Proved, after royalties
Reserve additions (mmcfe) 56,164 65,796 45,381 167,341
Finding costs ($ per mcfe) $ 1.83 $ 0.84 $ 2.04 $ 1.50
RESERVE REPLACEMENT
For the seventh consecutive year, we added more proved reserves than we produced
with total proved reserves increasing to 326 bcfe (266 bcfe after royalties).
The increase of 72.4 bcfe (56.2 bcfe after royalties), before production,
results in a reserve replacement rate of 197% (185% after royalties).
22
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RESERVES
Reports prepared by Netherland, Sewell & Associates, Inc., independent petroleum
engineers, as to our US reserves and internally as to our UK reserves, contain
estimates of our total proved reserves, before and after royalty deductions, as
described below. UK reserves comprise 1.9% (2.3% after royalties) of our total
proved reserves on a bcfe basis.
Before royalties After royalties
-------------------------------------- ---------------------------------------
Natural Gas Oil and ngls Equivalent Oil and ngls Oil and ngls Equivalent
RESERVE RECONCILIATION (mmcf) (mbbls) (mmcfe) (mbbls) (mbbls) (mmcfe)
- ----------------------------------------------- ----------- ------------ ---------- ------------ ------------ ----------
December 31, 1998 159,064 15,227 250,426 129,073 13,134 207,877
-------- -------- -------- -------- -------- --------
Purchase of producing properties -- -- -- -- -- --
Revision of previous estimates (5,786) 1,607 3,857 (4,858) 1,480 4,022
Extensions, discoveries and other additions 64,127 2,152 77,041 51,251 1,753 61,774
Sale of proved properties -- -- -- -- -- --
-------- -------- -------- -------- -------- --------
Net additions 58,341 3,759 80,898 46,393 3,233 65,796
Production (31,119) (1,656) (41,055) (25,533) (1,401) (33,939)
-------- -------- -------- -------- -------- --------
December 31, 1999 186,286 17,330 290,269 149,933 14,966 239,734
-------- -------- -------- -------- -------- --------
PURCHASE OF PRODUCING PROPERTIES 2,741 99 3,335 1,839 66 2,235
REVISION OF PREVIOUS ESTIMATES 31,485 (863) 26,307 23,942 (868) 18,734
EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS 41,280 239 42,712 34,019 196 35,195
SALE OF PROVED PROPERTIES -- -- -- -- -- --
-------- -------- -------- -------- -------- --------
NET ADDITIONS 75,506 (525) 72,354 59,800 (606) 56,164
PRODUCTION (27,956) (1,472) (36,788) (22,871) (1,243) (30,329)
-------- -------- -------- -------- -------- --------
DECEMBER 31, 2000 233,836 15,333 325,835 186,862 13,117 265,569
======== ======== ======== ======== ======== ========
Before royalties After royalties
------------------------------ ------------------------------
PROVED RESERVE LIFE INDEX (years) 2000 1999 1998 2000 1999 1998
- ---------------------------------------------------------- ------ ------ ------ ------ ------ ------
Natural gas 8.4 6.0 5.3 8.2 5.9 5.3
Oil and ngls 10.4 10.5 13.0 10.6 10.7 13.2
Equivalent 8.9 7.1 6.8 8.8 7.1 6.8
Reserve life indexes are calculated by dividing year-end reserve volumes by the
year's production volumes
Before royalties After royalties
--------------------------------- ---------------------------------
RESERVE SUMMARY - NATURAL GAS (mmcf) 2000 1999 1998 2000 1999 1998
- ------------------------------------ ------- ------- ------- ------- ------- -------
Proved reserves:
Developed producing - US 98,625 63,822 70,082 77,699 50,531 55,418
- UK 5,985 6,376 10,108 5,985 6,376 10,108
Developed non-producing - US 37,833 58,986 41,974 30,481 46,024 33,906
Undeveloped - US 91,393 57,102 36,900 72,697 47,002 29,641
------- ------- ------- ------- ------- -------
Total proved reserves 233,836 186,286 159,064 186,862 149,933 129,073
======= ======= ======= ======= ======= =======
Before royalties After royalties
------------------------------ ------------------------------
RESERVE SUMMARY - OIL AND NGLS (mbbls) 2000 1999 1998 2000 1999 1998
- -------------------------------------- ------ ------ ------ ------ ------ ------
Proved reserves:
Developed producing - US 6,893 7,447 5,430 6,002 6,580 4,739
- UK 19 20 27 19 20 27
Developed non-producing - US 1,315 1,633 3,329 1,092 1,347 2,768
Undeveloped - US 7,106 8,230 6,441 6,004 7,019 5,600
------ ------ ------ ------ ------ ------
Total proved reserves 15,333 17,330 15,227 13,117 14,966 13,134
====== ====== ====== ====== ====== ======
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NET FUTURE CAPITAL EXPENDITURES
The reserve reports incorporate estimated future capital expenditures, 89% of
which will be spent over the next five years, that are required to bring proved
undeveloped reserves to production, to maintain proved producing reserves, and
to provide for future abandonment.
NET FUTURE CAPITAL EXPENDITURES 2000 1999 1998
- ------------------------------- -------- -------- --------
(in thousands)
Proved developed $ 24,672 $ 28,120 $ 29,131
Proved undeveloped 97,056 56,753 32,532
-------- -------- --------
Total $121,728 $ 84,873 $ 61,663
======== ======== ========
RESERVE VALUE RECONCILIATION
As required by the Financial Accounting Standards Board Statement 69, our
reserves were estimated using year-end prices which, at December 31, 2000, were
$24.60 per barrel for oil and $9.68 per mcf for US natural gas. The resulting
estimated present values of proved reserves are not considered to be estimates
of fair market value. WE THEREFORE CAUTION AGAINST SIMPLISTIC USE OF THIS
INFORMATION.
ESTIMATED PRESENT VALUE OF PROVED RESERVES 2000 1999 1998
- -------------------------------------------- ---------- ---------- ----------
(in thousands)
Proved developed $ 798,646 $ 193,935 $ 135,867
Proved undeveloped 428,313 72,539 16,641
---------- ---------- ----------
Total PV-10 value before income taxes $1,226,959 $ 266,474 $ 152,508
========== ========== ==========
Standardized measure of discounted estimated
future net cash flows after income taxes $ 849,465 $ 224,533 $ 152,508
========== ========== ==========
PRICES USED IN CALCULATING PROVED RESERVES 2000 1999 1998
- ------------------------------------------ -------- -------- --------
Natural gas (per mcf)
US $ 9.68 $ 2.51 $ 2.15
UK $ 3.65 $ 0.99 $ 1.74
Oil and ngls (per barrel) $ 24.60 $ 20.40 $ 9.72
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.
Cash flow from operations, 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, write-down of marketable securities and
deferred income taxes. We generated cash flow from operations of $93.6 million
in 2000 compared to $50.1 million in 1999 and $37.8 million in 1998. The
variances are primarily a function of fluctuating revenues caused by the
volatility of commodity prices.
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27
Before royalties After royalties
-------------------------------------- --------------------------------------
CASH FLOW FROM OPERATIONS PER UNIT ANALYSIS 2000 1999 1998 2000 1999 1998
- ------------------------------------------- -------- -------- -------- -------- -------- --------
($ per mcfe)
Gross production revenue $ 3.87 $ 2.22 $ 1.99
Royalties (0.69) (0.39) (0.35)
-------- -------- -------- -------- -------- --------
Production revenue, after royalties 3.18 1.83 1.64 $ 3.86 $ 2.21 $ 1.98
Production costs (0.38) (0.35) (0.43) (0.46) (0.42) (0.53)
-------- -------- -------- -------- -------- --------
Gross margin 2.80 1.48 1.21 3.40 1.79 1.45
General and administrative expenses (0.16) (0.11) (0.13) (0.20) (0.13) (0.15)
-------- -------- -------- -------- -------- --------
Gross profit 2.64 1.37 1.08 3.20 1.66 1.30
Interest and other 0.04 (0.03) 0.05 0.05 (0.04) 0.08
Preferred share dividends (0.13) (0.12) (0.13) (0.16) (0.15) (0.16)
-------- -------- -------- -------- -------- --------
Cash flow from operations $ 2.55 $ 1.22 $ 1.00 $ 3.09 $ 1.47 $ 1.22
======== ======== ======== ======== ======== ========
Annual production volume (bcfe) 36.8 41.2 37.7 30.3 34.1 31.1
======== ======== ======== ======== ======== ========
In 1997, a third party sold its interests in producing properties that we
currently operate and since that time neither the vendor nor the purchaser has
reimbursed us on a timely basis for expenditures made by us, as operator, for
their account. Accordingly, we commenced an action in the Louisiana courts
against both the vendor and the purchaser to recover the amounts currently owing
to us, approximately $4.6 million, plus interest and costs. Although the
purchaser filed for Chapter 11 bankruptcy in the first half of 2000, we
currently expect to recover all current and future amounts outstanding and have
therefore made no allowance for doubtful collectability.
Our financing activities in 2000 provided $6.7 million of cash, the net result
of:
- - the drawdown of $10 million of our revolving credit facility;
- - the exercise of employee share options for $1.6 million; and
- - the purchase for cancellation of 228,600 common shares for $4.9 million
under a share repurchase program which expires on August 14, 2001.
Our financing activities in 1999 provided $16.2 million of cash, the net result
of:
- - the sale of 2,875,000 common shares for $46.3 million, net of issue
costs;
- - the net repayment of $30 million of our revolving credit facility; and
- - the purchase for cancellation of 7,500 common shares for $0.1 million
under a share repurchase program which expired on November 1, 1999.
Financing activities during 1998 provided $34.5 million of cash, the net result
of:
- - the drawdown of $40 million of our revolving credit facility;
- - the exercise of employee share options for $0.4 million; and
- - the purchase for cancellation of 294,700 common shares for $5.9 million
under a share repurchase program.
Cash used in natural resource investing activities increased to $102.7 million
for 2000 compared to $55.0 million and $92.6 million for 1999 and 1998,
respectively. The components of our natural resource investing activities are as
follows:
NATURAL RESOURCE INVESTING ACTIVITIES 2000 1999 1998
- ---------------------------------------- -------- -------- --------
(in thousands)
Leasehold and seismic $ 11,195 $ 7,854 $ 10,757
Purchase (sale) of producing properties -- (155) 883
Exploratory drilling 54,562 27,819 41,256
Development drilling 10,995 9,775 16,517
Capital field development 25,949 9,728 23,160
-------- -------- --------
Total $102,701 $ 55,021 $ 92,573
======== ======== ========
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Early in the fourth quarter of 2000, we purchased $5 million of marketable
securities. A $1.1 million write-down of the marketable securities, to a
carrying amount approximating their fair value, was recorded at December 31,
2000. Concurrent with the purchase of these shares, we entered into an agreement
giving us an option to acquire Qatari petroleum and natural gas interests. Early
in 2001, the option expired, unexercised.
Our December 31, 2000 cash balance was $8.7 million (1999 - $19.4 million; 1998
- - $10.6 million). We had outstanding borrowings of $20 million on our revolving
bank credit facility at December 31, 2000 (1999 - $10 million; 1998 - $40
million). During the third quarter of 2000, our revolving bank credit facility
was reduced to $70 million upon the withdrawal from the syndicate of one lender
for reasons unrelated to us. The original amount of the facility was $100
million. With no immediate need for the $30 million difference, we have decided
to not pursue an immediate replacement for the withdrawn syndicate member. The
weighted average interest rate on our borrowings for 2000 was 7.32% (1999 -
5.93%; 1998 - 6.19%).
RISK ASSESSMENT
There are a number of risks facing the oil and gas industry. Some 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, can result in the injury or death of people, and can
damage property and the environment.
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 US 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 rig supply tightens and drilling
costs rise. Drilling may be unsuccessful for many reasons, including the
inherent imprecision of geological interpretation, 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.
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, particularly in high potential prospects. We
also seek to operate projects in which we participate in order to better control
costs and timing. Additionally, we have increasingly relied on advanced
technologies, including 3D seismic analysis, to define geologic risks, thereby
enhancing the results of our drilling efforts.
ENVIRONMENTAL AND SAFETY RISKS
US 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 affect our business. US offshore oil and gas operations are
subject to regulations of the US 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 UK, deposits of substances or articles at sea from offshore oil and gas
operations are subject to the licensing control of the Ministry of Agriculture,
Fisheries and Food.
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.
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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 viable. 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 US have been characterized by periods of
unbalanced supply and 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 will 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. The recovery in prices, which started in
1999, continued through 2000, as did price volatility. Natural gas prices affect
us more than oil prices as natural gas was 76% (75% after royalties) of our 2000
and 1999 energy equivalent production and 80% (79% after royalties) of our 1998
energy equivalent production. Primarily because of lower prices, we recorded
ceiling test write-downs of the UK 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 OPEC.
We could be required to write down the carrying value of our natural gas and oil
properties in the future if natural gas and oil 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 affect our cash flow from operating activities. Once incurred,
these write-downs cannot be reversed at a later date.
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 2000, the directors met at
four regularly scheduled meetings. Two additional meeting 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 and the Board is informed of communication activities.
In addition to the Annual Meeting, the Company participates in conferences and
quarterly conference calls. The Company's transfer agent, CIBC Mellon Trust
Company has a toll-free number (1-800-387-0825) to assist shareholders. 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 site at
www.chieftaininternational.com.
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News releases and other prescribed documents are available on the electronic
databases mandated by the Securities and Exchange Commission known as "EDGAR"
(www.sec.gov/) and by Canadian Securities Authorities known as "SEDAR"
(www.sedar.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.
COMMITTEES OF THE BOARD
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 reviews and recommends to the
Board for its approval the annual financial statements and is also responsible
for reviewing interim unaudited financial statements prior to their release. The
Committee reviews and recommends the annual appointment, terms of engagement and
proposed fees of the independent 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 provides
recommendations to the Board on directors' compensation, appointment and
remuneration of officers and grants of share options. This Committee reviews
compensation and benefits policies, plans and budgets; salaries of certain
non-officer employees; results based compensation; 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 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 and makes recommendations to the Board of
Directors with regard to the Company's retirement plans, related agreements, the
appointment and performance of retirement fund investment managers, and
compliance with the plans' statements of investment policies.
Reserve Committee
The primary function of the Reserve Committee is to review the Company's
externally disclosed oil and natural gas reserve estimates. The Committee
reviews the reports of the independent engineers charged with evaluating the
Company's reserves and also reviews the selection and qualifications of the
independent engineers, the scope of their work and the evaluation procedures
used.
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:
- - Focus on the US Gulf of Mexico region. We focus our operations on the US
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.
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31
- - 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 2001 budget of $105 million for exploration and development
capital expenditures and we expect to use approximately $65 million of
this amount for exploration activities. We are currently drilling or
plan to drill approximately 36 gross exploratory and development wells
in the US Gulf of Mexico region in 2001. Approximately three-quarters of
these will be exploratory wells and the remainder are development wells
to follow up previous discoveries.
- - Manage drilling risks through joint ventures and the use of advanced
technologies. This element of our strategy is described under
Operational Risks on page 26.
- - 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 interests 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:
- - Financial capability and flexibility. At December 31, 2000, $50 million
was available under our unsecured revolving credit facility. We seek to
maintain low levels of debt in order to be able to respond quickly to
drilling or acquisition opportunities.
- - Substantial inventory of drilling projects in the US Gulf of Mexico
region. In the US Gulf of Mexico region, we continue to generate, and
maintain, a two year inventory of 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.
- - Proven exploratory expertise. Our ability to define and participate in
successful prospects in the US Gulf of Mexico is demonstrated by our
three year exploratory drilling success rate in the US Gulf of Mexico
region of 58%.
- - Experienced technical team. Our technical team is comprised of highly
respected industry professionals with an average of more than 20 years
of industry experience. Our exploration success is a direct result of
this team's geologic, geophysical, engineering and technical analysis.
OUR LOOK FORWARD
The fundamentals for US natural gas marketing remain positive. The US Energy
Information Administration ("EIA") reports that US natural gas demand increased
by 3.7% during 2000. For 2001, the EIA forecasts that consumption will be 23.35
trillion cubic feet, an increase of 3% from 2000 levels, even though it expects
wellhead natural gas prices to average $5.22 per mcf. The strong demand for
electricity continues to increase the requirement for natural gas-fired
generation. This, combined with the competing demand for natural gas to refill
storage, should support continued price strength. At year-end 2000, the American
Gas Association reported that storage volumes were 23% lower than the
comparative average for 1996-1998 and 29% lower than at year-end 1999.
On the natural gas supply side, low commodity prices in 1998 and 1999
dramatically reduced drilling. This downturn limited domestic production to 18.6
trillion cubic feet in 2000, an increase of less than 1% from 1999. The EIA is
forecasting that increased drilling activity will support a 5.3% increase in
domestic production in 2001. The active rig count in the US declined by 24% in
1999 to average 625 active rigs compared to 827 in 1998, according to Baker
Hughes. In comparison, the active rig count increased 47% to average 918 in 2000
and had increased to 1,128 by the third week of January 2001. This increased
level of activity reflects the recovery in commodity prices.
The experience of 2000 confirmed the earlier conclusion of many industry
observers that the natural gas supply and demand equation was tightening up in
the US. The balancing of natural gas supply and demand will continue to 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, during periods of
both low and high prices. Our current 2001 exploration and development budget,
which we plan to fund from operating cash flow, is expected to increase 2001
production volumes to 125 mmcfe per day, 24% above 2000 levels. In 2001, we will
benefit from the commencement of production from a number of new offshore
facilities.
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Our capital expenditures can vary significantly with exploration results,
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 2001 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 2001 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 US Gulf of Mexico region remains optimistic. We
believe that the control on oil prices that can be exerted by OPEC has been
amply demonstrated over the past few years. Should OPEC continue to adhere to
its production quotas, we expect that WTI prices well in excess of $20 per
barrel will continue to prevail.
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
The following consolidated financial statements of Chieftain International, Inc.
and the management's and auditors' reports thereon are included herein. The
financial statements are in US dollars.
Management's Report
Auditors' Report
Consolidated Balance Sheet as at December 31, 2000 and 1999
Consolidated Statement of Income (Loss) and Deficit for the years ended
December 31, 2000, 1999 and 1998
Consolidated Statement of Cash Flows for the years ended December 31,
2000, 1999 and 1998
Notes to Consolidated Financial Statements
Supplementary Financial Information (Unaudited)
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MANAGEMENT'S REPORT
The accompanying consolidated financial statements and all information in this
annual report are the responsibility of management. The financial statements
have been prepared by management in accordance with Canadian generally accepted
accounting principles. The financial information contained elsewhere in this
annual report is consistent with the consolidated financial statements in all
material respects.
The Company maintains accounting systems and internal controls to provide
reasonable assurance that its financial information is reliable and accurate,
and that its assets are adequately safeguarded. Where necessary, management has
made informed judgments and estimates in the preparation of the financial
statements.
Independent auditors, appointed by the shareholders, have examined the
consolidated financial statements. The Audit Committee of the Board of Directors
meets periodically with management and the independent auditors to review audit,
internal control, accounting policy and financial reporting matters.
The annual consolidated financial statements are approved by the Board of
Directors on the recommendation of the Audit Committee.
/s/ S. A. Milner /s/ R. J. Stefure
- ------------------------------------- ----------------------------------------
S.A. Milner R.J. Stefure
President and Chief Executive Officer Vice President and Controller
February 1, 2001
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AUDITORS' REPORT
We have audited the consolidated balance sheets of Chieftain International, Inc.
as at December 31, 2000 and 1999 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, 2000. 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 and United States 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, 2000
and 1999 and the results of its operations and its cash flows for each of the
years in the three-year period ended December 31, 2000 in accordance with
Canadian generally accepted accounting principles.
/s/ PricewaterhouseCoopers LLP
- ----------------------------------------
Chartered Accountants
Edmonton, Alberta
February 1, 2001
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CONSOLIDATED BALANCE SHEET
Chieftain International, Inc. and Subsidiary Companies
(Full Cost Method of Accounting) as at December 31, 2000 1999
- --------------------------------------------------------- --------- ---------
(US$ in thousands)
ASSETS
Current assets:
Cash and short-term deposits $ 8,718 $ 19,368
Accounts receivable 32,926 18,855
Other 754 750
Marketable securities 3,913 --
--------- ---------
46,311 38,973
--------- ---------
Capital assets, at cost:
Natural resource properties including exploration and
development thereon (Note 2) 710,102 607,401
Other capital assets 2,241 2,157
--------- ---------
712,343 609,558
Less: Accumulated depletion and amortization 374,940 332,409
--------- ---------
337,403 277,149
Deferred income taxes 11,746 14,636
--------- ---------
$ 395,460 $ 330,758
========= =========
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued $ 36,349 $ 25,369
Long-term debt (Note 3) 20,000 10,000
Abandonment cost accrual 9,728 8,595
Deferred income taxes 34,237 15,693
Shareholders' equity:
Preferred shares of a subsidiary (Note 4) 63,403 63,403
Share capital (Note 5) --
Authorized -- an unlimited number of --
First preferred shares
Second preferred shares
Common shares
Issued --
16,100,827 common shares (1999 -- 16,224,059) 235,295 237,076
Contributed surplus -- 26
Deficit (3,552) (29,404)
--------- ---------
295,146 271,101
--------- ---------
$ 395,460 $ 330,758
========= =========
Approved by the Board:
/s/ S. A. Milner /s/ L. G. Munin
- ----------------------------------- ----------------------------------------
S.A. Milner, Director L.G. Munin, Director
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CONSOLIDATED STATEMENT OF INCOME (LOSS) AND DEFICIT
Chieftain International, Inc. and Subsidiary Companies
Year ended December 31, 2000 1999 1998
- ----------------------------------------------------- --------- --------- ---------
(US$ in thousands except per share amounts)
Production revenue $ 142,391 $ 91,507 $ 74,861
Less: royalties 25,399 16,141 13,246
--------- --------- ---------
Production revenue, after royalties 116,992 75,366 61,615
Interest and other revenue (Note 6) 2,881 1,081 2,776
--------- --------- ---------
119,873 76,447 64,391
--------- --------- ---------
Production costs 14,092 14,320 16,355
General and administrative expenses 5,984 4,580 4,796
Interest 1,131 2,496 437
Depletion and amortization 43,770 51,385 42,081
Additional depletion -- 16,186 6,244
Write-down of marketable securities 1,079 -- --
--------- --------- ---------
66,056 88,967 69,913
--------- --------- ---------
Income (loss) before income taxes and
dividends on preferred shares of a subsidiary 53,817 (12,520) (5,522)
Income taxes (Note 7):
Current 93 11 14
Deferred 21,434 (5,634) (1,423)
--------- --------- ---------
21,527 (5,623) (1,409)
--------- --------- ---------
Income (loss) before dividends on preferred
shares of a subsidiary 32,290 (6,897) (4,113)
Dividends paid on preferred shares of a subsidiary 4,942 4,942 4,942
--------- --------- ---------
Net income (loss) applicable to common shares 27,348 (11,839) (9,055)
Deficit, beginning of year (29,404) (17,565) (7,089)
Cost of purchase of common shares in excess
of stated capital (Note 5) (1,496) -- (1,421)
--------- --------- ---------
Deficit, end of year $ (3,552) $ (29,404) $ (17,565)
========= ========= =========
Net income (loss) per common share (Note 8):
Basic $ 1.69 $ (0.86) $ (0.67)
--------- --------- ---------
Diluted (Note 1 (i)) $ 1.64 $ (0.86) $ (0.67)
========= ========= =========
Weighted average number of common shares outstanding
(in thousands):
Basic 16,183 13,701 13,480
========= ========= =========
Diluted 19,745 13,701 13,480
========= ========= =========
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CONSOLIDATED STATEMENT OF CASH FLOWS
Chieftain International, Inc. and Subsidiary Companies
Year ended December 31, 2000 1999 1998
- --------------------------------------------------------- --------- --------- ---------
(US$ in thousands)
Operating activities:
Net income (loss) applicable to common shares $ 27,348 $ (11,839) $ (9,055)
Items not requiring a current cash outlay:
Depletion and amortization 43,770 67,571 48,325
Write-down of marketable securities 1,079 -- --
Deferred income taxes 21,434 (5,634) (1,423)
--------- --------- ---------
Cash flow from operations 93,631 50,098 37,847
Change in non-cash operating working capital (Note 9)
Accounts receivable (14,071) (4,825) (3,168)
Other current assets (4) (468) 324
Accounts payable and accrued 2,897 3,830 164
--------- --------- ---------
82,453 48,635 35,167
--------- --------- ---------
Financing activities:
Issue of common shares 1,560 50,321 437
Purchase of common shares for cancellation (4,863) (80) (5,902)
Increase in long-term debt 10,000 5,000 40,000
Decrease in long-term debt -- (35,000) --
Financing costs -- (4,058) --
--------- --------- ---------
6,697 16,183 34,535
--------- --------- ---------
Net cash flows from operating and financing activities 89,150 64,818 69,702
--------- --------- ---------
Investing activities:
Lease acquisition, exploration and development costs (102,701) (55,176) (91,690)
Sale of producing properties -- 155 --
Purchase of producing gas and oil properties -- -- (883)
--------- --------- ---------
(102,701) (55,021) (92,573)
Purchase of other capital assets and other (182) (48) (93)
Change in investing accounts payable and accrued 8,083 (994) 6,652
Investment in marketable securities (5,000) -- --
--------- --------- ---------
(99,800) (56,063) (86,014)
--------- --------- ---------
Change in cash and short-term deposits (10,650) 8,755 (16,312)
Cash and short-term deposits, beginning of year 19,368 10,613 26,925
--------- --------- ---------
Cash and short-term deposits, end of year $ 8,718 $ 19,368 $ 10,613
========= ========= =========
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(DECEMBER 31, 2000, 1999 AND 1998)
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES *
We are engaged in natural gas and oil exploration, development and production
primarily in the United States ("US") and also in the United Kingdom ("UK")
sector of the North Sea. The Consolidated Financial Statements are expressed in
US currency as most of our assets and operations are denominated in US dollars.
1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) ACCOUNTING PRINCIPLES
Our financial statements are prepared in conformity with
Canadian generally accepted accounting principles. The
preparation of financial statements in conformity with
generally accepted accounting principles requires
management to make informed judgements and estimates.
Actual results may differ from those estimates. Material
differences between Canadian and US accounting
principles that affect us 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 our
accounts and the accounts of our subsidiary companies,
all of which are wholly-owned except for Chieftain
International Funding Corp., a US subsidiary which in
1992 issued 2,726,700 preferred shares to the public.
These preferred shares are convertible into common
shares of Chieftain International, Inc. See Note 4.
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) MARKETABLE SECURITIES
Our interest in marketable securities is accounted for
by the cost method. Application of the cost method
results in the investment initially being recorded at
cost and earnings therefrom are recognized only to the
extent that dividends are received or are receivable.
The amount of the investment is reduced by any dividends
received in excess of our pro rata share of
post-acquisition income.
(d) FOREIGN CURRENCY TRANSLATION
Canadian and other foreign currency amounts have been
translated into US currency on the following bases:
monetary assets and liabilities at the year-end rates of
exchange; non-monetary assets and liabilities at
historical exchange rates; and revenue and expenses at
monthly average exchange rates during the year.
Translation gains or losses are reflected in the
Consolidated Statement of Income (Loss) and Deficit.
(e) FINANCIAL ASSETS AND LIABILITIES
Our financial instruments that are included in the
Consolidated Balance Sheet are comprised of cash and
short-term deposits, accounts receivable, marketable
securities, all current liabilities and long-term debt.
In each case, their fair value approximates the carrying
amount reflecting 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. Marketable securities
are subject to currency, market and liquidity risks: the
shares trade in Canadian currency, share prices are
volatile and timely divestiture may not be possible at
share prices approximating fair value. Long-term debt is
subject to normal floating interest rate risk.
- -----------
* Unless the context indicates another meaning, the terms "we", "us" and "our"
refer to Chieftain International, Inc., a company organized under the laws of
the Province of Alberta, Canada, and its subsidiaries.
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(f) NATURAL RESOURCE PROPERTIES
We account for natural gas and oil properties in
accordance with the Canadian guideline 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, using the
ratio of 1 barrel of oil = 6,000 cubic feet of natural
gas. 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. See Note 2.
(g) LAND, BUILDINGS AND OTHER EQUIPMENT
Amortization is provided as follows:
Rate per
annum Method
------------- -------------
Buildings 5% Straight-line
Furniture, office equipment and leasehold improvements 10 - 20% Straight-line
Expenditures for renewals and betterments which
materially increase the estimated useful life of
buildings and equipment are capitalized; expenditures
for repairs and maintenance are charged to income. Costs
and accumulated amortization of assets retired or sold
are removed from the asset and related accumulated
amortization accounts; losses and gains thereon are
included in the Consolidated Statement of Income (Loss)
and Deficit as depletion and amortization.
(h) INCOME TAXES
Income taxes are recorded using the liability method of
accounting. Applying this method, deferred income taxes
are recognized, using applicable, enacted, or
substantively enacted, income tax rates, for future
income tax consequences attributable to differences
between the financial statement carrying values and
their respective income tax bases. The effect of a
change in tax rates on deferred income tax assets and
liabilities 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.
(i) PER SHARE AMOUNTS
Effective with the fourth quarter of 2000, we
retroactively adopted revised per share calculation
methods which are required to be adopted no later than
2001 under Canadian generally accepted accounting
principles. Consistent with the revision, we now include
share options in diluted per share amounts, where
dilutive, assuming that the share options are exercised
using the treasury stock method.
The retroactive application of this policy had the
effects of increasing our diluted income per common
share by $0.05 in 2000. All relevant amounts for prior
periods have been restated for consistency and
comparability.
2. NATURAL RESOURCE PROPERTIES
The following weighted average December 31 field prices were used in the
determination of our US future net revenues for purposes of the ceiling
test:
As at December 31, 2000 1999 1998
- --------------------------------------------- -------- -------- --------
Oil and ngls (per barrel) $ 24.60 $ 20.40 $ 12.27
Natural gas (per thousand cubic feet ("mcf")) $ 9.68 $ 2.51 $ 2.15
A field price of $3.65 (1999 - $0.99; 1998 - $1.74) per mcf was used in
the determination of our UK future net revenues for purposes of the
ceiling test.
There is uncertainty as to the prices at which natural gas and oil
produced by us may be sold in the future.
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The application of the ceiling test to US property carrying costs at
December 31, 1998, using the $12.27 per barrel average oil and natural
gas liquids ("ngls") price received by us during the year and the $2.15
per mcf December 31, 1998 natural gas price, required no write-down. At
December 31, 1998, a write-down of $10,614,000, after providing for tax
recoveries of $5,842,000, would have been required had prices as of that
date, $2.15 per mcf for natural gas and $9.72 per barrel for oil and
ngls, been used. At December 31, 1999 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 of
that date. 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 UK properties.
Depletion rates per physical unit of US production are as follows:
Natural Gas Oil and ngls
(per mcf) (per barrel)
----------- ------------
Year ended December 31, 1998 $1.16 $6.97
Year ended December 31, 1999 $1.25 $7.50
YEAR ENDED DECEMBER 31, 2000 $1.23 $7.36
The depletion rate per physical unit of UK natural gas production was
$0.51 per mcf for the year ended December 31, 2000 (1999 - $1.24; 1998 -
$0.81).
At December 31, 1998, Libyan property carrying costs of $9.9 million
were excluded from depletion calculations pending evaluation.
General and administrative costs relating directly to lease acquisition,
exploration and development activities have been capitalized as follows:
Year ended December 31, 2000 1999 1998
- ----------------------- ------ ------ ------
(in thousands)
Lease acquisition $1,849 $ 765 $ 857
Exploration 2,660 1,581 1,740
Development 1,547 1,601 1,715
------ ------ ------
$6,056 $3,947 $4,312
====== ====== ======
3. REVOLVING CREDIT AND LONG-TERM DEBT
In 1997 we arranged an unsecured revolving credit facility with a
syndicate of banks. The facility, in the amount of $70 million (1999
- $100 million)or the Canadian dollar equivalent, is fully revolving
for 364 day periods with extensions at the option of the lenders upon
our request. 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 rate, US base rate, Bankers'
Acceptance rate or LIBOR plus applicable margins. Certain financial
tests are required to be met quarterly. Under this facility, $20
million was utilized at December 31, 2000 (1999 - $10 million),
carrying a weighted average interest rate of 7.63% (1999 - 7.00%).
4. 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 US. The preferred shares are
redeemable, at the option of Funding, at $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
41
5. SHARE CAPITAL
(a) COMMON SHARES
Year ended December 31, 2000 1999 1998
- ----------------------- -------------------------- ------------------------- -----------------------
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 16,224,059 $237,076 13,355,891 $189,108 13,622,375 $192,845
Share options exercised 105,368 1,560 668 9 28,216 437
Shares purchased and cancelled* (228,600) (3,341) (7,500) (106) (294,700) (4,174)
Shares issued for cash** -- -- 2,875,000 48,065 -- --
----------- -------- ---------- -------- ---------- --------
Balance, end of year 16,100,827 $235,295 16,224,059 $237,076 13,355,891 $189,108
=========== ======== ========== ======== ========== ========
* 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, we sold 2,875,000 common shares by way of
a public offering in the US at $17.50 per share.
(b) COMMON SHARES RESERVED
At December 31, 2000, 1,394,632 (1999 - 1,130,207; 1998
- 1,130,875) of our authorized but unissued common
shares were reserved for issuance under the Share Option
Plan. See Note 5(d).
We have reserved 3,408,375 common shares for issuance
pursuant to the conversion provisions of the preferred
shares of a subsidiary. See Note 4.
(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.
(d) SHARE OPTION PLAN (THE "PLAN")
The Plan provides for the granting of options to
employees, directors and consultants to purchase our
common shares. 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, 2000 options
were outstanding to 60 participants in the Plan.
The following is a summary of activity related to the
Plan for the years ended December 31, 2000, 1999 and
1998.
Year ended December 31, 2000 1999 1998
- ----------------------- -------------------------- -------------------------- --------------------------
WEIGHTED WEIGHTED WEIGHTED
NUMBER AVERAGE NUMBER AVERAGE NUMBER AVERAGE
OF OPTION OF OPTION OF OPTION
SHARES PRICE SHARES PRICE SHARES PRICE
----------- -------- ----------- -------- ----------- --------
Outstanding at beginning of year 1,119,189 $16.58 1,083,857 $16.74 1,057,673 $ 16.47
Granted 233,000 20.26 180,000 13.44 65,000 21.08
Exercised (105,368) 14.81 (668) 13.63 (28,216) 15.49
Forfeited (2,000) 21.32 (4,000) 22.54 (10,600) 20.07
Expired -- -- (140,000) 13.61 -- --
----------- -------- ----------- -------- ----------- --------
Outstanding at end of year 1,244,821 17.41 1,119,189 16.58 1,083,857 16.74
=========== ======== =========== ======== =========== ========
Options exercisable at year=end 870,155 824,521 869,858
=========== =========== ===========
39
42
The following table summarizes information about options outstanding
at December 31, 2000.
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
- ---------------- ------------- ---------------- ------------- ------------- -------------
$ 11.43 -- 15.38 620,287 5.1 years $14.18 510,287 $ 14.43
18.00 -- 20.88 361,334 7.2 years 19.81 115,001 19.21
20.94 -- 23.75 263,200 6.6 years 21.74 244,867 21.69
--------- --------
1,244,821 870,155
========= ========
6. INTEREST AND OTHER REVENUE
Interest and other revenue for 2000 included non-recurring revenue of
$1.3 million arising from the Libyan venture which was terminated in
the second quarter of 1999. Under the terms of the concession, the
Libyan National Oil Company ("NOC") reimbursed us and our partners in
kind for NOC's share of production test expenditures. The
non-recurring revenue resulted from the increase in oil prices
between the time when production test expenditures were incurred and
the time when reimbursement was effected.
In 1998, interest and other revenue 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
of $1,129,000, $282,000 and $189,000, respectively.
7. INCOME TAXES
Income tax expense is made up of the following components:
Year ended December 31, 2000 1999 1998
- ----------------------- ---------------------- ----------------------- -----------------------
CANADA US Canada US Canada US
-------- -------- -------- -------- -------- --------
(in thousands)
Income (loss) before income taxes and
dividends on preferred shares of a subsidiary $ 1,043 $ 52,774 $(18,254) $ 5,734 $ (6,829) $ 1,307
======== ======== ======== ======== ======== ========
Income taxes (recovery)
Current $ -- $ 93 $ 11 $ -- $ 14 $ --
Deferred 2,890 18,544 (7,643) 2,009 (1,740) 317
-------- -------- -------- -------- -------- --------
$ 2,890 $ 18,637 $ (7,632) $ 2,009 $ (1,726) $ 317
======== ======== ======== ======== ======== ========
40
43
The actual tax rate differs from the expected tax rate for the
following reasons:
Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------ -------- -------- --------
(in thousands)
Tax at statutory rate of 44.62%
(Combined Canadian Federal and provincial rate) $ 24,013 $ (5,587) $ (2,465)
Add (deduct) the effect of:
Lower income tax rate on earnings of US subsidiaries (4,766) (496) (81)
Canadian income tax on exchange loss
which is eliminated upon consolidation 426 909 631
Reduction in value of deferred tax assets resulting from
reduction in future Canadian rate 1,318 -- --
Other 536 (449) 506
-------- -------- --------
Tax at effective rate $ 21,527 $ (5,623) $ (1,409)
======== ======== ========
Effective tax rate 40.0 % 44.9 % 25.5 %
======== ======== ========
Temporary differences comprising the deferred tax assets
(liabilities) are as follows:
2000 1999
------------------------------------- -------------------------------------
As at December 31, CANADA US TOTAL Canada US Total
- ------------------------------------- -------- -------- -------- -------- -------- --------
(in thousands)
Deferred tax assets
Depletion and amortization $ 8,588 $ -- $ 8,588 $ 10,679 $ -- $ 10,679
Financing costs 1,254 -- 1,254 2,005 -- 2,005
Loss carryforwards 681 26,656 27,337 1,461 26,645 28,106
Other 1,223 14 1,237 491 4 495
-------- -------- -------- -------- -------- --------
11,746 26,670 38,416 14,636 26,649 41,285
-------- -------- -------- -------- -------- --------
Deferred tax liabilities
Depletion and amortization -- (60,907) (60,907) -- (42,342) (42,342)
-------- -------- -------- -------- -------- --------
Net deferred tax assets (liabilities) $ 11,746 $(34,237) $(22,491) $ 14,636 $(15,693) $ (1,057)
======== ======== ======== ======== ======== ========
At December 31, 2000 our net operating tax losses carried forward are
summarized in the following table. We are of the opinion that the tax
benefit of these tax losses will be realized.
Year of expiry Canada US
- -------------- ------- -------
(in thousands)
2003 $ 1,492 $ --
2005 239 6,119
2007 -- 2,835
2009 -- 6,139
2010 -- 18,007
2011 -- 3,773
2012 -- 2,090
2018 -- 16,088
2019 -- 19,221
2020 -- 814
------- -------
Total $ 1,731 $75,086
======= =======
41
44
8. PER SHARE AMOUNTS
Basic net income (loss) per common share is calculated by dividing
net income (loss) applicable to common shares by the weighted average
number of common shares outstanding during the year. Diluted income
(loss) per common share is calculated to give effect to share options
and shares issuable on conversion of preferred shares.
Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------ -------- -------- --------
(in thousands)
Net income (loss) applicable to common shares $ 27,348 $(11,839) $ (9,055)
Dividends paid on preferred shares of a subsidiary 4,942 -- --
-------- -------- --------
Diluted net income (loss) $ 32,290 $(11,839) $ (9,055)
======== ======== ========
Year ended December 31, 2000 1999 1998
-------- -------- --------
(shares in thousands)
Basic weighted average number of common shares outstanding 16,183 13,701 13,480
Effect of dilutive securities
Exercise of share options 154 -- --
Conversion of preferred shares 3,408 -- --
-------- -------- --------
Diluted weighted average number of common shares outstanding 19,745 13,701 13,480
======== ======== ========
9. SUPPLEMENTAL CASH FLOW INFORMATION
Net cash outflows for (inflows from) income taxes were $211,000,
$(12,000) and $14,000 for the years 2000, 1999 and 1998,
respectively. Cash outflows for long-term debt interest were
$1,032,000, $2,601,000 and $628,000 in 2000, 1999 and 1998,
respectively.
10. PENSION COSTS AND OBLIGATIONS
We contributed $178,416, $145,418 and $145,300 for 2000, 1999 and
1998, respectively, to defined contribution pension plans. Under a
supplementary defined contribution pension plan established in 1991,
costs of $209,484, $216,401 and $198,294 for 2000, 1999 and 1998,
respectively, and the related liability are recorded in the accounts.
We have established no other post-employment benefit plans.
11. SEGMENTED INFORMATION
We have a single reportable segment with activities as explained in
the preamble to the Notes. Production revenue, after royalties, all
of which arises from external customers, is attributed to the country
in which the underlying production occurred. Most of the US natural
gas, oil and ngls we produce are marketed by a single aggregator.
Production revenues, after royalties, associated with the aggregator
were $90,842,000 (1999 - $59,665,000; 1998 - $46,340,000). As at
December 31, 2000, we had entered into natural gas forward contracts
with the aggregator. The forward contracts are for the physical
delivery of, during the first nine months of the following year,
natural gas volumes totalling 7.1 billion cubic feet ("bcf") (1999 -
6.1 bcf), at an average price of $4.86 per mcf (1999 - $2.49 per
mcf). Our 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, after royalties, associated
with sales to the regional refiner were $14,188,000 (1999 -
$9,710,000; 1998 - $8,207,000). At December 31, 1999, we had entered
into an oil forward contract with the regional refiner for the
physical delivery, in 2000, of oil volumes of 90,000 barrels at an
average price of $19.00 per barrel. We believe that alternative
marketing arrangements would be readily available for our natural
gas, oil and ngls.
42
45
2000 1999 1998
-------- -------- --------
(in thousands)
Production revenue, after royalties
US $113,005 $ 71,487 $ 56,199
UK 3,987 3,582 4,411
Libya -- 297 1,005
-------- -------- --------
Total production revenue, after royalties 116,992 75,366 61,615
Interest and other revenue 2,881 1,081 2,776
-------- -------- --------
Total revenue $119,873 $ 76,447 $ 64,391
======== ======== ========
Net capital assets
US $336,114 $274,904 $267,020
UK 1,013 1,994 11,337
Canada and other 276 251 285
Libya -- -- 9,835
-------- -------- --------
$337,403 $277,149 $288,477
======== ======== ========
12. US ACCOUNTING PRINCIPLES
(a) FULL COST ACCOUNTING
US full cost accounting rules differ materially from the
Canadian full cost accounting guidelines we follow. In
determining the limitation on carrying values, US rules
require the discounting of future net revenues at 10%,
and Canadian guidelines require the use of undiscounted
future net revenues and the deduction of estimated
future administrative and financing costs. During 1999
and 1998, impairment adjustments would have been
required under US accounting rules. The quarterly test
required by US accounting rules, using a March 31, 1999
UK natural gas price of $0.84 per mcf to determine
future net revenues, would have resulted in a write-down
of UK property carrying costs at March 31, 1999 of $7.1
million and, after providing for tax recoveries of $3.1
million, a net charge to operations of $4.0 million.
Using December 31, 1998 US natural gas and oil prices of
$2.15 per mcf and $9.72 per barrel to determine future
net revenues would have resulted in a write-down of US
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. Using June 30, 1998 US prices of $2.09 per mcf and
$12.40 per barrel to determine future net revenues would
have resulted in a write-down of US property carrying
costs of $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
would result in reduced depletion expense, under US
rules, for subsequent periods. In 1999, under Canadian
guidelines the test resulted in a write-down of UK
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 US accounting rules.
43
46
(b) EFFECT ON EARNINGS
The effect on consolidated earnings of the differences
between Canadian and US accounting principles is
summarized as follows:
Year ended December 31, 2000 1999 1998
- ------------------------------------------------------------------ -------- -------- --------
(in thousands except per share amounts)
Net income (loss) applicable to
common shares, as reported $ 27,348 $(11,839) $ (9,055)
Additional depletion difference -- (2,311) (89,153)
-------- -------- --------
27,348 (14,150) (98,208)
-------- -------- --------
Reduction in depletion expense 11,042 17,623 4,235
Reduction (increase) in deferred tax provision (2,657) (5,440) 30,010
-------- -------- --------
Net income (loss) applicable to common
shares under US accounting principles $ 35,733 $ (1,967) $(63,963)
======== ======== ========
Net income (loss) per common share under US accounting principles:
Basic $ 2.21 $ (0.14) $ (4.75)
======== ======== ========
Diluted $ 2.06 $ (0.14) $ (4.75)
======== ======== ========
Diluted common shares outstanding 19,745 13,701 13,480
======== ======== ========
(c) EFFECT ON BALANCE SHEET
The effect on the Consolidated Balance Sheet of the
differences between Canadian and US accounting
principles is as follows:
As at December 31, 2000 1999
- ------------------ -------------------------- --------------------------
UNDER US Under US
AS ACCOUNTING As Accounting
REPORTED PRINCIPLES Reported Principles
--------- ---------- --------- ----------
(in thousands)
Net capital assets $ 337,403 $ 260,797 $ 277,149 $ 189,501
Deferred tax -- asset 11,746 13,675 14,636 30,238
Deferred tax -- liability 34,237 7,528 15,693 --
Deficit (3,552) (51,520) (29,404) (85,757)
Additionally for US reporting purposes, the preferred
shares shown as shareholders' equity in these
consolidated financial statements would be shown outside
the equity section.
(d) INCOME TAX DISCLOSURES
Provisions for deferred income taxes are as follows:
Year ended December 31, 2000 1999 1998
- ----------------------- ---------------------- ----------------------- -----------------------
CANADA US Canada US Canada US
-------- -------- -------- -------- -------- --------
(in thousands)
Income (loss) before income taxes and
dividends on preferred shares of a subsidiary $ 1,648 $ 63,211 $(17,492) $ 20,284 $ (5,002) $(85,440)
======== ======== ======== ======== ======== ========
Provision for deferred income taxes $ 1,842 $ 22,249 $ (7,248) $ 7,054 $ (921) $(30,512)
======== ======== ======== ======== ======== ========
44
47
The provision for income taxes differs from the amount
of income tax determined by applying the Canadian
statutory rate to pre-tax income before dividends paid
on preferred shares of a subsidiary, as a result of the
following:
Year ended December 31, 2000 1999 1998
- -------------------------------------------------- -------- -------- --------
(in thousands)
Tax at statutory Canadian rate of 44.62% $ 28,940 $ 1,247 $(40,355)
Lower income tax rate on earnings of
US subsidiaries (5,717) (1,823) 7,830
Canadian income tax on exchange
loss which is eliminated upon consolidation 426 909 631
Exchange revaluation of Canadian
deferred tax assets 515 (553) 280
Other 20 37 195
-------- -------- --------
Tax at effective rate $ 24,184 $ (183) $(31,419)
======== ======== ========
Effective tax rate 37.3 % (6.6)% 34.7 %
======== ======== ========
Temporary differences comprising the deferred tax assets
(liabilities) are as follows:
2000 1999
------------------------------------- -------------------------------------
As at December 31, CANADA US TOTAL Canada US Total
- ------------------------------------- -------- -------- -------- -------- -------- --------
(in thousands)
Deferred tax assets
Depletion and amortization $ 10,155 $ -- $ 10,155 $ 11,561 $ -- $ 11,561
Financing costs 1,374 -- 1,374 2,005 -- 2,005
Loss carryforwards 772 26,656 27,428 1,461 26,645 28,106
Other 1,374 15 1,389 490 5 495
-------- -------- -------- -------- -------- --------
13,675 26,671 40,346 15,517 26,650 42,167
-------- -------- -------- -------- -------- --------
Deferred tax liabilities
Depletion and amortization -- (34,199) (34,199) -- (11,929) (11,929)
-------- -------- -------- -------- -------- --------
Net deferred tax assets (liabilities) $ 13,675 $ (7,528) $ 6,147 $ 15,517 $ 14,721 $ 30,238
======== ======== ======== ======== ======== ========
(e) STOCK-BASED COMPENSATION
We apply the intrinsic value method prescribed by APB
Opinion 25 and related interpretations in accounting for
share option transactions. Accordingly, no compensation
cost is recognized in the accounts. US accounting
principles require disclosure of the impact on earnings
and earnings per share of the value of options granted
after 1994, calculated in accordance with FAS 123.
45
48
Such impact, using fair values of $11.38, $7.75 and
$10.61 for options granted in 2000, 1999 and 1998,
respectively, would approximate the following pro forma
amounts.
Year ended December 31, 2000 1999 1998
- --------------------------------------------- ---------- ---------- ----------
(in thousands except per share amounts)
Compensation costs, net of tax $ 1,361 $ 1,255 $ 1,502
Net income (loss) applicable to common shares
As reported $ 35,733 $ (1,967) $ (63,963)
Pro forma $ 34,372 $ (3,222) $ (65,465)
Net income (loss) per common share
Basic
As reported $ 2.21 $ (0.14) $ (4.75)
Pro forma $ 2.12 $ (0.24) $ (4.86)
Diluted
As reported $ 2.06 $ (0.14) $ (4.75)
Pro forma $ 2.01 $ (0.24) $ (4.86)
The fair value of each option granted is estimated on
the date of grant using the Black-Scholes option pricing
model with weighted average assumptions for grants as
follows:
Year ended December 31, 2000 1999 1998
- ----------------------- ------ ------ ------
Risk free interest rate 6.48 % 5.68 % 5.64 %
Expected lives (years) 10 10 10
Expected volatility 29% 28 % 25 %
Dividends NONE None None
(f) RECENT ACCOUNTING PRONOUNCEMENTS
FAS 133, Accounting for Derivative Instruments and
Hedging Activities, as amended by FAS 138, is first
effective for our 2001 fiscal year. FAS 133 currently
has no affect on us as our derivative instruments
qualify for the normal purchases and normal sales
exception.
46
49
SUPPLEMENTARY FINANCIAL INFORMATION
CHIEFTAIN INTERNATIONAL, INC. AND SUBSIDIARY COMPANIES
DECEMBER 31, 2000
(Unaudited)
RESERVE INFORMATION
Reports prepared by Netherland, Sewell & Associates, Inc. as to our US reserves
and by ourselves as to the UK reserves, estimate the total proved reserves owned
by us, before and after royalty deductions, as follows:
Natural Gas -- mmcf Oil and ngls -- mbbls*
-------------------------------------- ----------------------
TOTAL PROVED RESERVES -- BEFORE ROYALTY DEDUCTIONS US UK Total US
- ------------------------------------------------- -------- -------- -------- --------
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
PURCHASE OF PRODUCING PROPERTIES 2,741 -- 2,741 99
REVISION OF PREVIOUS ESTIMATES 29,936 1,549 31,485 (870)
EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS 41,280 -- 41,280 239
SALE OF PROVED PROPERTIES -- -- -- --
PRODUCTION (26,016) (1,940) (27,956) (1,464)
-------- -------- -------- --------
DECEMBER 31, 2000 227,851 5,985 233,836 15,314
======== ======== ======== ========
Natural Gas -- mmcf Oil and ngls -- mbbls*
-------------------------------------- ----------------------
Total Proved Reserves -- After Royalty Deductions US UK Total US
- ------------------------------------------------- -------- -------- ------- --------
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
PURCHASE OF PRODUCING PROPERTIES 1,839 -- 1,839 66
REVISION OF PREVIOUS ESTIMATES 22,393 1,549 23,942 (875)
EXTENSIONS, DISCOVERIES AND OTHER ADDITIONS 34,019 -- 34,019 196
SALE OF PROVED PROPERTIES -- -- -- --
PRODUCTION (20,931) (1,940) (22,871) (1,235)
------- ------- -------- --------
DECEMBER 31, 2000 180,877 5,985 186,862 13,098
======= ======= ======== ========
* 19,100 (1999 - 20,100) barrels of natural gas liquids, before and after
royalty deductions, associated with the UK gas reserves are not included in
this table.
47
50
(Unaudited)
Natural Gas -- mmcf Oil and ngls -- mbbls
--------------------------------- ---------------------
PROVED DEVELOPED PRODUCING RESERVES - BEFORE ROYALTY DEDUCTIONS US UK Total US
- --------------------------------------------------------------- ------- ------- ------- -------
December 31, 1998 70,082 10,108 80,190 5,430
December 31, 1999 63,822 6,376 70,198 7,447
DECEMBER 31, 2000 98,625 5,985 104,610 6,893
Natural Gas -- mmcf Oil and ngls -- mbbls
------------------------------ ---------------------
PROVED DEVELOPED PRODUCING RESERVES - AFTER ROYALTY DEDUCTIONS US UK Total US
- -------------------------------------------------------------- ------ ------ ------ ------
December 31, 1998 55,418 10,108 65,526 4,739
December 31, 1999 50,531 6,376 56,907 6,580
DECEMBER 31, 2000 77,699 5,985 83,684 6,002
RESULTS OF OPERATIONS FOR GAS AND OIL PRODUCING ACTIVITIES
Year ended December 31, 2000 1999 1998
- --------------------------------------------- --------- --------- ---------
(in thousands)
US
Revenue -- net of royalties $ 113,005 $ 71,487 $ 56,199
Production costs (16,861) (18,128) (15,675)
Depletion and amortization (42,680) (46,796) (39,460)
--------- --------- ---------
Results of operations before income taxes 53,464 6,563 1,064
Income tax (expense) recovery (18,966) (2,300) (333)
--------- --------- ---------
Results of operations after income taxes 34,498 4,263 731
--------- --------- ---------
UK
Revenue -- net of royalties 3,987 3,582 4,411
Production costs (256) (338) (964)
Depletion and amortization (1,016) (9,304) (3,646)
--------- --------- ---------
Results of operations before income taxes 2,715 (6,060) (199)
Income tax (expense) recovery (1,088) 2,624 117
--------- --------- ---------
Results of operations after income taxes 1,627 (3,436) (82)
--------- --------- ---------
Libya
Revenue -- net of royalties -- 297 1,005
Production costs -- (631) (1,041)
Depletion and amortization -- (11,393) (5,144)
--------- --------- ---------
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 116,992 75,366 $ 61,615
Production costs (17,117) (19,097) (17,680)
Depletion and amortization (43,696) (67,493) (48,250)
--------- --------- ---------
Results of operations before income taxes 56,179 (11,224) (4,315)
Income tax (expense) recovery (20,054) 5,557 2,096
--------- --------- ---------
Results of operations after income taxes $ 36,125 $ (5,667) $ (2,219)
========= ========= =========
48
51
(Unaudited)
CAPITALIZED COSTS RELATING TO GAS AND OIL EXPLORATION AND PRODUCTION ACTIVITIES
December 31, 2000 1999 1998
- ------------------------------- --------- --------- ---------
(in thousands)
Proved gas and oil properties $ 636,939 $ 550,097 $ 475,902
Unproved gas and oil properties 73,163 57,304 76,478
--------- --------- ---------
710,102 607,401 552,380
Accumulated depletion (383,482) (339,786) (266,066)
--------- --------- ---------
Net capitalized costs $ 326,620 $ 267,615 $ 286,314
========= ========= =========
COSTS INCURRED IN GAS AND OIL PROPERTY ACQUISITION, EXPLORATION AND DEVELOPMENT
ACTIVITIES
Year ended December 31, 2000 1999 1998
- --------------------------------- -------- -------- --------
(in thousands)
Property acquisition costs:
US $ 7,789 $ 5,352 $ 7,903
UK 33 28 115
-------- -------- --------
7,822 5,380 8,018
-------- -------- --------
Purchase of producing properties:
US -- -- 883
Sale of producing properties:
US -- (155) --
Exploration costs:
US 57,926 28,753 43,317
UK 9 9 72
Other foreign -- 1,531 606
-------- -------- --------
57,935 30,293 43,995
-------- -------- --------
Development costs:
US 36,943 19,542 39,606
UK 1 (39) 71
-------- -------- --------
36,944 19,503 39,677
-------- -------- --------
Total $102,701 $ 55,021 $ 92,573
======== ======== ========
49
52
(Unaudited)
STANDARDIZED MEASURE OF DISCOUNTED FUTURE NET CASH FLOWS AND CHANGES THERE IN
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. WE THEREFORE CAUTION AGAINST SIMPLISTIC USE OF
THIS INFORMATION.
December 31, 2000 1999 1998
- ------------------------------------------------------------------ ----------- ----------- -----------
(in thousands)
US
Future cash inflows $ 2,073,021 $ 665,306 $ 382,771
Future production costs (203,058) (180,948) (116,976)
Future development costs (120,262) (83,476) (60,203)
Future income tax expense (539,413) (63,590) --
----------- ----------- -----------
Future net cash flows 1,210,288 337,292 205,592
Ten percent annual discount for estimated timing of cash flows (371,192) (114,871) (62,089)
----------- ----------- -----------
Standardized measure of discounted future net cash flows 839,096 222,421 143,503
----------- ----------- -----------
UK
Future cash inflows 22,809 11,826 19,349
Future production costs (3,735) (8,261) (7,483)
Future development costs (1,469) (1,397) (1,457)
Future income tax expense (4,441) -- --
----------- ----------- -----------
Future net cash flows 13,164 2,168 10,409
Ten percent annual discount for estimated timing of cash flows (2,795) (56) (1,404)
----------- ----------- -----------
Standardized measure of discounted future net cash flows 10,369 2,112 9,005
----------- ----------- -----------
Total
Future cash inflows 2,095,830 677,132 402,120
Future production costs (206,793) (189,209) (124,459)
Future development costs (121,731) (84,873) (61,660)
Future income tax expense (543,854) (63,590) --
----------- ----------- -----------
Future net cash flows 1,223,452 339,460 216,001
Ten percent annual discount for estimated timing of cash flows (373,987) (114,927) (63,493)
----------- ----------- -----------
Standardized measure of discounted future net cash flows $ 849,465 $ 224,533 $ 152,508
=========== =========== ===========
50
53
(Unaudited)
The following table sets out principal sources of change in the standardized
measure of discounted future net cash flows during the respective periods.
Year ended December 31, 2000 1999 1998
- -------------------------------------------------------------------- --------- --------- ---------
(in thousands)
Sales of oil, ngls and natural gas produced, net of production costs $(102,732) $ (61,192) $ (45,231)
Net change in prices and production costs 710,398 83,559 (79,471)
Extensions and discoveries, less related costs 224,214 83,248 30,159
Purchase of producing properties 10,792 -- 2,793
Sales of producing properties -- -- --
Development costs incurred during the period 27,828 9,734 23,131
Revisions of previous quantity estimates 87,934 (8,441) (17,191)
Accretion of discount 22,453 15,251 19,958
Net change in income taxes (330,636) (41,941) 38,739
Changes in estimated future development costs (39,238) (23,126) (16,421)
Other 13,919 14,933 (3,531)
--------- --------- ---------
Net increase (decrease) 624,932 72,025 (47,065)
Beginning of year 224,533 152,508 199,573
--------- --------- ---------
End of year $ 849,465 $ 224,533 $ 152,508
========= ========= =========
51
54
(Unaudited)
Quarterly Information
2000 QUARTER ENDED 1999 Quarter Ended
------------------------------------- ------------------------------------------
MAR 31 JUN 30 SEP 30 DEC 31 Mar 31 Jun 30 Sep 30 Dec 31
------- ------- ------- ------- ------- -------- ------- -------
(in thousands except for per share amounts)
FINANCIAL
Revenue $21,224 $24,436 $32,996 $41,217 $13,218 $ 17,543 $22,763 $22,923
Gross profit 5,376 8,968 16,352 23,121 (4,169) (12,491) 3,874 266
Net income (loss) 2,105 3,912 8,940 12,391 (3,860) (8,507) 1,282 (754)
Per share - basic 0.13 0.24 0.55 0.77 (0.29) (0.64) 0.10 (0.05)
- diluted * 0.13 0.24 0.51 0.69 (0.29) (0.64) 0.09 (0.05)
Capital expenditures $19,460 $25,493 $21,102 $36,836 $10,389 $ 9,337 $16,489 $18,854
Weighted average common shares
outstanding
- basic 16,224 16,224 16,216 16,068 13,354 13,348 13,349 14,743
- diluted * 16,224 16,404 19,781 19,766 13,354 13,348 13,523 14,743
COMMON SHARE INFORMATION
American Stock Exchange
Per share - high $ 20.38 $ 22.25 $ 22.50 $ 27.75 $ 15.50 $ 18.63 $ 22.75 $ 20.38
- low 13.38 17.63 15.88 19.31 9.56 12.25 17.44 14.06
- close $ 20.13 $ 19.06 $ 20.69 $ 27.63 $ 12.25 $ 17.50 $ 19.00 $ 17.25
Volume 2,924 2,914 3,965 4,424 3,703 2,959 1,872 5,551
Toronto Stock Exchange
Per share - high C$ 27.85 C$ 33.20 C$ 33.50 C$ 41.90 C$ 24.00 C$ 26.95 C$ 34.00 C$ 30.25
- low 19.50 25.45 23.60 29.20 14.50 19.25 25.90 21.00
- close C$ 27.85 C$ 28.60 C$ 31.00 C$ 41.50 C$ 18.90 C$ 25.25 C$ 27.60 C$ 25.00
Volume 483 269 536 599 911 720 413 345
* Restated to reflect retroactive application of treasury stock method when
assessing share options for dilutive effect.
52
55
(Unaudited)
Quarterly Information
2000 QUARTER ENDED 1999 Quarter Ended
------------------------------------------ ------------------------------------------
MAR 31 JUN 30 SEP 30 DEC 31 Mar 31 Jun 30 Sep 30 Dec 31
------ ------ ------ ------ ------ ------ ------ ------
OPERATING
Daily volumes, before royalties
Natural gas (mmcf)
US 66.1 63.4 77.2 77.6 76.1 74.4 76.7 74.6
UK 8.5 5.9 0.3 6.5 11.0 7.7 10.5 10.1
------ ------ ------ ------ ------ ------ ------ ------
Total 74.6 69.3 77.5 84.1 87.1 82.1 87.2 84.7
====== ====== ====== ====== ====== ====== ====== ======
Oil and ngls (barrels) 4,154 4,181 3,964 3,792 3,679 5,222 5,200 4,329
Equivalent (mmcfe) 99.5 94.3 101.3 106.8 109.2 113.4 118.4 110.7
Daily volumes, after royalties
Natural gas (mmcf)
US 52.9 51.0 62.4 62.4 60.1 59.1 61.4 59.8
UK 8.5 5.9 0.3 6.5 11.0 7.7 10.5 10.1
------ ------ ------ ------ ------ ------ ------ ------
Total 61.4 56.9 62.7 68.9 71.1 66.8 71.9 69.9
====== ====== ====== ====== ====== ====== ====== ======
Oil and ngls (barrels) 3,494 3,531 3,351 3,208 3,156 4,421 4,394 3,671
Equivalent (mmcfe) 82.4 78.1 82.8 88.1 90.1 93.3 98.3 92.0
Pricing
Natural gas ($ per mcf)
US $ 2.51 $ 3.18 $ 3.84 $ 5.20 $ 1.60 $ 1.97 $ 2.46 $ 2.58
UK 1.35 1.58 1.92 3.09 1.13 0.82 0.81 1.03
Composite 2.38 3.04 3.83 5.03 1.54 1.86 2.26 2.39
Oil and ngls ($ per barrel) $24.06 $26.30 $30.53 $30.32 $10.94 $15.17 $19.31 $21.67
53
56
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE
There have been no disagreements between us and our auditors on accounting or
financial disclosure matters.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS
Additional information relating to our directors is incorporated herein by
reference from page 6 of our Information Circular dated April 4, 2001 for the
annual and special meeting of shareholders on May 17, 2001.
ITEM 11. EXECUTIVE COMPENSATION
"Executive Compensation" on pages 6 to 10 of our Information Circular dated
April 4, 2001 for the annual and special meeting of shareholders on May 17, 2001
is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT
"Voting Shares" and "Share Ownership" on pages 3 and 4 of our Information
Circular dated April 4, 2001 for the annual and special meeting of shareholders
on May 17, 2001 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 30 of this report.
EXHIBITS
Reference is made to the Index to Exhibits on page 55 of this report.
54
57
Index to Exhibits
Exhibit
Number Exhibit
------ -------
* 3 (a) Articles of Incorporation.
* 3 (b) Articles of Amendment.
* 3 (c) Articles of Amalgamation.
* 3 (d) By-laws number 1 and number 2.
** 4 (a) Form of Subordinated Guarantee Agreement.
*** 4 (b) Shareholder Rights Plan adopted April 23, 1994.
**** 10 (a)(i) Retirement Plan as amended May 15, 1997.
**** 10 (a)(ii) Supplementary Retirement Plan as amended March 20, 1997.
***** 10 (b) Share Option Plan as amended March 15, 2000.
* 10 (c) 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 April 4, 2001 relating to the annual and special meeting of shareholders
to be held on May 17, 2001.
****** 22 Subsidiaries.
***** 24 (a) Consent of Netherland, Sewell & Associates, Inc.
***** 24 (b) Consent of PricewaterhouseCoopers LLP.
* Previously filed as an exhibit to the Registration Statement on Form
S-1, File No. 33-27254.
** Previously filed as an exhibit to the Registration Statement on Form
S-1/S-3, File No. 33-51630.
*** Previously filed as an exhibit to Form 8-K dated March 1, 1994.
**** Previously filed as an exhibit to Form 10-K dated March 20, 1998.
***** Filed herewith.
****** Previously filed as an exhibit to Form 10-K dated March 17, 1994.
******* To be filed.
55
58
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 14, 2001
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 14, 2001
- ----------------------------------
D.E. Mitchell O.C.
/s/ S.A. MILNER President, Chief Executive Officer and March 14, 2001
- ----------------------------------
S.A. Milner, A.O.E., LL.D. Director; Principal Executive and Financial Officer
/s/ S.C. HURLEY Director March 14, 2001
- ----------------------------------
S.C. Hurley
/s/ H.J. KELLY Director March 14, 2001
- ----------------------------------
H.J. Kelly
/s/ J.E. MAYBIN Director March 14, 2001
- ----------------------------------
J.E. Maybin
/s/ L.G. MUNIN Director March 14, 2001
- ----------------------------------
L.G. Munin
/s/ E.S. ONDRACK Director March 14, 2001
- ----------------------------------
E.S. Ondrack
/s/ S.T. PEELER Director March 14, 2001
- ----------------------------------
S.T. Peeler
/s/ R.J. STEFURE Vice President and Controller March 14, 2001
- ----------------------------------
R.J. Stefure Principal Accounting Officer
56
59
Exhibit 10(b)
CHIEFTAIN INTERNATIONAL, INC.
SHARE OPTION PLAN
MARCH 15, 2000
60
CHIEFTAIN INTERNATIONAL, INC.
SHARE OPTION PLAN
1. PURPOSE
The purpose of the Plan is to encourage present and future directors,
key employees and consultants to promote the growth and development of
Chieftain International, Inc. (the "Company") by providing such
directors, employees and consultants with the opportunity, through share
options, to purchase shares in the Company and to recognize the
contributions of directors, key employees and consultants to the success
of the Company by granting them share options.
2. ADMINISTRATION
The Plan shall be administered and interpreted by the Board of Directors
(the "Board") of the Company. The Board may delegate to the Compensation
Committee (the "Committee") full power and authority to take any action
required or permitted to be taken by the Board under the Plan including
the full power and authority to administer the Plan, but excluding the
power to amend or terminate the Plan. Any decision on Plan
interpretation made by the Board shall be final and nothing contained
herein shall restrict or limit or be deemed to restrict or limit the
rights or powers of the Board.
3. ELIGIBILITY
Such directors and employees of and consultants to the Company and its
subsidiaries as are designated by the Board upon the advice of the
President shall be eligible to receive options under the Plan.
4. SHARES SUBJECT TO PLAN
Shares subject to the Plan shall be such number of unissued common
shares of the Company as has been reserved for purposes of the Plan by
resolution of the Board, subject to such regulatory approval as may
apply. Shares in respect of which options have terminated without
exercise shall be available for subsequent options.
The number of shares reserved for grants under the Plan shall be limited
to 1,500,000 shares subject to the provisions of Section 10,
"Alterations in Shares", and shall not in any event exceed ten per cent
of the total number of issued and outstanding common shares of the
Company.
5. GRANTING OF OPTIONS
The Board upon the advice of the President may from time to time grant,
to eligible directors, employees and consultants options to purchase
shares of the Company in such amounts as the Board may determine, except
that at no time will an optionee hold options to purchase more than 5%
of the issued and outstanding common shares of the Company.
61
Chieftain International, Inc. Share Option Plan
March 15, 2000 2
6. OPTION PRICE
The option price shall be fixed by the Board when an option is granted
at not less than the market price of the final board lot of the common
shares traded on the American Stock Exchange on the trading day
preceding the day on which the option is granted during which at least
500 common shares traded.
7. MATURITY OF OPTIONS
Each option will mature and be exercisable as to one-third (1/3) of the
shares subject thereto immediately following the end of each of the
first three years of the term and may be exercised at any time in whole
or in part only after maturity and prior to the end of the full term.
8. OPTION AGREEMENTS
Each option granted hereunder shall be evidenced by a written option
agreement between the Company and the optionee and shall contain such
terms and conditions as may be provided by the Board upon the advice of
the President. The terms and conditions of option agreements need not be
identical. The option agreements shall include provisions as to:
(a) the number of shares under option,
(b) the option price,
(c) any restrictions on exercise of the option, and
(d) the expiry date of the option.
9. EXERCISE OF OPTION
An option, or any portion thereof, may be exercised by delivering to the
Company a written notice of exercise specifying the number of shares
with respect to which the option is being exercised and accompanied by
payment in full of the purchase price of the shares.
The Company, in the sole discretion of the Board, may, in lieu of
delivering common shares upon exercise of a stock option, pay the
optionee the amount of the difference between the fair market value and
the option price, fair market value being the weighted average trading
price for the common shares on the American Stock Exchange during the
five trading days immediately preceding the exercise date.
10. ALTERATIONS IN SHARES
Appropriate adjustments in the number of shares subject to option and in
the option price per share shall be made by the Board to give effect to
adjustments in the number of common shares of the Company resulting from
subdivision, consolidation or reclassification of the common shares of
the Company, or the reconstruction, reorganization or recapitalization
of the Company or other relevant changes in the capital of the Company.
62
Chieftain International, Inc. Share Option Plan
March 15, 2000 3
11. CHANGE OF CONTROL
Clause 7 hereof notwithstanding, in the event of (i) the making of an
offer for such number of common shares of the Company as would, if
successful, result, in the opinion of the Board, in a change of control;
or (ii) any event which, in the opinion of the Board, warrants same, the
option shall be exercisable in full and the optionee may exercise the
option for a period of 60 days following the date of such event, or such
shorter period of time as the Board shall fix, having regard to the
nature of the event.
12. EXPIRY OF OPTIONS
An option granted under the Plan shall, unless otherwise prescribed by
the Board, expire on the tenth anniversary of the date the option was
granted, provided the optionee remains in the service of the Company.
Notwithstanding the provisions of Clause 7, in the event of termination
of service as a result of:
(a) retirement of an employee under a retirement plan or early
retirement policy of the Company after at least five years of
service, or
(b) conclusion of service of a director or consultant after at least
five years of service as a director or consultant
the option shall be exercisable and the optionee or the legal heirs of
the optionee, as the case may be, may exercise the option for a period
of 5 years or until the normal expiry date of such option, if earlier.
Also notwithstanding the provisions of Clause 7, in the event of
termination of service as a result of:
(a) disability, or
(b) death,
the option shall be exercisable and the optionee or the legal heirs of
the optionee, as the case may be, may exercise the option for a period
of 18 months unless a longer period, ending no later than the normal
expiry date of the option, is fixed by the Board.
In the case of termination of service for any other reason and unless
the Board determines otherwise, the optionee may continue to exercise
his option, to the extent it was exercisable on the date of termination,
for 60 days following such termination or until the normal expiry date
of such option, if earlier.
13. CASH PREMIUMS
The Company will provide to the optionee a cash payment approximately
equal to the income tax payable as a result of the optionee having
exercised his option, in whole or in part, subject to the following
conditions:
63
Chieftain International, Inc. Share Option Plan
March 15, 2000 4
(a) cash premiums will be paid only in respect of the exercise of
his option no earlier than four years from the date of grant,
(b) cash premiums will be paid only with respect to shares retained
in the manner prescribed herein, and
(c) the maximum marginal tax rate used to calculate such cash
premiums will be 50%.
To be eligible to receive a cash premium, the optionee will place in
escrow with the Company for a period of two years shares obtained
through exercise of his option under the Plan. To remove the shares from
escrow prior to the end of the two years, the optionee must reimburse
the Company twenty-five percent of the cash premium for each six month
period or part thereof that remains in the 24 month escrow period.
In the event of the death or permanent disability of an optionee or
retirement under a Company retirement plan, the Company may, at its sole
discretion, waive the requirement for reimbursement of the cash premium.
14. NON ASSIGNABILITY OF OPTIONS
The interest of an optionee shall not be transferable or alienable by
the optionee either by assignment or in any other manner during the
optionee's lifetime but shall enure to the benefit of the legal heirs of
the optionee.
15. RIGHTS AS A SHAREHOLDER
The optionee shall have no rights whatsoever as a shareholder in respect
of his option until and to the extent that the optionee exercises his
option to purchase shares in accordance with clause 9.
16. DIVIDENDS
Dividends will not be paid on shares which are subject to an option
until the option to purchase shares in accordance with clause 9 is
exercised and then only in respect of the shares so purchased.
17. AMENDMENT OR DISCONTINUANCE OF PLAN
The Board may amend the plan at any time, and from time to time but no
such amendment may impair any option previously granted to an optionee
without written consent of that optionee.
64
EXHIBIT 24(a)
CONSENT OF INDEPENDENT PETROLEUM ENGINEERS AND GEOLOGISTS
We hereby consent to the references to our firm and our report and to the
use of our report in the Annual Report of Chieftain International, Inc. on Form
10-K for the fiscal year ended December 31, 2000, 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 22, 2001
65
EXHIBIT 24 (b)
March 22, 2001
CONSENT OF INDEPENDENT AUDITORS
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 1, 2001 relating to the consolidated financial statements
for the year ended December 31, 2000 that appear in this Form 10-K.
(signed) PricewaterhouseCoopers LLP
Chartered Accountants
Edmonton, Alberta, Canada