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0000909567-04-000345.txt : 20040311
0000909567-04-000345.hdr.sgml : 20040311
20040311142127
ACCESSION NUMBER: 0000909567-04-000345
CONFORMED SUBMISSION TYPE: 10-K
PUBLIC DOCUMENT COUNT: 13
CONFORMED PERIOD OF REPORT: 20031231
FILED AS OF DATE: 20040311
FILER:
COMPANY DATA:
COMPANY CONFORMED NAME: IMPERIAL OIL LTD
CENTRAL INDEX KEY: 0000049938
STANDARD INDUSTRIAL CLASSIFICATION: PETROLEUM REFINING [2911]
IRS NUMBER: 980017682
FISCAL YEAR END: 1231
FILING VALUES:
FORM TYPE: 10-K
SEC ACT: 1934 Act
SEC FILE NUMBER: 000-12014
FILM NUMBER: 04662599
BUSINESS ADDRESS:
STREET 1: 111 ST CLAIR AVE W
CITY: TORONTO ONTARIO CANADA M5W 1K3
STATE: A6
BUSINESS PHONE: 4169684111
MAIL ADDRESS:
STREET 1: 111 ST. CLAIR AVE WEST
CITY: TORONTO
STATE: A6
ZIP: M5W 1K3
10-K
1
t12211e10vk.htm
10-K
e10vk
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
|
|
|
For the fiscal year ended December 31, 2003 |
|
Commission file number: 0-12014 |
IMPERIAL OIL LIMITED
(Exact name of registrant as specified in its charter)
|
|
|
CANADA |
|
98-0017682 |
(State or other jurisdiction of |
|
(I.R.S. Employer |
incorporation or organization) |
|
Identification No.) |
|
|
|
111 ST. CLAIR AVENUE WEST, TORONTO, ONT., CANADA |
|
M5W 1K3 |
(Address of
principal executive officers) |
|
(Zip Code) |
Registrants telephone number, including area code:
1-800-567-3776
Securities registered pursuant to Section 12(b) of the Act:
|
|
|
|
|
Name of each exchange on |
Title of each class |
|
which registered |
None |
|
None |
|
|
|
Securities registered pursuant to
Section 12(g) of the Act:
Common Shares (without par value)
(Title of Class)
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 þ No o
Disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is
not contained herein, and will not be contained, to the best of registrants
knowledge, in definitive proxy or information statements incorporated by
reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Yes
þ
No o
The registrant is an accelerated filer (as defined in Rule 12 b-2 of the
Securities Exchange Act of 1934).
Yes þ No o
As of the last business day of the 2003 second fiscal quarter, the
aggregate market value of the voting stock held by non-affiliates of the
registrant was Canadian $5,327,412,752 based upon the reported last sale price
of such stock on the Toronto Stock Exchange on that date.
The number of common shares outstanding, as of February 27, 2004, was
361,316,496.
TABLE OF CONTENTS
TABLE OF CONTENTS
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Page |
PART I |
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Item 1. Business |
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3 |
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|
Financial Information by Operating Segments |
|
|
3 |
|
|
Natural Resources |
|
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4 |
|
|
|
Petroleum and Natural Gas Production |
|
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4 |
|
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|
Land Holdings |
|
|
10 |
|
|
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Exploration and Development |
|
|
10 |
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Petroleum Products |
|
|
12 |
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Supply |
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12 |
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Refining |
|
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12 |
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Distribution |
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13 |
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Marketing |
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13 |
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Chemicals |
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14 |
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Research |
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14 |
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Environmental Protection |
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14 |
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Human Resources |
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14 |
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Competition |
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14 |
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Government Regulation |
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15 |
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The Company Online |
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|
15 |
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Item 2. Properties |
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|
16 |
|
Item 3. Legal Proceedings |
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|
16 |
|
Item 4. Submission of Matters to a Vote of Security Holders |
|
|
16 |
|
PART II |
|
|
|
|
Item 5. Market for Registrants Common Equity, Related Stockholder
Matters and Issuer
Purchases of Equity Securities |
|
|
16 |
|
Item 6. Selected Financial Data |
|
|
17 |
|
Item 7. Managements Discussion and Analysis of Financial Condition
and Results of Operation |
|
|
21 |
|
Item 7A. Quantitative and Qualitative Disclosures About Market Risk |
|
|
29 |
|
Item 8. Financial Statements and Supplementary Data |
|
|
30 |
|
Item 9. Changes in and Disagreements with Accountants on Accounting
and Financial Disclosure |
|
|
33 |
|
Item 9A. Controls and Procedures |
|
|
34 |
|
PART III |
|
|
|
|
Item 10. Directors and Executive Officers of the Registrant |
|
|
35 |
|
Item 11. Executive Compensation |
|
|
38 |
|
Item 12. Security Ownership of Certain Beneficial Owners and
Management and
Related Stockholder Matters |
|
|
45 |
|
Item 13. Certain Relationships and Related Transactions |
|
|
46 |
|
Item 14. Principal Accountant Fees and Services |
|
|
46 |
|
PART IV |
|
|
|
|
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K |
|
|
47 |
|
Index to Financial Statements |
|
|
F-1 |
|
Auditors Report |
|
|
F-2 |
|
All dollar amounts set forth in this report are in Canadian dollars, except
where otherwise indicated.
The following table sets forth (i) the rates of exchange for the Canadian
dollar, expressed in U.S. dollars, in effect at the end of each of the periods
indicated, (ii) the average of exchange rates in effect on the last day of each
month during such periods, and (iii) the high and low exchange rates during
such periods, in each case based on the noon buying rate in New York City for
cable transfers in Canadian dollars as certified for customs purposes by the
Federal Reserve Bank of New York.
|
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2003 |
|
2002 |
|
2001 |
|
2000 |
|
1999 |
|
|
|
|
|
|
|
|
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|
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|
|
|
|
|
|
|
|
|
|
(Dollars) |
|
|
|
|
|
|
|
|
Rate at end of period |
|
|
0.7738 |
|
|
|
0.6329 |
|
|
|
0.6279 |
|
|
|
0.6669 |
|
|
|
0.6925 |
|
Average rate during period |
|
|
0.7186 |
|
|
|
0.6368 |
|
|
|
0.6444 |
|
|
|
0.6725 |
|
|
|
0.6744 |
|
High |
|
|
0.7738 |
|
|
|
0.6619 |
|
|
|
0.6697 |
|
|
|
0.6969 |
|
|
|
0.6925 |
|
Low |
|
|
0.6349 |
|
|
|
0.6200 |
|
|
|
0.6241 |
|
|
|
0.6410 |
|
|
|
0.6535 |
|
On February 27, 2004, the noon buying rate in New York City for cable transfers
in Canadian dollars as certified for customs purposes by the Federal Reserve
Bank of New York was $0.7460 U.S. = $1.00 Canadian.
2
This report contains forward looking information on future production,
project start ups and future capital spending. Actual results could differ
materially as a result of market conditions or changes in law, government
policy, operating conditions, costs, project schedules, operating performance,
demand for oil and natural gas, commercial negotiations or other technical and
economic factors.
PART I
Item 1. Business.
Imperial Oil Limited was incorporated under the laws of Canada in 1880 and
was continued under the Canada Business Corporations Act (the CBCA) by
certificate of continuance dated April 24, 1978. The head and principal office
of the Company is located at 111 St. Clair Avenue West, Toronto, Ontario,
Canada M5W 1K3; telephone 1-800-567-3776. Exxon Mobil Corporation owns
approximately 69.6 percent of the outstanding shares of the Company with the
remaining shares being publicly held, with the majority of shareholders having
Canadian addresses of record. In this report, unless the context otherwise
indicates, reference to the Company includes Imperial Oil Limited and its
subsidiaries.
The Company is Canadas largest integrated oil company. It is active in
all phases of the petroleum industry in Canada, including the exploration for,
and production and sale of, crude oil and natural gas. In Canada, it is one of
the largest producers of crude oil and natural gas liquids and a major producer
of natural gas, and the largest refiner and marketer of petroleum products. It
is also a major supplier of petrochemicals.
The Companys operations are conducted in three main segments: natural
resources (upstream), petroleum products (downstream) and chemicals.
Natural resources operations include the exploration for, and production of,
crude oil and natural gas, including upgraded crude oil and crude bitumen.
Petroleum products operations consist of the transportation, refining and
blending of crude oil and refined products and the distribution and marketing
thereof. The chemicals operations consist of the manufacturing and marketing of
various petrochemicals.
Financial Information by Operating Segments
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
1999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions) |
External revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural resources |
|
$ |
3,424 |
|
|
$ |
2,677 |
|
|
$ |
3,155 |
|
|
$ |
3,262 |
|
|
$ |
2,216 |
|
|
|
Petroleum products |
|
|
14,764 |
|
|
|
13,396 |
|
|
|
13,105 |
|
|
|
13,788 |
|
|
|
9,885 |
|
|
|
Chemicals |
|
|
994 |
|
|
|
955 |
|
|
|
930 |
|
|
|
945 |
|
|
|
717 |
|
|
|
Corporate and other |
|
|
26 |
|
|
|
14 |
|
|
|
63 |
|
|
|
56 |
|
|
|
35 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
19,208 |
|
|
$ |
17,042 |
|
|
$ |
17,253 |
|
|
$ |
18,051 |
|
|
$ |
12,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural resources |
|
$ |
2,224 |
|
|
$ |
2,217 |
|
|
$ |
2,166 |
|
|
$ |
2,638 |
|
|
$ |
1,688 |
|
|
|
Petroleum products |
|
|
1,294 |
|
|
|
1,038 |
|
|
|
1,300 |
|
|
|
1,332 |
|
|
|
780 |
|
|
|
Chemicals |
|
|
238 |
|
|
|
209 |
|
|
|
245 |
|
|
|
228 |
|
|
|
155 |
|
Total revenues: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural resources |
|
$ |
5,648 |
|
|
$ |
4,894 |
|
|
$ |
5,321 |
|
|
$ |
5,900 |
|
|
$ |
3,904 |
|
|
|
Petroleum products |
|
|
16,058 |
|
|
|
14,434 |
|
|
|
14,405 |
|
|
|
15,120 |
|
|
|
10,665 |
|
|
|
Chemicals |
|
|
1,232 |
|
|
|
1,164 |
|
|
|
1,175 |
|
|
|
1,173 |
|
|
|
872 |
|
|
|
Corporate and other |
|
|
26 |
|
|
|
14 |
|
|
|
63 |
|
|
|
56 |
|
|
|
35 |
|
|
Net earnings (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural resources |
|
$ |
1,139 |
|
|
$ |
1,056 |
|
|
$ |
957 |
|
|
$ |
1,177 |
|
|
$ |
567 |
|
|
|
Petroleum products |
|
|
407 |
|
|
|
127 |
|
|
|
353 |
|
|
|
313 |
|
|
|
15 |
|
|
|
Chemicals |
|
|
37 |
|
|
|
52 |
|
|
|
23 |
|
|
|
59 |
|
|
|
43 |
|
|
|
Corporate and other (2) /eliminations |
|
|
99 |
|
|
|
(11 |
) |
|
|
(78 |
) |
|
|
(139 |
) |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,682 |
|
|
$ |
1,224 |
|
|
$ |
1,255 |
|
|
$ |
1,410 |
|
|
$ |
628 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Identifiable assets at December 31 (3): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural resources |
|
$ |
6,434 |
|
|
$ |
6,014 |
|
|
$ |
5,385 |
|
|
$ |
5,310 |
|
|
$ |
5,399 |
|
|
|
Petroleum products |
|
|
5,341 |
|
|
|
5,048 |
|
|
|
4,348 |
|
|
|
4,812 |
|
|
|
4,549 |
|
|
|
Chemicals |
|
|
446 |
|
|
|
418 |
|
|
|
373 |
|
|
|
379 |
|
|
|
347 |
|
|
|
Corporate and other/eliminations |
|
|
140 |
|
|
|
414 |
|
|
|
675 |
|
|
|
743 |
|
|
|
533 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
12,361 |
|
|
$ |
11,894 |
|
|
$ |
10,781 |
|
|
$ |
11,244 |
|
|
$ |
10,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital and exploration expenditures: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural resources |
|
$ |
1,007 |
|
|
$ |
986 |
|
|
$ |
746 |
|
|
$ |
434 |
|
|
$ |
430 |
|
|
|
Petroleum products |
|
|
478 |
|
|
|
589 |
|
|
|
339 |
|
|
|
232 |
|
|
|
203 |
|
|
|
Chemicals |
|
|
41 |
|
|
|
25 |
|
|
|
30 |
|
|
|
13 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
1,526 |
|
|
$ |
1,600 |
|
|
$ |
1,115 |
|
|
$ |
679 |
|
|
$ |
653 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(continued on following page)
3
|
(1) |
|
These amounts are presented as if each segment were a separate business
entity and, accordingly, include the financial effect of transactions between
the segments. Intersegment sales are made essentially at prevailing market
prices. |
|
|
(2) |
|
Includes primarily interest charges on the debt obligations of the Company,
interest income on investments and intersegment consolidating adjustments. |
|
|
(3) |
|
The identifiable assets in each operating segment represent the net book
value of the tangible and intangible assets attributed to such segment. |
Natural Resources
Petroleum and Natural Gas Production
The Companys average daily production of crude oil and natural gas
liquids during the five years ended December 31, 2003, was as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
1999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(thousands per day) |
Conventional (including
natural gas liquids): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
|
|
|
Gross (1) |
|
|
11.8 |
|
|
|
12.4 |
|
|
|
13.2 |
|
|
|
14.3 |
|
|
|
15.3 |
|
|
|
|
|
|
|
Net (2) |
|
|
9.1 |
|
|
|
9.5 |
|
|
|
10.2 |
|
|
|
11.0 |
|
|
|
11.9 |
|
|
Barrels |
|
|
|
|
|
Gross (1) |
|
|
74 |
|
|
|
78 |
|
|
|
83 |
|
|
|
90 |
|
|
|
96 |
|
|
|
|
|
|
|
Net (2) |
|
|
57 |
|
|
|
60 |
|
|
|
64 |
|
|
|
69 |
|
|
|
75 |
|
Oil Sands (Cold Lake): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
|
|
|
Gross (1) |
|
|
20.5 |
|
|
|
17.8 |
|
|
|
20.4 |
|
|
|
18.9 |
|
|
|
21.0 |
|
|
|
|
|
|
|
Net (2) |
|
|
18.4 |
|
|
|
16.9 |
|
|
|
19.2 |
|
|
|
16.2 |
|
|
|
17.1 |
|
|
Barrels |
|
|
|
|
|
Gross (1) |
|
|
129 |
|
|
|
112 |
|
|
|
128 |
|
|
|
119 |
|
|
|
132 |
|
|
|
|
|
|
|
Net (2) |
|
|
116 |
|
|
|
106 |
|
|
|
121 |
|
|
|
102 |
|
|
|
107 |
|
Tar Sands (Syncrude): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
|
|
|
Gross (1) |
|
|
8.4 |
|
|
|
9.1 |
|
|
|
8.9 |
|
|
|
8.1 |
|
|
|
8.9 |
|
|
|
|
|
|
|
Net (2) |
|
|
8.3 |
|
|
|
9.1 |
|
|
|
8.3 |
|
|
|
6.7 |
|
|
|
8.7 |
|
|
Barrels |
|
|
|
|
|
Gross (1) |
|
|
53 |
|
|
|
57 |
|
|
|
56 |
|
|
|
51 |
|
|
|
56 |
|
|
|
|
|
|
|
Net (2) |
|
|
52 |
|
|
|
57 |
|
|
|
52 |
|
|
|
42 |
|
|
|
55 |
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
|
|
|
Gross (1) |
|
|
40.7 |
|
|
|
39.3 |
|
|
|
42.5 |
|
|
|
41.3 |
|
|
|
45.2 |
|
|
|
|
|
|
|
Net (2) |
|
|
35.8 |
|
|
|
35.5 |
|
|
|
37.7 |
|
|
|
33.9 |
|
|
|
37.7 |
|
|
Barrels |
|
|
|
|
|
Gross (1) |
|
|
256 |
|
|
|
247 |
|
|
|
267 |
|
|
|
260 |
|
|
|
284 |
|
|
|
|
|
|
|
Net (2) |
|
|
225 |
|
|
|
223 |
|
|
|
237 |
|
|
|
213 |
|
|
|
237 |
|
(1) |
|
Gross production of crude oil is the Companys share of production from
conventional wells, Syncrude tar sands and Cold Lake oil sands, and gross
production of natural gas liquids is the amount derived from processing the
Companys share of production of natural gas (excluding purchased gas), in each
case before deduction of the mineral owners or governments share or both. |
|
(2) |
|
Net production is gross production less the mineral owners or governments
share or both. |
From 1999, conventional production has declined due to the sale of oil and
gas producing properties and the natural decline in the productivity of the
Companys conventional oil fields. In 2000, Cold Lake production declined due
to the timing of steaming cycles and Syncrude production decreased because of
operating difficulties and extended maintenance to heavy crude oil upgrading
equipment. In 2001, Cold Lake net production increased mainly due to the timing
of steaming cycles and lower royalties and Syncrude production increased mainly
due to the start up of the Aurora mine during the second half of 2000 and fewer
disruptions in upgrading operations than the previous year. In 2002, Cold Lake
production decreased mainly due to the timing of steaming cycles and Syncrude
net production increased mainly due to lower royalties. In 2003, Cold Lake net
production increased as a result of a full year of production of stages 11 to
13, which was offset in part by the timing of steaming cycles and higher
royalties. Syncrude production decreased in 2003 due to extended maintenance of
upgrading facilities.
4
The Companys average daily production and sales of natural gas during the
five years ended December 31, 2003 are set forth below. All gas volumes in this
report are calculated at a pressure base of, in the case of cubic metres,
101.325 kilopascals absolute at 15 degrees Celsius and, in the case of cubic
feet, 14.73 pounds per square inch at 60 degrees Fahrenheit.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
1999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions per day) |
|
|
|
|
Sales (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
13.0 |
|
|
|
14.1 |
|
|
|
14.2 |
|
|
|
11.9 |
|
|
|
11.1 |
|
|
Cubic feet |
|
|
460 |
|
|
|
499 |
|
|
|
502 |
|
|
|
419 |
|
|
|
393 |
|
Gross Production (2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
14.5 |
|
|
|
15.0 |
|
|
|
16.2 |
|
|
|
14.9 |
|
|
|
13.3 |
|
|
Cubic feet |
|
|
513 |
|
|
|
530 |
|
|
|
572 |
|
|
|
526 |
|
|
|
469 |
|
Net Production (2): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
12.9 |
|
|
|
13.1 |
|
|
|
13.2 |
|
|
|
13.0 |
|
|
|
11.7 |
|
|
Cubic feet |
|
|
457 |
|
|
|
463 |
|
|
|
466 |
|
|
|
459 |
|
|
|
413 |
|
Gross Production available for sale (3): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
12.6 |
|
|
|
13.1 |
|
|
|
13.7 |
|
|
|
9.8 |
|
|
|
8.5 |
|
|
Cubic feet |
|
|
446 |
|
|
|
463 |
|
|
|
482 |
|
|
|
345 |
|
|
|
300 |
|
Net Production available for sale (3): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
11.0 |
|
|
|
11.2 |
|
|
|
10.7 |
|
|
|
7.8 |
|
|
|
6.9 |
|
|
Cubic feet |
|
|
390 |
|
|
|
396 |
|
|
|
376 |
|
|
|
277 |
|
|
|
244 |
|
(1) |
|
Sales are sales of the Companys share of production (before deduction of
the mineral owners and/or governments share) and sales of gas purchased,
processed and/or resold. |
|
(2) |
|
Gross production of natural gas is the Companys share of production
(excluding purchases) before deducting the shares of mineral owners or
governments or both. Net production excludes those shares. Production data
include amounts used for internal consumption with the exception of amounts
reinjected. |
|
(3) |
|
Gross production available for sale is the Companys share of production
available for sale (excluding purchases) before deducting the shares of mineral
owners or governments or both. Net production available for sale excludes those
shares. Production available for sale data exclude amounts used for internal
consumption and amounts reinjected. Production available for sale in 2001
reflects a change in the supply of natural gas to Company operations from
Company produced natural gas to purchased natural gas. |
In 2000 and 2001, natural gas production increased primarily due to gas
production from the Sable Offshore Energy Project, which went into production
at the end of 1999, and increased production from gas caps overlaying two
former oil fields, both in Alberta. In 2002 and 2003, natural gas production
decreased primarily due to the depletion of gas caps in Alberta and in 2003
also due to increased maintenance activity at gas processing facilities.
Most of the Companys natural gas sales are made under short-term contracts.
The Companys average sales price and production (lifting) costs for
conventional and Cold Lake crude oil and natural gas liquids and natural gas
for the five years ended December 31, 2003, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
1999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Sales Price: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per cubic metre |
|
$ |
181.92 |
|
|
$ |
174.72 |
|
|
$ |
134.16 |
|
|
$ |
190.02 |
|
|
$ |
120.82 |
|
|
|
Per barrel |
|
|
28.92 |
|
|
|
27.78 |
|
|
|
21.33 |
|
|
|
30.21 |
|
|
|
19.21 |
|
|
Natural gas: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per thousand cubic metres |
|
$ |
232.99 |
|
|
$ |
141.91 |
|
|
$ |
201.92 |
|
|
$ |
176.15 |
|
|
$ |
93.90 |
|
|
|
Per thousand cubic feet |
|
|
6.60 |
|
|
|
4.02 |
|
|
|
5.72 |
|
|
|
4.99 |
|
|
|
2.66 |
|
Average Production (Lifting) Costs Per
Unit of Net Production (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per cubic metre |
|
$ |
63.85 |
|
|
$ |
48.81 |
|
|
$ |
46.17 |
|
|
$ |
47.36 |
|
|
$ |
37.54 |
|
|
|
Per barrel |
|
|
10.15 |
|
|
|
7.76 |
|
|
|
7.34 |
|
|
|
7.53 |
|
|
|
5.97 |
|
(1) |
|
Average production (lifting) costs do not include depreciation and
depletion of capitalized acquisition, exploration and development costs.
Administrative expenses are included. Average production (lifting) costs
per unit of net production were computed after converting gas production
into equivalent units of oil on the basis of relative energy content. |
5
Canadian crude oil prices are mainly determined by international crude oil
markets which are volatile.
Canadian natural gas prices are determined by North
American gas markets and are also volatile. Prices for Canadian natural gas
increased significantly in 2000 and again in early 2001 and 2003, in line with
tighter North American market conditions. Canadian natural gas prices decreased
in 2002 primarily due to a weaker U.S. economy and warmer weather.
In 2000, average production (lifting) costs increased mainly due to higher
costs for purchased natural gas at Cold Lake. In 2001, average production
(lifting) costs decreased mainly due to higher net production at Cold Lake. In
2002, average production (lifting) costs increased mainly due to lower net
production at Cold Lake. In 2003, average production (lifting) costs increased
mainly due to higher costs of purchased natural gas at Cold Lake.
The Company has interests in a large number of facilities related to the
production of crude oil and natural gas. Among these facilities are 28 plants
that process natural gas to produce marketable gas and recover natural gas
liquids or sulphur. The Company is the principal owner and operator of 11 of
the plants.
The Companys production of conventional and Cold Lake crude oil and
natural gas is derived from wells located exclusively in Canada. The total
number of producing wells in which the Company had interests at December 31,
2003, is set forth in the following table. The statistics in the table are
determined in part from information received from other operators.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude Oil |
|
Natural Gas |
|
Total |
|
|
|
|
|
|
|
|
|
Gross (1) |
|
Net (2) |
|
Gross (1) |
|
Net (2) |
|
Gross (1) |
|
Net (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional wells |
|
|
2,334 |
|
|
|
1,321 |
|
|
|
4,033 |
|
|
|
2,187 |
|
|
|
6,367 |
|
|
|
3,508 |
|
Oil Sands (Cold Lake) wells |
|
|
3,524 |
|
|
|
3,524 |
|
|
|
|
|
|
|
|
|
|
|
3,524 |
|
|
|
3,524 |
|
|
(1) |
Gross wells are wells in which the Company owns a working interest. |
|
|
(2) |
Net wells are the sum of the fractional working interests owned by the
Company in gross wells, rounded to the nearest whole number. |
Conventional Oil and Gas
The Company has major interests in the Norman Wells oil field in the
Northwest Territories and the West Pembina oil field in Alberta. Together they
currently account for approximately 60 percent of the Companys net production
of conventional crude oil (approximately 65 percent of gross production).
Norman Wells is the Companys largest producing conventional oil field. In
2003, net production of crude oil and natural gas liquids was about 2,500 cubic
metres (15,900 barrels) per day and gross production was about 3,700 cubic
metres (23,200 barrels) per day. The Government of Canada has a one-third
carried interest and receives a production royalty of five percent in the
Norman Wells oil field. The Government of Canadas carried interest entitles it
to receive payment of a one-third share of an amount based on revenues from the
sale of Norman Wells production, net of operating and capital costs. Under a
shipping agreement, the Company pays for the construction, operating and other
costs of the 870 kilometre (540 mile) pipeline which transports the crude oil
and natural gas liquids from the project. In 2003, those costs were about $35
million.
Most of the larger oil fields in the Western Provinces have been in
production for several decades, and the amount of oil that is produced from
conventional fields is declining. In some cases, however, additional oil can be
recovered by using various methods of enhanced recovery. The Companys largest
enhanced recovery projects are located at the West Pembina oil field.
The Company produces natural gas from a large number of gas fields located
in the Western Provinces, primarily in Alberta.
The Company has a nine percent interest in a project to develop natural
gas reserves in the Sable Island area off the coast of the Province of Nova
Scotia. About $4 billion has been spent by the participants to the end of 2003
on the project. Production from the Sable Offshore Energy Project began at the
end of 1999 and is expected to average about 13 million cubic metres (450
million cubic feet) per day of natural gas and 2,900 cubic metres (18,000
barrels) per day of natural gas liquids through the end of the decade.
6
Cold Lake
The Company holds about 78,000 leased hectares (192,000 acres) of oil
sands near Cold Lake, Alberta. This oil sands deposit contains a very heavy
crude oil (crude bitumen). To develop the technology necessary to produce this
oil commercially, the Company has conducted experimental pilot operations since
1964 to recover the crude bitumen from wells by means of new drilling and
production techniques including steam injection. During 2003, net production
from the pilots averaged about 1,700 cubic metres (10,800 barrels) per day and
gross production was about 1,900 cubic metres (12,000 barrels) per day.
Research at, and operation of, the Cold Lake pilots is continuing.
In late 1983, the Company commenced the development, in stages, of its oil
sands resources at Cold Lake. The initial six stages of this production project
were completed by 1986. In 1987, the Company received approval from the Alberta
Energy Resources Conservation Board (AERCB) to increase the production of the
existing six stages from 9,000 cubic metres (57,000 barrels) to 12,000 cubic
metres (76,000 barrels) of crude bitumen per day. Also in 1987, the Company
received an amended approval from the AERCB for four additional stages (stages
seven to ten) of development at Cold Lake. During 2003, average net production
from those ten stages was about 13,000 cubic metres (81,800 barrels) per day
and gross production was about 14,500 cubic metres (91,000 barrels) per day.
To maintain production at Cold Lake, capital expenditures for additional
production wells and associated facilities will be required periodically. In
2003, the Company spent $93 million on a development drilling program of 118
wells on existing stages. In 2004, a significant development drilling program
of more than 300 wells is planned within the currently approved development
area to enhance productivity from existing Cold Lake stages. In addition,
opportunities are also being evaluated to improve utilization of the existing
infrastructure.
Construction began in 2000 on stages 11 to 13 of development. Total
capital investment for the development was about $650 million with the project
being completed in late 2002. The new stages are expected to provide, on
average, an additional 4,800 cubic metres (30,000 barrels) per day of crude
bitumen production. To improve overall energy efficiency, the project includes
a 170 megawatt cogeneration facility that will provide steam for the new stages
and generate enough electricity to supply all of the Companys other Cold Lake
operations. Any surplus electricity is sold into the Province of Alberta power
pool.
In 2002, the Company applied for regulatory approval for further expansion
of its operations at Cold Lake. The expansion would include three more
production stages (stages 14 to 16), which is expected to add about 4,800 cubic
metres (30,000 barrels) per day, and the extension of existing stages 9 and 10.
Assuming timely regulatory approval and favourable market conditions,
production is expected to begin as early as 2007, from extended stages 9 and 10
and from stages 14 to 16 by the end of the decade. The total cost of the new
developments is expected to be about $1 billion. The expansion, along with
stages 11 to 13, is expected to bring total production to about 28,600 cubic
metres (180,000 barrels) per day by the end of the decade.
Most of the production from Cold Lake is sold to refineries in the
northern United States. The remainder of the Cold Lake production is shipped to
certain of the Companys refineries and to a heavy oil upgrader in
Lloydminster, Saskatchewan.
The Province of Alberta, in its capacity as lessor of the Cold Lake oil
sands leases, is entitled to a royalty on production from the Cold Lake
production project, as defined in an agreement with the Province. Near the
beginning of 1996, the royalty increased from five percent of production to the
greater of five percent of production or 30 percent of an amount based on
revenue net of operating and capital costs for the project. The effective
royalty on gross production was ten percent in 2003, five percent in 2002 and
2001, 14 percent in 2000 and 18 percent in 1999. In late 2000, the Company
entered into an agreement with the Province of Alberta, effective January 1,
2000, on a transitional royalty arrangement that will apply to all of the
Companys current and proposed operations at Cold Lake until the end of 2007,
at which time the generic Alberta regulations for royalties that apply to all
other oil sands development in the Province will take effect. This transition
is expected to be royalty neutral. The Company expects that after 2007 the
royalty will be the greater of one percent of gross revenue or 25 percent of an
amount based on revenue net of operating and capital costs for the Cold Lake
production project and the pilot operations.
Other Oil Sands Activity
The Company has interests in other oil sands leases in the Athabasca and
Peace River areas of northern Alberta. Evaluation wells completed on these
leased areas established the presence of very heavy crude oil in place. The
Company continues to evaluate these leases to determine their potential for
future development.
7
The Company holds varying interests in lands totalling about 68,000 leased
net hectares (168,000 net acres) in the Athabasca area where the oil sands are
buried too deeply to permit recovery by surface mining methods. The Company, as
part of an industry consortium and several joint ventures, has been involved in
recovery research and pilot studies and in evaluating the quality and extent of
the oil sands.
Syncrude Mining Operations
The Company holds a 25 percent participating interest in Syncrude, a joint
venture established to recover shallow deposits of tar sands using open-pit
mining methods, to extract the crude bitumen, and to produce a high-quality,
light (32 degree API), sweet, synthetic crude oil. The Syncrude operation,
located near Fort McMurray, Alberta, exploits a portion of the Athabasca Oil
Sands Deposit. The location is readily accessible by public road. The produced
synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by
Alberta Oil Sands Pipeline Ltd. The pipeline is currently being expanded to
accommodate increased Syncrude production. Since startup in 1978, Syncrude has
produced about 1.5 billion barrels of synthetic crude oil.
Syncrude has an operating license issued by the Province of Alberta which
is effective until 2035. This license permits Syncrude to mine tar sands and
produce synthetic crude oil from approved development areas on tar sands
leases. Syncrude holds eight tar sands leases covering about 102,000 hectares
(252,000 acres) in the Athabasca Oil Sands Deposit. Issued by the Province of
Alberta, the leases are automatically renewable as long as tar sands operations
are ongoing or the leases are part of an approved development plan. Syncrude
leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30 and
31 (containing no proven reserves) are included within a development plan
approved by the Province of Alberta. There were no known previous commercial
operations on these leases prior to the start-up of operations in 1978.
The Syncrude participants agreed with the Province of Alberta, in its
capacity as lessor of Syncrude tar sands leases, on an amendment to their
revenue sharing agreement, which amendment applies from January 1, 1997. Among
other things, this amendment provided for lower royalties on certain new
production and for immediate royalty credit on capital expenditures. The
royalty was reduced to 25 percent of deemed net profits from Syncrude, as
defined in the agreement, on production in excess of 1996 levels for the period
1997 through 2001. As of January 1,
2002, a greater of 25 percent deemed net profit royalty or one percent
gross royalty applies to all Syncrude production after the deduction of new
capital expenditures.
The Government of Canada had issued an order that expired at the end of
2003 which provided for the remission of any federal income tax otherwise
payable by the participants as the result of the non-deductibility from the
income of the participants of amounts receivable by the Province of Alberta as
a royalty or otherwise with respect to Syncrude. That remission order excluded
royalty payable on production for the Aurora project.
Operations at Syncrude involve three main processes: open pit mining,
extraction of crude bitumen and upgrading of crude bitumen into synthetic crude
oil. In the Base mine (lease 17), the mining and transportation system uses
draglines, bucketwheel reclaimers and belt conveyors. In the North mine (leases
17 and 22) and in the Aurora mine (leases 10, 12 and 34), a truck, shovel and
hydrotransport system is used. The extraction facilities, which separate crude
bitumen from sand, are capable of processing approximately 495,000 tonnes
(545,000 tons) of tar sands a day, producing about 18 million cubic metres (110
million barrels) of crude bitumen a year. This represents recovery capability
of about 92 percent of the crude bitumen contained in the mined tar sands.
Crude bitumen extracted from tar sands is refined to a marketable
hydrocarbon product through a combination of carbon removal in two large, high
temperature, fluid coking vessels and by hydrogen addition in high temperature,
high pressure, hydrocracking vessels. These processes remove carbon and sulphur
and reformulate the crude into a low viscosity, low sulphur, high quality
synthetic crude oil product. In 2003, the upgrading process yielded 0.860 cubic
metres of synthetic crude oil per cubic metre of crude bitumen (0.860 barrels
of synthetic crude oil per barrel of crude bitumen). In 2003, about 55 percent
of the synthetic crude oil was processed by Edmonton area refineries and the
remaining 45 percent was pipelined to refineries in eastern Canada and the
mid-western United States. Electricity is provided to Syncrude by a 270
megawatt electricity generating plant and a 80 megawatt electricity generating
plant, both located at Syncrude. The generating plants are owned by the
Syncrude participants. The Companys 25 percent share of net investment in
plant, property and equipment, including surface mining facilities,
transportation equipment and upgrading facilities is about $2.2 billion.
In 2003, Syncrudes net production of synthetic crude oil was about 33,300
cubic metres (209,400 barrels) per day and gross production was about 33,600
cubic metres (211,500 barrels) per day. The Companys share of net production
in 2003 was about 8,300 cubic metres (52,300 barrels) per day.
8
In 2000, Syncrude completed development of the first stage of the Aurora
mine. The Aurora investment involved extending mining operations to a new
location about 35 km from the main Syncrude site and expanding upgrading
capacity. In 2001, the Syncrude owners approved another major expansion of
upgrading capacity and further development of the Aurora mine. This project is
expected to lead to a total production capacity of about 55,600 cubic metres
(350,000 barrels) of synthetic crude oil a day with expected completion in
mid-2006. The Companys share of project costs is expected to be about $2
billion.
The following table sets forth certain operating statistics for the Syncrude
operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
1999 |
|
|
|
|
|
|
|
|
|
|
|
|
Total mined volume (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of cubic metres |
|
|
83.5 |
|
|
|
77.9 |
|
|
|
90.3 |
|
|
|
65.0 |
|
|
|
76.5 |
|
|
millions of cubic yards |
|
|
109.2 |
|
|
|
102.0 |
|
|
|
118.3 |
|
|
|
85.1 |
|
|
|
100.1 |
|
Mined volume to tar sands ratio (1) |
|
|
1.15 |
|
|
|
1.05 |
|
|
|
1.15 |
|
|
|
0.96 |
|
|
|
0.99 |
|
Tar sands mined |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of tonnes |
|
|
152.4 |
|
|
|
156.5 |
|
|
|
164.8 |
|
|
|
142.2 |
|
|
|
162.1 |
|
|
millions of tons |
|
|
168.0 |
|
|
|
172.1 |
|
|
|
181.2 |
|
|
|
156.4 |
|
|
|
178.7 |
|
Average bitumen grade (weight percent) |
|
|
11.0 |
|
|
|
11.2 |
|
|
|
11.0 |
|
|
|
11.0 |
|
|
|
10.8 |
|
Crude bitumen in mined tar sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of tonnes |
|
|
16.8 |
|
|
|
17.5 |
|
|
|
18.1 |
|
|
|
15.6 |
|
|
|
17.5 |
|
|
millions of tons |
|
|
18.5 |
|
|
|
19.2 |
|
|
|
19.9 |
|
|
|
17.2 |
|
|
|
19.3 |
|
Average extraction recovery (percent) |
|
|
88.6 |
|
|
|
89.9 |
|
|
|
87.0 |
|
|
|
89.7 |
|
|
|
91.4 |
|
Crude bitumen production (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of cubic metres |
|
|
14.7 |
|
|
|
15.5 |
|
|
|
15.5 |
|
|
|
13.8 |
|
|
|
15.8 |
|
|
millions of barrels |
|
|
92.3 |
|
|
|
97.8 |
|
|
|
97.6 |
|
|
|
86.8 |
|
|
|
99.6 |
|
Average upgrading yield (percent) |
|
|
86.0 |
|
|
|
86.3 |
|
|
|
84.5 |
|
|
|
84.3 |
|
|
|
83.9 |
|
Gross synthetic crude oil produced |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of cubic metres |
|
|
12.5 |
|
|
|
13.5 |
|
|
|
13.1 |
|
|
|
11.6 |
|
|
|
13.3 |
|
|
millions of barrels |
|
|
78.4 |
|
|
|
84.8 |
|
|
|
82.4 |
|
|
|
73.2 |
|
|
|
83.6 |
|
Companys net share (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of cubic metres |
|
|
3 |
|
|
|
3 |
|
|
|
3 |
|
|
|
2 |
|
|
|
3 |
|
|
millions of barrels |
|
|
19 |
|
|
|
21 |
|
|
|
19 |
|
|
|
15 |
|
|
|
20 |
|
(1) |
|
Includes pre-stripping of mine areas and reclamation volumes. |
|
(2) |
|
Crude bitumen production is equal to crude bitumen in mined tar sands
multiplied by the average extraction recovery and the appropriate conversion
factor. |
|
(3) |
|
Reflects the Companys 25 percent interest in production, less applicable
royalties payable to the Province of Alberta. |
Other Tar Sands Activity
The Company holds a 100 percent interest in approximately 16,500 hectares
(40,700 acres) of surface mineable tar sands in the Kearl area in the Athabasca
area of northern Alberta. The Company is assessing a potential project with
another company to jointly develop mineable bitumen. A 200 well delineation
drilling program was begun in 2003 to better define the available resource. A
phased project is being assessed which may have the potential to produce up to
a total of 31,800 cubic metres (200,000 barrels) per day.
9
Land Holdings
At December 31, 2003 and 2002, the Company held the following oil and gas
rights, and tar sands leases:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Hectares |
|
Acres |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed |
|
Undeveloped |
|
Total |
|
Developed |
|
Undeveloped |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2002 |
|
2003 |
|
2002 |
|
2003 |
|
2002 |
|
2003 |
|
2002 |
|
2003 |
|
2002 |
|
2003 |
|
2002 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(thousands) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western Provinces Conventional
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
1,101 |
|
|
|
1,109 |
|
|
|
187 |
|
|
|
205 |
|
|
|
1,288 |
|
|
|
1,314 |
|
|
|
2,721 |
|
|
|
2,740 |
|
|
|
462 |
|
|
|
507 |
|
|
|
3,183 |
|
|
|
3,247 |
|
|
|
|
|
Net (2) |
|
|
450 |
|
|
|
454 |
|
|
|
127 |
|
|
|
139 |
|
|
|
577 |
|
|
|
593 |
|
|
|
1,112 |
|
|
|
1,122 |
|
|
|
314 |
|
|
|
343 |
|
|
|
1,426 |
|
|
|
1,465 |
|
Oil Sands (Cold Lake and other) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
42 |
|
|
|
41 |
|
|
|
175 |
|
|
|
200 |
|
|
|
217 |
|
|
|
241 |
|
|
|
104 |
|
|
|
101 |
|
|
|
432 |
|
|
|
494 |
|
|
|
536 |
|
|
|
595 |
|
|
|
|
|
Net (2) |
|
|
41 |
|
|
|
41 |
|
|
|
104 |
|
|
|
114 |
|
|
|
145 |
|
|
|
155 |
|
|
|
101 |
|
|
|
101 |
|
|
|
257 |
|
|
|
282 |
|
|
|
358 |
|
|
|
383 |
|
Tar Sands (Syncrude and other) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
41 |
|
|
|
20 |
|
|
|
77 |
|
|
|
98 |
|
|
|
118 |
|
|
|
118 |
|
|
|
101 |
|
|
|
49 |
|
|
|
190 |
|
|
|
242 |
|
|
|
291 |
|
|
|
291 |
|
|
|
|
|
Net (2) |
|
|
10 |
|
|
|
10 |
|
|
|
32 |
|
|
|
32 |
|
|
|
42 |
|
|
|
42 |
|
|
|
25 |
|
|
|
25 |
|
|
|
79 |
|
|
|
79 |
|
|
|
104 |
|
|
|
104 |
|
Canada Lands (3): Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
31 |
|
|
|
31 |
|
|
|
321 |
|
|
|
396 |
|
|
|
352 |
|
|
|
427 |
|
|
|
77 |
|
|
|
77 |
|
|
|
793 |
|
|
|
979 |
|
|
|
870 |
|
|
|
1,056 |
|
|
|
|
|
Net (2) |
|
|
4 |
|
|
|
4 |
|
|
|
98 |
|
|
|
150 |
|
|
|
102 |
|
|
|
154 |
|
|
|
10 |
|
|
|
10 |
|
|
|
242 |
|
|
|
371 |
|
|
|
252 |
|
|
|
381 |
|
Atlantic Offshore: Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
17 |
|
|
|
17 |
|
|
|
1,329 |
|
|
|
1,329 |
|
|
|
1,346 |
|
|
|
1,346 |
|
|
|
42 |
|
|
|
42 |
|
|
|
3,284 |
|
|
|
3,284 |
|
|
|
3,326 |
|
|
|
3,326 |
|
|
|
|
|
Net (2) |
|
|
2 |
|
|
|
2 |
|
|
|
565 |
|
|
|
565 |
|
|
|
567 |
|
|
|
567 |
|
|
|
5 |
|
|
|
5 |
|
|
|
1,396 |
|
|
|
1,396 |
|
|
|
1,401 |
|
|
|
1,401 |
|
Total (4): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
1,232 |
|
|
|
1,218 |
|
|
|
2,089 |
|
|
|
2,228 |
|
|
|
3,321 |
|
|
|
3,446 |
|
|
|
3,045 |
|
|
|
3,009 |
|
|
|
5,161 |
|
|
|
5,506 |
|
|
|
8,206 |
|
|
|
8,515 |
|
|
|
|
|
Net (2) |
|
|
507 |
|
|
|
511 |
|
|
|
926 |
|
|
|
1,000 |
|
|
|
1,433 |
|
|
|
1,511 |
|
|
|
1,253 |
|
|
|
1,263 |
|
|
|
2,288 |
|
|
|
2,471 |
|
|
|
3,541 |
|
|
|
3,734 |
|
(1) |
|
Gross hectares or acres include the interests of
others. |
|
(2) |
|
Net hectares or acres exclude the interests of others. |
|
(3) |
|
Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and
Other Northwest Territories, Nunavut and the Yukon. |
|
(4) |
|
Certain land holdings are subject to modification under agreements whereby
others may earn interests in the Companys holdings by performing certain
exploratory work (farmout) and whereby the Company may earn interests in
others holdings by performing certain exploratory work (farmin). |
Exploration and Development
The Company has been involved in the exploration for and development of
petroleum and natural gas in the Western Provinces, in the Canada Lands (which
include the Arctic Islands, the Beaufort Sea/Mackenzie Delta, and Other
Northwest Territories, Nunavut and the Yukon) and in the Atlantic Offshore.
The Companys exploration strategy in the Western Provinces is to search
for hydrocarbons on its existing land holdings and especially near established
facilities. Higher risk areas are evaluated through shared ventures with other
companies.
The following table sets forth the conventional and oil sands net
exploratory and development wells that were drilled or participated in by the
Company during the five years ended December 31, 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2002 |
|
2001 |
|
2000 |
|
1999 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Western and Atlantic Provinces: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas |
|
|
3 |
|
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
|
|
3 |
|
|
|
|
Dry Holes |
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
Development |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
4 |
|
|
|
1 |
|
|
|
17 |
|
|
|
18 |
|
|
|
3 |
|
|
|
|
Gas |
|
|
89 |
|
|
|
42 |
|
|
|
68 |
|
|
|
49 |
|
|
|
33 |
|
|
|
|
Dry Holes |
|
|
3 |
|
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil Sands (Cold Lake and other)
Development |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
118 |
|
|
|
332 |
|
|
|
307 |
|
|
|
112 |
|
|
|
211 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
218 |
|
|
|
381 |
|
|
|
393 |
|
|
|
183 |
|
|
|
251 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The 118 oil sands development wells in 2003 were related to productivity
maintenance in existing stages at Cold Lake.
At December 31, 2003, the Company was participating in the drilling of 144
gross (90 net) exploratory and development wells.
10
Western Provinces
In 2003, the Company had a working interest in eight gross (three net)
exploratory wells and 361 gross (214 net) development wells, while retaining an
overriding royalty in an additional nine gross exploratory wells drilled by
others. The majority of the exploratory wells were directed toward extending
reserves around existing fields.
Beaufort Sea/Mackenzie Delta
Substantial quantities of gas have been found by the Company and others in
the Beaufort Sea/Mackenzie Delta.
In 1999, the Company and three other companies entered into an agreement
to study the feasibility of developing Mackenzie Delta gas. The four companies
are participating in development planning for onshore natural gas resources
totalling approximately 170 billion cubic metres (six trillion cubic feet). The
Companys share of these resources is about 50 percent. The commercial
viability of these natural gas resources, and the pipeline required to
transport this natural gas to markets, is dependent on a number of factors.
These factors include natural gas markets, support from northern parties,
regulatory approvals, environmental considerations, pipeline participation,
fiscal terms, and the cost of constructing, operating and abandoning the field
production and pipeline facilities. There are complex issues to be resolved and
many interested parties to be consulted, before any development could proceed.
In October 2001, the four companies and the Aboriginal Pipeline Group (APG),
which represents aboriginal peoples of the Northwest Territories, signed a
memorandum of understanding to pursue economic and timely development of a
Mackenzie Valley pipeline. In 2002, the four companies completed a preliminary
study of the feasibility of developing existing discoveries
of Mackenzie Delta gas and based on the results of the study announced
together with the APG their intention to begin preparing the regulatory
applications needed to develop the gas resources, including construction of a
Mackenzie Valley pipeline. In 2003, the Preliminary Information Package for the
Mackenzie Gas Project was submitted to the regulatory authorities, and funding
and participation agreements between the four companies, the APG and
TransCanada PipeLines Limited were reached for the proposed Mackenzie Valley
pipeline. In late 2003, the application for Commercial Discovery Declaration
for the Taglu field was filed with the National Energy Board. This filing was
the next regulatory step towards bringing natural gas from the Taglu field into
production. Filing of the main regulatory applications for the project, the
next major step in the process, is expected to take place in 2004.
In 2003, the Company relinquished its 86 percent interest in a petroleum
and natural gas lease with the Inuvialuit Land Corporation. Other land holdings
include majority interests in 20 and minority interests in six significant
discovery licences granted by the Government of Canada as the result of
previous oil and gas discoveries, all of which are managed by the Company and
majority interests in two and minority interests in 16 other significant
discovery licences and one production licence, managed by others.
Arctic Islands
The Company has an interest in 16 significant discovery licences and one
production licence granted by the Government of Canada in the Arctic Islands.
These licences are managed by another company on behalf of all participants.
The Company has not participated in wells drilled in this area since 1984.
Atlantic Offshore
The Company manages five significant discovery licences granted by the
Government of Canada in the Atlantic offshore. The Company also has minority
interests in 27 significant discovery licences, and four production licences,
managed by others.
The Company has a nine percent working interest in an exploration licence
for about 74,000 gross hectares (183,000 gross acres) in the Sable Island area
off the coast of the Province of Nova Scotia. An exploratory well was completed
in 2001 in this area, without commercial success.
In 1998, the Company acquired a 20 percent interest in an exploration
licence for about 23,500 gross hectares (58,100 gross acres) in the Sable
Island area. In 1999, the Company acquired a 20 percent interest in six
exploration licences for about 217,000 gross hectares (536,000 gross acres) in
the Sable Island area. One exploratory well was completed in 2000 in that area,
without commercial success. Also in 1999, the Company acquired a 100 percent
interest in two exploration licences for about 225,000 gross hectares (556,000
gross acres) farther offshore in deeper water. A 3-D seismic evaluation program
was begun in 2000 in that area, which was completed in 2001, and in 2002 there
were 3-D seismic and geological evaluations. In 2002, the Company signed a
farmout agreement with another company whereby that company will earn a 30
percent interest in these licences by participating in the first exploration
well. In 2003, one exploratory well was drilled on these licences, without
commercial success. In early 2001, the Company acquired about a 17 percent
interest in three additional deep water exploration licences for about 475,000
gross hectares (1,174,000 gross acres). The Companys share of proposed
exploration spending in these areas is about $125 million.
11
In early 2004, the Company and two other companies acquired a 25 percent
interest in eight deep water exploration licences offshore Newfoundland in the
Orphan Basin for about 2,125,000 gross hectares (5,251,000 gross acres). The
Companys share of proposed exploration spending is about $170 million with a
minimum commitment of about $40 million.
Petroleum Products
Supply
To supply the requirements of its own refineries and condensate
requirements for blending with crude bitumen, the Company supplements its own
production with substantial purchases from others.
The Company purchases domestic crude oil at freely negotiated prices from
a number of sources. Domestic purchases of crude oil are generally made under
30-day contracts. There are no domestic purchases of crude oil under contracts
longer than 60 days.
Crude oil from foreign sources is purchased by the Company at competitive
prices mainly through Exxon Mobil Corporation (which has beneficial access to
major market sources of crude oil throughout the world).
Refining
The Company owns and operates four refineries. Two of these, the Sarnia
refinery and the Strathcona refinery, have lubricating oil production
facilities. The Strathcona refinery processes Canadian crude oil, and the
Dartmouth, Sarnia and Nanticoke refineries process a combination of Canadian
and foreign crude oil. In addition to crude oil, the Company purchases finished
products to supplement its refinery production.
In 2003, capital expenditures of about $336 million were made at the
Companys refineries. About 75 percent of those expenditures were on new
facilities required to meet Government of Canada regulations on the sulphur
level in motor gasoline with the remaining expenditures being on safety and
efficiency improvements, and environmental control projects.
The approximate average daily volumes of refinery throughput during the
five years ended December 31, 2003, and the daily rated capacities of the
refineries at December 31, 1998 and 2003, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Volumes of |
|
Daily Rated |
|
|
Refinery Throughput (1) |
|
Capacities at |
|
|
Year Ended December 31
|
|
December 31 (2)
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
2003
|
|
1998
|
|
|
(thousands of cubic metres) |
|
Strathcona, Alberta |
|
|
27.6 |
|
|
|
26.0 |
|
|
|
25.4 |
|
|
|
27.0 |
|
|
|
26.2 |
|
|
|
29.8 |
|
|
|
28.0 |
|
Sarnia, Ontario |
|
|
14.7 |
|
|
|
16.5 |
|
|
|
16.5 |
|
|
|
16.2 |
|
|
|
17.0 |
|
|
|
19.2 |
|
|
|
18.9 |
|
Dartmouth, Nova Scotia |
|
|
13.0 |
|
|
|
12.5 |
|
|
|
12.3 |
|
|
|
11.2 |
|
|
|
11.9 |
|
|
|
13.1 |
|
|
|
13.1 |
|
Nanticoke, Ontario |
|
|
16.3 |
|
|
|
16.2 |
|
|
|
17.2 |
|
|
|
17.2 |
|
|
|
15.0 |
|
|
|
17.8 |
|
|
|
17.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
71.6 |
|
|
|
71.2 |
|
|
|
71.4 |
|
|
|
71.6 |
|
|
|
70.1 |
|
|
|
79.9 |
|
|
|
77.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Volumes of |
|
Daily Rated |
|
|
Refinery Throughput (1) |
|
Capacities at |
|
|
Year Ended December 31
|
|
December 31 (2)
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
2003
|
|
1998
|
|
|
|
(thousands of barrels) |
|
Strathcona, Alberta |
|
|
174 |
|
|
|
163 |
|
|
|
160 |
|
|
|
170 |
|
|
|
165 |
|
|
|
187 |
|
|
|
176 |
|
Sarnia, Ontario |
|
|
92 |
|
|
|
104 |
|
|
|
104 |
|
|
|
102 |
|
|
|
107 |
|
|
|
121 |
|
|
|
119 |
|
Dartmouth, Nova Scotia |
|
|
82 |
|
|
|
78 |
|
|
|
77 |
|
|
|
70 |
|
|
|
75 |
|
|
|
82 |
|
|
|
82 |
|
Nanticoke, Ontario |
|
|
102 |
|
|
|
102 |
|
|
|
108 |
|
|
|
108 |
|
|
|
94 |
|
|
|
112 |
|
|
|
112 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
450 |
|
|
|
447 |
|
|
|
449 |
|
|
|
450 |
|
|
|
441 |
|
|
|
502 |
|
|
|
489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Refinery throughput is the volume of crude oil and feedstocks that is
processed in the refinery atmospheric distillation units. |
|
|
(2) |
|
Rated capacities are based on definite specifications as to types of crude
oil and feedstocks that are processed in the refinery atmospheric distillation
units, the products to be obtained and the refinery process, adjusted to
include an estimated allowance for normal maintenance shutdowns. Accordingly,
actual capacities may be higher or lower than rated capacities due to changes
in refinery operation and the type of crude oil available for processing. |
Refinery throughput was 90 percent of capacity in 2003, the same as for the
previous year.
12
Distribution
The Company maintains a nation-wide distribution system, including 29
primary terminals, to handle bulk and packaged petroleum products moving from
refineries to market by pipeline, tanker, rail and road transport. The Company
owns and operates crude oil, natural gas liquids and products pipelines in
Alberta, Manitoba and Ontario and has interests in the capital stock of two
products and three crude oil pipeline companies.
At December 31, 2003, the Company owned and operated two barges. These
vessels are used primarily for domestic transportation of refined petroleum
products.
Marketing
The Company markets more than 700 petroleum products throughout Canada
under well known brand names, notably Esso, to all types of customers.
The Company sells to the motoring public through approximately 2,100 Esso
retail outlets, of which about 820 are Company owned or leased, but none of
which are Company operated. The Company continues to improve its Esso retail
outlet network, providing more customer services such as car washes and
convenience stores, primarily at high volume sites in urban centres.
The Canadian farm, residential heating and small commercial markets are
served through about 100 sales facilities, of which about 40 also sell
fertilizers to the western Canadian farm markets. A major program to improve
the productivity of the Companys rural agency marketing network was largely
completed in 2002. The three year $50 million project transformed the rural
network from more than 300 bulk fuel locations to less than 100 sites supplied
by a more efficient transportation system. The final component of the new
network, a centralized order management process to better meet customer needs
was completed in 2003.
Heating oil is provided through authorized dealers as well as through
three Company operated Home Comfort facilities in urban markets. The Company
also sells petroleum products to large industrial and commercial accounts as
well as to other refiners and marketers.
The approximate daily volumes of petroleum products sold during the five
years ended December 31, 2003 are set out in the following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(thousands per day) |
Gasolines: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
33.0 |
|
|
|
32.9 |
|
|
|
32.3 |
|
|
|
32.0 |
|
|
|
31.9 |
|
Barrels |
|
|
208 |
|
|
|
207 |
|
|
|
203 |
|
|
|
201 |
|
|
|
201 |
|
Heating, Diesel and Jet Fuels: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
26.2 |
|
|
|
25.0 |
|
|
|
26.5 |
|
|
|
27.5 |
|
|
|
26.9 |
|
Barrels |
|
|
165 |
|
|
|
157 |
|
|
|
166 |
|
|
|
173 |
|
|
|
169 |
|
Heavy Fuel Oils: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
5.4 |
|
|
|
4.9 |
|
|
|
5.4 |
|
|
|
5.1 |
|
|
|
4.6 |
|
Barrels |
|
|
34 |
|
|
|
31 |
|
|
|
34 |
|
|
|
32 |
|
|
|
29 |
|
Lube Oils and Other Products (1): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
5.8 |
|
|
|
6.4 |
|
|
|
5.4 |
|
|
|
5.0 |
|
|
|
5.8 |
|
Barrels |
|
|
36 |
|
|
|
41 |
|
|
|
34 |
|
|
|
31 |
|
|
|
36 |
|
Net petroleum product sales: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
70.4 |
|
|
|
69.2 |
|
|
|
69.6 |
|
|
|
69.6 |
|
|
|
69.2 |
|
Barrels |
|
|
443 |
|
|
|
436 |
|
|
|
437 |
|
|
|
437 |
|
|
|
435 |
|
Sales under purchase and sale agreements: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
14.6 |
|
|
|
13.9 |
|
|
|
11.6 |
|
|
|
10.7 |
|
|
|
10.8 |
|
Barrels |
|
|
92 |
|
|
|
87 |
|
|
|
73 |
|
|
|
67 |
|
|
|
68 |
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
85.0 |
|
|
|
83.1 |
|
|
|
81.2 |
|
|
|
80.3 |
|
|
|
80.0 |
|
Barrels |
|
|
535 |
|
|
|
523 |
|
|
|
510 |
|
|
|
504 |
|
|
|
503 |
|
|
(1) |
|
Includes 1.0 thousand cubic metres (6 thousand barrels) per day of
butane commencing in 2002. Butane is not included in prior years. |
The total domestic sales of petroleum products as a percentage of total
sales of petroleum products during the five years ended December 31, 2003, were
as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
93.3 |
% |
|
|
91.5 |
% |
|
|
93.4 |
% |
|
|
94.0 |
% |
|
|
95.6 |
% |
The Company continues to evaluate and adjust its Esso retail outlet and
distribution system to increase productivity and efficiency.
During 2003, the Company closed or debranded about 130 Esso retail sites,
about 70 of which were Company owned, and added about 80
sites. The Companys average annual throughput per Esso retail outlet was
3.4 million litres, an increase of 0.1 million litres from 2002. Average
throughput per Company owned Esso retail outlet was 5.2 million litres in 2003,
an increase of about 0.3 million litres from 2002.
13
Chemicals
The Companys Chemicals operations manufacture and market ethylene,
benzene, aromatic and aliphatic solvents, plasticizer intermediates and
polyethylene resin. Its major petrochemical and polyethylene manufacturing
operations are located in Sarnia, Ontario, adjacent to the Companys petroleum
refinery. There is also a heptene and octene plant located in Dartmouth, Nova
Scotia.
The Companys average daily sales of petrochemicals during the five years
ended December 31, 2003, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
|
(thousands per day) |
|
Petrochemicals: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Tonnes |
|
|
3.3 |
|
|
|
3.5 |
|
|
|
3.3 |
|
|
|
3.1 |
|
|
|
3.0 |
|
Tons |
|
|
3.6 |
|
|
|
3.9 |
|
|
|
3.6 |
|
|
|
3.4 |
|
|
|
3.3 |
|
Research
In 2003, the Companys research expenditures in Canada, before deduction
of investment tax credits, were $36 million, as compared with $50 million in
2002 and $37 million in 2001. Those funds were used mainly for developing
improved heavy crude oil recovery methods and better lubricants.
A research facility to support the Companys natural resources operations
is located in Calgary, Alberta. Research in these laboratories is aimed at
developing new technology for the production and processing of crude bitumen.
About 40 people were involved in this type of research in 2003. The Company
also participated in bitumen recovery and processing research for tar sands
development through its interest in Syncrude, which maintains research
facilities in Edmonton, Alberta and through research arrangements with others.
In Company laboratories in Sarnia, Ontario, research is mainly conducted
on the development and improvement of lubricants. About 130 people were
employed in this type of research at the end of 2003. Also in Sarnia, there are
about 15 people engaged in new product development for the Companys and Exxon
Mobil Corporations polyethylene injection and rotational molding businesses.
The Company has scientific research agreements with affiliates of Exxon
Mobil Corporation which provide for technical and engineering work to be
performed by all parties, the exchange of technical information and the
assignment and licensing of patents and patent rights. These agreements provide
mutual access to scientific and operating data related to nearly every phase of
the petroleum and petrochemical operations of the parties.
Environmental Protection
The Company is concerned with and active in protecting the environment in
connection with its various operations. The Company works in cooperation with
government agencies and industry associations to deal with existing and to
anticipate potential environmental protection issues. In the past five years,
the Company has spent about $775 million on environmental protection and
facilities. In 2003, the Companys capital expenditures relating to
environmental protection totalled approximately $290 million, and are expected
to be about $195 million in 2004. Increased environmental expenditures over the
past two years primarily reflect spending on a project to reduce sulphur in
motor gasolines, a requirement of the Government of Canada. The total cost of
that project is expected to be about $600 million. In 2002, the Government of
Canada adopted a new regulation requiring ultra-low sulphur on-road diesel fuel
commencing in 2006 and which is to be fully implemented in 2007. Capital
expenditures on safety related projects in 2003 were approximately $20 million.
Human Resources
At December 31, 2003, the Company employed full-time approximately 6,300
persons compared with about 6,500 at the end of 2002 and 6,700 at the end of
2001. About seven percent of those employees are members of unions.
The Company continues to maintain a broad range of benefits, including
illness, disability and survivor benefits, a savings plan and pension plan.
Competition
The Canadian petroleum, natural gas and chemical industries are highly
competitive. Competition includes the search for and development of new sources
of supply, the construction and operation of crude oil and refined products
pipelines and the refining, distribution and marketing of petroleum products
and chemicals. The petroleum industry also competes with other industries in
supplying energy, fuel and other needs of consumers.
14
Government Regulation
Petroleum and Natural Gas Rights
Most of the Companys petroleum and natural gas rights were acquired from
governments, either federal or provincial. Reservations, permits or licences
are acquired from the provinces for cash and entitle the holder to obtain
leases upon completing specified work. Leases may also be acquired for cash. A
lease entitles the holder to produce petroleum or natural gas from the leased
lands. The holder of a licence relating to Canada Lands and the Atlantic
Offshore is generally required to make cash payments or to undertake specified
work or amounts of exploration expenditures in order to retain the holders
interest in the land and may become entitled to produce petroleum or natural
gas from the licenced land.
Crude Oil
Production
The maximum allowable gross production of crude oil from wells in Canada
is subject to limitation by various regulatory authorities on the basis of
engineering and conservation principles.
Exports
Export contracts of more than one year for light crude oil and petroleum
products and two years for heavy crude oil (including crude bitumen) require
the prior approval of the National Energy Board (the NEB) and the Government
of Canada.
Natural Gas
Production
The maximum allowable gross production of natural gas from wells in Canada
is subject to limitation by various regulatory authorities on the basis of
engineering and conservation principles. A permit is required from the Alberta
Energy and Utilities Board, subject to the approval of the Province of Alberta,
for the removal from Alberta of natural gas produced in that province.
Exports
The Government of Canada has the authority to regulate the export price
for natural gas and has a gas export pricing policy which accommodates export
prices for natural gas negotiated between Canadian exporters and U.S.
importers.
Exports of natural gas from Canada require approval by the NEB and the
Government of Canada. The Government of Canada allows the export of natural gas
by NEB order without volume limitation for terms not exceeding 24 months.
Royalties
The Government of Canada and the provinces in which the Company produces
crude oil and natural gas impose royalties on production from lands where they
own the mineral rights. Some producing provinces also receive revenue by
imposing taxes on production from lands where they do not own the mineral
rights.
Different royalties are imposed by the Government of Canada and each of
the producing provinces. Royalties imposed by the producing provinces on crude
oil vary depending on well production volumes, selling prices, recovery methods
and the date of initial production. Royalties imposed by the producing
provinces on natural gas and natural gas liquids vary depending on well
production volumes, selling prices and the date of initial production. For
information with respect to royalty rates for Norman Wells, Cold Lake and
Syncrude, see Natural Resources Petroleum and Natural Gas Production.
Investment Canada Act
The Investment Canada Act requires Government of Canada approval, in
certain cases, of the acquisition of control of a Canadian business by an
entity that is not controlled by Canadians. In certain circumstances, the
acquisition of natural resource properties may be considered to be a
transaction that constitutes an acquisition of control of a Canadian business
requiring Government of Canada approval. The Act requires notification of the
establishment of new unrelated businesses in Canada by entities not controlled
by Canadians, but does not require Government of Canada approval except when
the new business is related to Canadas cultural heritage or national identity.
By virtue of the majority stock ownership of the Company by Exxon Mobil
Corporation, the Company is considered to be an entity which is not controlled
by Canadians.
The Company Online
The Companys website www.imperialoil.ca contains a variety of corporate
and investor information which are available free of charge, including the
Companys annual report on Form 10-K, quarterly reports on Form 10-Q and
current reports on Form 8-K and amendments to these reports. These reports are
made available as soon as reasonably practicable after they are filed or
furnished to the U.S. Securities and Exchange Commission.
15
Item 2. Properties.
Reference is made to Item 1 above, and for the reserves of the Syncrude
mining operations, reference is made to Item 8 of this report.
Item 3. Legal Proceedings.
Not applicable.
Item 4. Submission of Matters to a Vote of Security Holders.
Not applicable.
PART II
Item 5. Market for Registrants Common Equity, Related Stockholder Matters and
Issuer Purchases of Equity Securities.
Information for Security Holders Outside Canada
Cash dividends paid to shareholders resident in countries with which
Canada has an income tax convention are usually subject to a Canadian
nonresident withholding tax of 15 percent.
The withholding tax is reduced to five percent on dividends paid to a
corporation resident in the United States that owns at least 10 percent of the
voting shares of the Company.
The Company is a qualified foreign corporation for purposes of the new
reduced U.S. capital gains tax rates (15% and 5% for certain individuals) which
are applicable to dividends paid by U.S. domestic corporations and qualified
foreign corporations.
There is no Canadian tax on gains from selling shares or debt instruments
owned by nonresidents not carrying on business in Canada.
Quarterly Financial and Stock Trading Data
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
2002 |
|
|
three months ended |
|
three months ended |
|
|
Mar. 31
|
|
June 30
|
|
Sept. 30
|
|
Dec. 31
|
|
Mar. 31
|
|
June 30
|
|
Sept. 30
|
|
Dec. 31
|
Per-share information (dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividends (declared quarterly) |
|
|
0.21 |
|
|
|
0.22 |
|
|
|
0.22 |
|
|
|
0.22 |
|
|
|
0.21 |
|
|
|
0.21 |
|
|
|
0.21 |
|
|
|
0.21 |
|
Share prices (dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Toronto Stock Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
47.80 |
|
|
|
47.40 |
|
|
|
53.49 |
|
|
|
58.22 |
|
|
|
47.85 |
|
|
|
49.38 |
|
|
|
47.10 |
|
|
|
46.10 |
|
Low |
|
|
43.48 |
|
|
|
43.20 |
|
|
|
45.62 |
|
|
|
50.16 |
|
|
|
41.13 |
|
|
|
43.76 |
|
|
|
38.51 |
|
|
|
41.55 |
|
Close |
|
|
47.35 |
|
|
|
47.10 |
|
|
|
50.80 |
|
|
|
57.53 |
|
|
|
47.45 |
|
|
|
47.29 |
|
|
|
45.90 |
|
|
|
44.86 |
|
American Stock Exchange ($U.S.) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
32.20 |
|
|
|
34.99 |
|
|
|
38.79 |
|
|
|
44.75 |
|
|
|
30.33 |
|
|
|
31.85 |
|
|
|
31.09 |
|
|
|
29.31 |
|
Low |
|
|
28.25 |
|
|
|
29.94 |
|
|
|
33.04 |
|
|
|
37.24 |
|
|
|
25.83 |
|
|
|
28.15 |
|
|
|
24.00 |
|
|
|
26.61 |
|
Close |
|
|
32.14 |
|
|
|
34.92 |
|
|
|
37.21 |
|
|
|
44.42 |
|
|
|
29.84 |
|
|
|
31.19 |
|
|
|
29.00 |
|
|
|
28.70 |
|
The Companys shares are listed on the Toronto Stock Exchange and are
admitted to unlisted trading on the American Stock Exchange in New York. The
symbol on these exchanges for the Companys common shares is IMO. Share prices
were obtained from stock exchange records.
As of February 27, 2004, there were 15,422 holders of record of common shares
of the Company.
Issuer purchases of equity securities (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) Total number of shares |
|
(d) Maximum number (or appropriate |
|
|
(a) Total number |
|
|
|
|
|
purchased as part |
|
dollar value) or shares that |
|
|
of shares |
|
(b) Average price |
|
of publicly announced |
|
may yet be purchased under |
Period
|
|
purchased
|
|
paid per share
|
|
plans or programs
|
|
the plans or programs
|
October 2003
(October 1 - October 31) |
|
|
1,088,546 |
|
|
$ |
51.94 |
|
|
|
1,088,546 |
|
|
|
12,971,885 |
|
November 2003
(November 1 -November 30) |
|
|
2,343,788 |
|
|
$ |
52.08 |
|
|
|
2,343,788 |
|
|
|
10,628,097 |
|
December 2003
(December 1 - December 31) |
|
|
1,864,647 |
|
|
$ |
54.49 |
|
|
|
1,864,647 |
|
|
|
8,763,450 |
|
|
(1) |
|
The purchases were pursuant to a 12 month normal course share
purchase program that was renewed on June 23, 2003 under which the
Company may purchase up to 18,632,218 of its outstanding common share
less any shares purchased by the employee savings plan and Company
pension fund. If not previously terminated, the program will terminate
on June 22, 2004. |
16
Item 6. Selected Financial Data.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
Total revenues |
|
$ |
19,208 |
|
|
$ |
17,042 |
|
|
$ |
17,253 |
|
|
$ |
18,051 |
|
|
$ |
12,853 |
|
Net earnings |
|
|
1,682 |
|
|
|
1,224 |
|
|
|
1,255 |
|
|
|
1,410 |
|
|
|
628 |
|
Total assets |
|
|
12,361 |
|
|
|
11,894 |
|
|
|
10,781 |
|
|
|
11,244 |
|
|
|
10,828 |
|
Long term debt |
|
|
859 |
|
|
|
1,466 |
|
|
|
1,029 |
|
|
|
1,037 |
|
|
|
1,352 |
|
Other long term obligations |
|
|
972 |
|
|
|
1,207 |
|
|
|
1,098 |
|
|
|
1,104 |
|
|
|
1,172 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(dollars) |
Net earnings/share basic |
|
|
4.52 |
|
|
|
3.23 |
|
|
|
3.19 |
|
|
|
3.38 |
|
|
|
1.46 |
|
Net earnings/share diluted |
|
|
4.52 |
|
|
|
3.23 |
|
|
|
3.19 |
|
|
|
3.38 |
|
|
|
1.46 |
|
Cash dividends/share |
|
|
0.87 |
|
|
|
0.84 |
|
|
|
0.83 |
|
|
|
0.78 |
|
|
|
0.75 |
|
Reference is made to the table setting forth exchange rates for the
Canadian dollar, expressed in U.S. dollars, on page 2 of this report.
Reconciliation of Canadian and United States generally accepted accounting
principles
The financial statements of the Company have been prepared in accordance
with generally accepted accounting principles (GAAP) in Canada. These
principles conform in all material respects to those in the United States
except for the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
|
|
|
|
|
|
|
|
(millions) |
|
|
|
|
|
|
|
|
Net earnings as shown in
financial statements (a) |
|
$ |
1,682 |
|
|
$ |
1,224 |
|
|
$ |
1,255 |
|
|
$ |
1,410 |
|
|
$ |
628 |
|
Impact of U.S. accounting principles: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capitalized interest (1) |
|
|
19 |
|
|
|
4 |
|
|
|
(3 |
) |
|
|
(3 |
) |
|
|
(3 |
) |
Enacted tax rate difference (2) |
|
|
|
|
|
|
|
|
|
|
(13 |
) |
|
|
13 |
|
|
|
|
|
Restatement to reflect accounting
changes (3) |
|
|
|
|
|
|
(14 |
) |
|
|
(16 |
) |
|
|
(12 |
) |
|
|
(7 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings under U.S. GAAP before
cumulative effect of accounting change |
|
$ |
1,701 |
|
|
$ |
1,214 |
|
|
$ |
1,223 |
|
|
$ |
1,408 |
|
|
$ |
618 |
|
Cumulative effect of accounting change |
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings under U.S. GAAP (a) |
|
$ |
1,705 |
|
|
$ |
1,214 |
|
|
$ |
1,223 |
|
|
$ |
1,408 |
|
|
$ |
618 |
|
Other comprehensive income (expense), net of
tax (7): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Minimum pension liability adjustment
(net of tax expense of $57 million
in 2003;
2002 $155 million benefit; 2001
$34 million benefit; |
|
|
49 |
|
|
|
(238 |
) |
|
|
(52 |
) |
|
|
(16 |
) |
|
|
22 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income under U.S. GAAP |
|
$ |
1,754 |
|
|
$ |
976 |
|
|
$ |
1,171 |
|
|
$ |
1,392 |
|
|
$ |
640 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) Net earnings/share |
|
(dollars) |
Under accounting principles of: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada basic |
|
|
4.52 |
|
|
|
3.23 |
|
|
|
3.19 |
|
|
|
3.38 |
|
|
|
1.46 |
|
diluted |
|
|
4.52 |
|
|
|
3.23 |
|
|
|
3.19 |
|
|
|
3.38 |
|
|
|
1.46 |
|
United States basic |
|
|
4.58 |
|
|
|
3.20 |
|
|
|
3.11 |
|
|
|
3.37 |
|
|
|
1.43 |
|
diluted |
|
|
4.58 |
|
|
|
3.20 |
|
|
|
3.11 |
|
|
|
3.37 |
|
|
|
1.43 |
|
Notes (1) through (9) found on pages 18 to 20 apply to the above and following tables.
The adjustments under United States GAAP result in changes to the consolidated balance sheet of the
Company as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at |
|
As at |
|
|
December 31, 2003 |
|
December 31, 2002 |
|
|
(millions)
|
|
(millions)
|
|
|
As |
|
U.S. |
|
As |
|
U.S. |
|
|
Reported
|
|
GAAP
|
|
Reported
|
|
GAAP
|
Current assets (6) |
|
$ |
2,275 |
|
|
$ |
2,275 |
|
|
$ |
2,657 |
|
|
$ |
2,657 |
|
Future income tax assets (5) |
|
|
353 |
|
|
|
502 |
|
|
|
323 |
|
|
|
530 |
|
Investments and other long term assets (4) (6) |
|
|
259 |
|
|
|
97 |
|
|
|
134 |
|
|
|
134 |
|
Property, plant and equipment cost (1) |
|
|
19,288 |
|
|
|
19,433 |
|
|
|
18,078 |
|
|
|
18,130 |
|
Property, plant and equipment
accumulated depreciation and depletion (1) |
|
|
(10,070 |
) |
|
|
(10,166 |
) |
|
|
(9,553 |
) |
|
|
(9,610 |
) |
Goodwill |
|
|
204 |
|
|
|
204 |
|
|
|
204 |
|
|
|
204 |
|
Other intangible assets cost (4) |
|
|
87 |
|
|
|
176 |
|
|
|
81 |
|
|
|
195 |
|
accumulated depreciation
and depletion |
|
|
(35 |
) |
|
|
(35 |
) |
|
|
(30 |
) |
|
|
(30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
$ |
12,361 |
|
|
$ |
12,486 |
|
|
$ |
11,894 |
|
|
$ |
12,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(continued on the following page) |
17
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
As at |
|
As at |
|
|
December 31, 2003 |
|
December 31, 2002 |
|
|
(millions)
|
|
(millions)
|
|
|
As |
|
U.S. |
|
As |
|
U.S. |
|
|
Reported
|
|
GAAP
|
|
Reported
|
|
GAAP
|
Current liabilities (6) |
|
$ |
2,889 |
|
|
$ |
2,889 |
|
|
$ |
2,743 |
|
|
$ |
2,743 |
|
Current portion of long term debt |
|
|
501 |
|
|
|
501 |
|
|
|
|
|
|
|
|
|
Long term debt (6) |
|
|
859 |
|
|
|
859 |
|
|
|
1,466 |
|
|
|
1,466 |
|
Other long term obligations (4) |
|
|
972 |
|
|
|
1,314 |
|
|
|
1,207 |
|
|
|
1,823 |
|
Future income tax liabilities (5) |
|
|
1,362 |
|
|
|
1,378 |
|
|
|
1,262 |
|
|
|
1,267 |
|
Shareholders equity |
|
|
5,778 |
|
|
|
5,545 |
|
|
|
5,216 |
|
|
|
4,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities, deferred income taxes and
shareholders equity |
|
$ |
12,361 |
|
|
$ |
12,486 |
|
|
$ |
11,894 |
|
|
$ |
12,210 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders Equity: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares at stated value
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At beginning of year |
|
$ |
1,939 |
|
|
$ |
1,939 |
|
|
$ |
1,941 |
|
|
$ |
1,941 |
|
Share purchases at stated value (net) |
|
|
(80 |
) |
|
|
(80 |
) |
|
|
(2 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At end of year |
|
$ |
1,859 |
|
|
$ |
1,859 |
|
|
$ |
1,939 |
|
|
$ |
1,939 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Retained earnings |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At beginning of year |
|
$ |
3,277 |
|
|
$ |
3,287 |
|
|
$ |
2,382 |
|
|
$ |
2,402 |
|
Net earnings for the year |
|
|
1,682 |
|
|
|
1,705 |
|
|
|
1,224 |
|
|
|
1,214 |
|
Share purchases in excess of stated value |
|
|
(717 |
) |
|
|
(717 |
) |
|
|
(11 |
) |
|
|
(11 |
) |
Dividends |
|
|
(323 |
) |
|
|
(323 |
) |
|
|
(318 |
) |
|
|
(318 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At end of year |
|
$ |
3,919 |
|
|
$ |
3,952 |
|
|
$ |
3,277 |
|
|
$ |
3,287 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income/(loss) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At beginning of year |
|
|
|
|
|
|
(315 |
) |
|
|
|
|
|
|
(77 |
) |
Other comprehensive income for the period |
|
|
|
|
|
|
49 |
|
|
|
|
|
|
|
(238 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At end |
|
|
|
|
|
|
(266 |
) |
|
|
|
|
|
|
(315 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total shareholders equity |
|
$ |
5,778 |
|
|
$ |
5,545 |
|
|
$ |
5,216 |
|
|
$ |
4,911 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Interest expense related to major construction projects is not
required to be capitalized in Canada, as it is in the United States.
Total debt related interest expense in 2003 was $38 million of which $34
million was capitalized under U.S. GAAP. The Companys financing costs
including debt related expense are reported in note 12 to the financial
statements on page F-17. At December 31, 2003, the unamortized balance
of capitalized interest under U.S. GAAP was $49 million (2002 $21
million). This was offset in future (deferred) income taxes and
shareholders equity. |
|
(2) |
|
Under Canadian GAAP enacted income tax rates are recognized by
the introduction of the enacting legislation in the Canadian federal
parliament or provincial legislatures. Under U.S. GAAP income tax rates
are enacted when proclaimed into law. There was no enacted tax rate
difference for 2003. |
|
(3) |
|
When a change in accounting policy is applied retroactively, Canadian GAAP
require the restatement of all prior periods presented to give effect to the
new accounting policy for comparative purposes. Under U.S. GAAP, the cumulative
effect, based on a retroactive computation, is recognized in net earnings for
the period of the change. |
|
|
|
Net earnings as shown in the financial statements have been restated to reflect
the adoption of the new standard of accounting for asset retirement obligations
(ARO). The adjustment is to remove the restatement effect on earnings for all
prior periods presented. Under Canadian GAAP, the following balance sheet
accounts (as reported) have also been restated: property, plant and equipment,
other long term obligations, future income tax liabilities and retained
earnings. |
|
(4) |
|
Disclosures required under revised Statement of Financial Accounting
Standards (SFAS) No. 132 Employers Disclosures about Pensions and Other
Postretirement Benefits that are not in note 5 to the financial
statements on pages F-12 and F-13 are as follows: |
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
2003
|
|
2002
|
|
|
(millions) |
Liability recognized under Canadian GAAP |
|
$ |
(219 |
) |
|
$ |
(388 |
) |
Prepaid benefit cost recognized under Canadian GAAP |
|
|
162 |
|
|
|
|
|
Intangible asset |
|
|
(89 |
) |
|
|
(114 |
) |
Accumulated other comprehensive income (before tax) |
|
|
(415 |
) |
|
|
(521 |
) |
|
|
|
|
|
|
|
|
|
Net liability recognized under U.S. GAAP |
|
$ |
(561 |
) |
|
$ |
(1,023 |
) |
|
|
|
|
|
|
|
|
|
|
|
Under Canadian GAAP, a prepaid benefit cost was recognized as funding exceeded
the book liability for the registered pension plan. Under U.S. GAAP, a minimum
pension liability adjustment was required resulting in book liability exceeding
funding and no prepaid benefit cost existed. As a result, a reclassification of
the prepaid benefit cost from investments and other long term assets to other
long term obligation was required under U.S. GAAP. |
|
|
|
An adjustment required by SFAS No. 130 remains a CanadianU.S. GAAP difference
(see note 7). |
(Continued on following page)
18
|
|
The accumulated benefit obligation for all the defined
pension plans was $3,347
million and $3,127 million at December 31, 2003 and 2002 respectively. |
|
|
|
A summary of pension plans with accumulated benefit obligation in excess of
plan assets is shown in the table below: |
|
|
|
|
|
|
|
|
|
|
|
Pension Benefits
|
|
|
2003
|
|
2002
|
|
|
(millions) |
For funded pension plans with accumulated benefit obligations
in excess of plan assets: |
|
|
|
|
|
|
|
|
Projected benefit obligations |
|
$ |
3,464 |
|
|
$ |
3,230 |
|
Accumulated benefit obligation |
|
|
3,126 |
|
|
|
2,895 |
|
Fair value of plan assets |
|
|
2,786 |
|
|
|
2,104 |
|
Accumulated benefit obligation less fair value of plan assets |
|
|
340 |
|
|
|
791 |
|
For unfunded plans covered by book reserves: |
|
|
|
|
|
|
|
|
Projected benefit obligation |
|
|
297 |
|
|
|
300 |
|
Accumulated benefit obligation |
|
|
221 |
|
|
|
232 |
|
|
|
In 2004, the Company expects to make cash contributions of about $110 million
to the pension plans. |
|
(5) |
|
Differences from the adjustments described in notes (1) and (7) result in
future (deferred) income tax liabilities (net of future income tax assets) that
are $133 million lower at December 31, 2003 than reported under Canadian GAAP
(2002 $202 million lower). |
|
(6) |
|
SFAS No. 107 Disclosures about Fair Value of Financial Instruments and
SFAS No. 133 Accounting for Derivative Instruments and Hedging Activities
requires a summary table of the fair value and related carrying amounts of
financial instruments. The estimated fair values of the Companys financial
instruments are as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
|
Carrying |
|
Fair |
|
Carrying |
|
Fair |
|
|
Amount
|
|
Value
|
|
Amount
|
|
Value
|
|
|
(millions) |
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
$ |
448 |
|
|
$ |
448 |
|
|
$ |
766 |
|
|
$ |
766 |
|
Accounts receivable |
|
|
1,315 |
|
|
|
1,315 |
|
|
|
1,348 |
|
|
|
1,348 |
|
Other long term assets (receivable) |
|
|
20 |
|
|
|
18 |
|
|
|
60 |
|
|
|
59 |
|
Liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(2,889 |
) |
|
|
(2.889 |
) |
|
|
(2,743 |
) |
|
|
(2,743 |
) |
Current portion of long term debt |
|
|
(501 |
) |
|
|
(501 |
) |
|
|
|
|
|
|
|
|
Long term debt |
|
|
(859 |
) |
|
|
(859 |
) |
|
|
(1,466 |
) |
|
|
(1,466 |
) |
|
|
The fair values of cash, marketable securities, promissory notes, accounts
receivable and current liabilities approximate recorded amounts because of the
short period to receipt or payment of cash. The fair value of the Companys
long term debt is estimated based on quoted market prices for the same or
similar issues or on the current rates offered to the Company for debt of the
same duration to maturity. The fair values of other financial instruments held
by the Company are estimated primarily by discounting future cash flows using
current rates for similar financial instruments under similar credit risk and
maturity conditions. |
|
|
|
No significant energy derivatives, foreign exchange forward contracts or
currency and interest rate swaps were transacted by the Company in the past
three years. |
|
|
|
Letters of credit and guarantees that are outstanding have not been included in
the above table because the fair value of these commitments, determined either
by the fees charged to enter into similar agreements or the expected amount
required to settle these instruments, is not material. |
|
(7) |
|
SFAS No. 130, Reporting Comprehensive Income, adopted for U.S. GAAP
reporting, requires that changes in the balances of items in equity from
non-shareholder sources be reported in a financial statement as other
comprehensive income (loss). The item of comprehensive income (loss) that
applies to the Company is the equity adjustment for minimum pension liability
as required by SFAS No. 87. The $49 million gain recognized in 2003 (2002
$238 million loss; 2001 $52 million loss) represents a reduction of the
additional pension liability under U.S. GAAP in the current period. |
|
(8) |
|
SFAS No. 148 Accounting for Stock-Based Compensation Transition and
Disclosure provides alternative methods of transition for a voluntary change
to the fair value based method of accounting for stock based employee
compensation. In addition, the disclosure requirements under SFAS No. 148
require more prominent disclosures in the financial statements about the method
of accounting for stock based employee compensation and the effect of the
method used on reported results. |
(Continued on following page)
19
|
|
Effective January 1, 2003, the Company adopted for all stock-based compensation
granted after that date the fair value based recognition provisions as
prescribed by SFAS No. 123 Accounting for Stock Based Compensation. The
following information on stock based compensation meets the new disclosure
requirements under SFAS No. 148. |
|
|
|
Stock based compensation |
|
|
|
The Company accounts for its stock based compensation programs, except for the
stock option plan, under the fair value based recognition provisions of SFAS
No. 123. Under the fair value based method, compensation expense related to the
units of these programs is recorded in the consolidated statement of earnings
over the vesting period. The Company accounts for its stock option plan by
using the intrinsic value method as permitted by SFAS No. 123, and does not
recognize compensation expense on the issuance of stock options as long as the
exercise price is equal to the market value at date of grant. The Companys
incentive compensation programs are described in note 8 to the financial
statements on page F-15. |
|
|
|
If the provisions of SFAS No. 123 had been adopted for all prior years, the
impact on compensation expense, net earnings and earnings per share would have
been as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
(millions) |
Net earnings as shown in financial statements |
|
$ |
1,682 |
|
|
$ |
1,224 |
|
|
$ |
1,255 |
|
Stock-based compensation expense as reported, net of tax |
|
|
78 |
|
|
|
24 |
|
|
|
30 |
|
Stock-based compensation expense, net of tax,
determined under fair value based method |
|
|
(83 |
) |
|
|
(40 |
) |
|
|
(30 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Pro forma net earnings |
|
$ |
1,677 |
|
|
$ |
1,208 |
|
|
$ |
1,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings/share: |
|
|
|
|
|
(dollars) |
|
|
|
|
As reported basic and diluted |
|
|
4.52 |
|
|
|
3.23 |
|
|
|
3.19 |
|
Pro forma basic and diluted |
|
|
4.51 |
|
|
|
3.19 |
|
|
|
3.19 |
|
(9) |
|
In December 2003, the Financial Accounting Standards Board issued a
revised interpretation No. 46 (FIN 46), Consolidation of Variable
Interest Entities, replacing the original interpretation issued in
January 2003. FIN 46 provides guidance on when certain entities should
be consolidated or the interests in those entities should be disclosed
by enterprises that do not control them through majority voting
interest. Under FIN 46, entities are required to be consolidated by
enterprises that lack majority voting interest when equity investors of
those entities have insignificant capital at risk or they lack voting
rights, the obligation to absorb expected losses, or the right to
receive expected returns. Entities identified with these characteristics
are called variable interest entities and the interests that enterprises
have in these entities are called variable interests. These interests
can derive from certain guarantees, leases, loans, or other arrangements
that result in risks and rewards that are disproportionate to the voting
interests in the entities. |
|
|
|
The provisions of FIN 46 must be immediately applied for variable interest
entities created after January 31, 2003 and for variable interests in
entities commonly referred to as special purpose entities. For all other
variable interest entities, implementation is required by March 31, 2004. |
|
|
|
This interpretation does not have an impact on the Company as the Company
does not have a variable interest in any variable interest entities created
before or after January 31, 2003. |
Frequently used financial terms
Listed below are definitions of three of the Companys frequently used
financial performance measures. The definitions are provided to facilitate
understanding of the terms and how they are calculated. These terms do not have
any standardized meaning prescribed by Canadian generally accepted accounting
principles (GAAP) and may not be calculated in the same way as similar measures
are by other companies.
Capital employed
Capital employed is a measure of net investment. When viewed from the
perspective of how capital is used by the business, it includes the Companys
property, plant and equipment and other assets, less liabilities, excluding
both short term and long term debt. When viewed from the perspective of the
sources of capital employed for the total company, it includes total debt and
shareholders equity. Both of these views include the Companys share of
amounts applicable to equity companies.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
(millions) |
Business uses: asset and liability perspective
Total assets |
|
$ |
12,361 |
|
|
$ |
11,894 |
|
|
$ |
10,781 |
|
Less: total current liabilities excluding short-term debt and
current portion of long-term debt |
|
|
(2,817 |
) |
|
|
(2,671 |
) |
|
|
(2,565 |
) |
Less: total long-term liabilities excluding long-term debt |
|
|
(2,334 |
) |
|
|
(2,469 |
) |
|
|
(2,404 |
) |
Add: Imperials share of debt-financed equity company net
assets |
|
|
52 |
|
|
|
49 |
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital employed |
|
$ |
7,262 |
|
|
$ |
6,803 |
|
|
$ |
5,841 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Continued on following page)
20
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
(millions) |
Total company sources: debt and equity perspective |
|
|
|
|
|
|
|
|
|
|
|
|
Short-term debt |
|
$ |
72 |
|
|
$ |
72 |
|
|
$ |
460 |
|
Current portion of long-term debt |
|
|
501 |
|
|
|
|
|
|
|
|
|
Long-term debt |
|
|
859 |
|
|
|
1,466 |
|
|
|
1,029 |
|
Shareholders equity |
|
|
5,778 |
|
|
|
5,216 |
|
|
|
4,323 |
|
Add: Imperials share of equity company debt |
|
|
52 |
|
|
|
49 |
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital employed |
|
$ |
7,262 |
|
|
$ |
6,803 |
|
|
$ |
5,841 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating costs
Operating costs are the combined total of operating, selling, general,
exploration, depreciation and depletion expenses from the consolidated
statement of earnings and the Companys share of similar costs for equity
companies. Operating costs are the costs incurred during the period to produce,
manufacture and otherwise prepare the Companys products for sale including
staffing, maintenance, and other costs to explore for and produce oil and gas
and operate refining and chemical plants. Delivery costs to customers and
marketing expenses are also included. Operating costs exclude the cost of raw
materials and those costs incurred in bringing inventory to its existing
condition and final storage prior to delivery to a customer. These expenses are
on a before tax basis. While the Companys management is responsible for all
revenue and expense elements of net earnings, particular focus is placed on
managing the controllable aspects of this group of expenses.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
(millions) |
Expenses (from page F-3) |
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
$ |
55 |
|
|
$ |
30 |
|
|
$ |
45 |
|
Operating |
|
|
2,025 |
|
|
|
1,865 |
|
|
|
1,830 |
|
Selling and general |
|
|
1,269 |
|
|
|
1,222 |
|
|
|
1,280 |
|
Depreciation and depletion |
|
|
750 |
|
|
|
705 |
|
|
|
718 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Subtotal |
|
$ |
4,099 |
|
|
$ |
3,822 |
|
|
$ |
3,873 |
|
Imperials share of equity company expenses |
|
|
56 |
|
|
|
49 |
|
|
|
42 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total operating costs |
|
$ |
4,155 |
|
|
$ |
3,871 |
|
|
$ |
3,915 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from earnings
Cash flow from earnings is determined by adjusting net earnings for the
effects of non cash items. It measures the extent of cash generated from the
business before the effects of changes in non cash working capital and before
any investing and financing activities by the Company. Cash flow from earnings
is a measure used by the Companys management for analysis and evaluation of
operating performance and liquidity of each business segment and for future
investment decisions. A reconciliation of net earnings to cash flow from
earnings is provided in the consolidated statement of cash flows on page F-4.
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operation.
Financial Summary
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
Revenues |
|
$ |
19,208 |
|
|
$ |
17,042 |
|
|
$ |
17,253 |
|
|
$ |
18,051 |
|
|
$ |
12,853 |
|
Net earnings by segment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural resources |
|
|
1,139 |
|
|
|
1,056 |
|
|
|
957 |
|
|
|
1,177 |
|
|
|
567 |
|
Petroleum products |
|
|
407 |
|
|
|
127 |
|
|
|
353 |
|
|
|
313 |
|
|
|
15 |
|
Chemicals |
|
|
37 |
|
|
|
52 |
|
|
|
23 |
|
|
|
59 |
|
|
|
43 |
|
Corporate and other |
|
|
99 |
|
|
|
(11 |
) |
|
|
(78 |
) |
|
|
(139 |
) |
|
|
3 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
$ |
1,682 |
|
|
$ |
1,224 |
|
|
$ |
1,255 |
|
|
$ |
1,410 |
|
|
$ |
628 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets |
|
$ |
12,361 |
|
|
$ |
11,894 |
|
|
$ |
10,781 |
|
|
$ |
11,244 |
|
|
$ |
10,828 |
|
Long term debt |
|
|
859 |
|
|
|
1,466 |
|
|
|
1,029 |
|
|
|
1,037 |
|
|
|
1,352 |
|
Other long term obligations |
|
|
972 |
|
|
|
1,207 |
|
|
|
1,098 |
|
|
|
1,104 |
|
|
|
1,172 |
|
Per share information (dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share basic and diluted |
|
|
4.52 |
|
|
|
3.23 |
|
|
|
3.19 |
|
|
|
3.38 |
|
|
|
1.46 |
|
Dividends |
|
|
0.87 |
|
|
|
0.84 |
|
|
|
0.83 |
|
|
|
0.78 |
|
|
|
0.75 |
|
21
Results of operations
Net earnings in 2003 were $1,682 million or $4.52 a share the best year
on record compared with $1,224 million or $3.23 a share in 2002 (2001
$1,255 million or $3.19 a share). Higher realizations for natural gas and crude
oil and higher industry margins for petroleum products, partly offset by the
negative impact of a higher Canadian dollar, were the main reasons for the
increased earnings.
Total revenues were $19.2 billion, up about 13 percent from 2002.
Natural Resources
Earnings from natural resources were $1,139 million, up from $1,056
million in 2002 (2001 $957 million). Higher realizations for natural gas and
crude oil and higher production of Cold Lake bitumen were largely offset by the
negative impact of a higher Canadian dollar.
Resource revenues were $5.6 billion, up from $4.9 billion in 2002 (2001
$5.3 billion). The main reasons for the increase were higher prices for natural
gas and crude oil and increased production from Cold Lake.
Financial statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
Net earnings |
|
$ |
1,139 |
|
|
$ |
1,056 |
|
|
$ |
957 |
|
|
$ |
1,177 |
|
|
$ |
567 |
|
Revenues |
|
|
5,648 |
|
|
|
4,894 |
|
|
|
5,321 |
|
|
|
5,900 |
|
|
|
3,904 |
|
World oil prices strengthened considerably in early 2003 and remained
relatively strong due to a combination of world supply concerns and increased
world demand. The annual average price of Brent crude oil, the most actively
traded North Sea crude and a common benchmark of world oil markets, was $29
(U.S.) a barrel in 2003, compared with $25 in 2002 (2001 $24.50).
The increase in the Companys realizations on sales of conventional
Canadian crude oil was diminished by the strengthening of the Canadian dollar.
Average realizations during the year were $40.10 (Cdn) a barrel versus $36.81
in 2002 (2001 $35.56).
Average prices for Canadian heavy crude oil were higher in 2003, but not
as high as those for lighter crude oil, as increased supply of Canadian heavy
crude oil widened the average spread between light and heavy crude. The price
of Bow River, a benchmark Canadian heavy crude oil, increased by four percent
in 2003, compared with a nine percent increase in prices for Canadian light
crude oil. Average realizations for Cold Lake bitumen were about two percent
lower than the previous year, as the stronger Canadian dollar offset any price
increases.
Prices for Canadian natural gas in 2003 were higher on average than in the
previous year. The average of 30 day spot prices for natural gas at the AECO
hub in Alberta was about $6.70 a thousand cubic feet in 2003, up from $4.10 in
2002 (2001 $6.30).
The Companys average realizations on natural gas sales increased to $6.60
a thousand cubic feet from $4.02 in 2002 (2001 $5.72).
Average realizations and
prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
Conventional crude oil realizations (a barrel) |
|
$ |
40.10 |
|
|
$ |
36.81 |
|
|
$ |
35.56 |
|
|
$ |
41.52 |
|
|
$ |
24.75 |
|
Natural gas realizations (a thousand cubic feet) |
|
|
6.60 |
|
|
|
4.02 |
|
|
|
5.72 |
|
|
|
4.99 |
|
|
|
2.66 |
|
Par crude oil price at Edmonton (a barrel) |
|
|
43.93 |
|
|
|
40.44 |
|
|
|
39.64 |
|
|
|
45.02 |
|
|
|
27.80 |
|
Heavy crude oil price at Hardisty
(Bow River, a barrel) |
|
|
33.00 |
|
|
|
31.85 |
|
|
|
25.11 |
|
|
|
34.49 |
|
|
|
23.51 |
|
Gross production of crude oil and natural gas liquids (NGLs) increased to
256,000 barrels a day from 247,000 barrels in 2002 (2001 267,000). Net
production increased slightly to 225,000 barrels a day from 223,000 barrels in
2002 (2001 237,000).
Net bitumen production at the Companys wholly owned facilities at Cold
Lake increased to 116,000 barrels a day from 106,000 barrels in 2002 (2001
121,000). The higher volume was a result of the initial production cycles from
phases 11 13, which began operation in December 2002. This was offset in part
by lower production from existing operations, due to the cyclic nature of
production at Cold Lake.
The effective royalty rate on Cold Lake production increased in 2003, as
capital expenditures were lower upon the completion of phases 11 13. The rate
increased to 10 percent of production from five percent in 2002 (2001 five
percent).
22
Production from the Syncrude operation, in which the Company has a 25
percent interest, decreased during 2003 as increased unplanned maintenance
affected production through much of the year. Gross production of upgraded
crude oil dropped to 211,000 barrels a day from 229,000 barrels in 2002 (2001
223,000). The Companys share of average net production decreased to 52,000
barrels a day from 57,000 barrels in 2002 (2001 52,000).
Net production of conventional oil decreased to 35,000 barrels a day from
39,000 barrels in 2002 (2001 42,000) as a result of the natural decline in
western Canadian reservoirs.
Gross production of natural gas decreased to 513 million cubic feet a day
from 530 million in 2002 (2001 572 million). Net production was 457 million
cubic feet a day in 2003, down from 463 million in 2002 (2001 466 million).
Net production available for sale decreased to 390 million cubic feet a day
from 396 million in 2002 (2001 376 million). Lower production as a result of
reservoir decline was mostly offset by production from the new facilities at
Wizard Lake in Alberta, which were completed in the third quarter of 2003.
Crude oil and NGLs
production and sales (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
gross
|
|
net
|
|
gross
|
|
net
|
|
gross
|
|
net
|
|
gross
|
|
net
|
|
gross
|
|
net
|
|
|
(thousands of barrels a day) |
Conventional crude oil |
|
|
46 |
|
|
|
35 |
|
|
|
51 |
|
|
|
39 |
|
|
|
55 |
|
|
|
42 |
|
|
|
60 |
|
|
|
46 |
|
|
|
65 |
|
|
|
51 |
|
Cold Lake |
|
|
129 |
|
|
|
116 |
|
|
|
112 |
|
|
|
106 |
|
|
|
128 |
|
|
|
121 |
|
|
|
119 |
|
|
|
102 |
|
|
|
132 |
|
|
|
107 |
|
Syncrude |
|
|
53 |
|
|
|
52 |
|
|
|
57 |
|
|
|
57 |
|
|
|
56 |
|
|
|
52 |
|
|
|
51 |
|
|
|
42 |
|
|
|
56 |
|
|
|
55 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total crude oil production |
|
|
228 |
|
|
|
203 |
|
|
|
220 |
|
|
|
202 |
|
|
|
239 |
|
|
|
215 |
|
|
|
230 |
|
|
|
190 |
|
|
|
253 |
|
|
|
213 |
|
NGLs available for sale (b) |
|
|
28 |
|
|
|
22 |
|
|
|
27 |
|
|
|
21 |
|
|
|
28 |
|
|
|
22 |
|
|
|
30 |
|
|
|
23 |
|
|
|
31 |
|
|
|
24 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total crude oil and NGL production |
|
|
256 |
|
|
|
225 |
|
|
|
247 |
|
|
|
223 |
|
|
|
267 |
|
|
|
237 |
|
|
|
260 |
|
|
|
213 |
|
|
|
284 |
|
|
|
237 |
|
Cold Lake sales,including diluent (c) |
|
|
170 |
|
|
|
|
|
|
|
145 |
|
|
|
|
|
|
|
167 |
|
|
|
|
|
|
|
156 |
|
|
|
|
|
|
|
173 |
|
|
|
|
|
NGL sales |
|
|
39 |
|
|
|
|
|
|
|
40 |
|
|
|
|
|
|
|
43 |
|
|
|
|
|
|
|
42 |
|
|
|
|
|
|
|
43 |
|
|
|
|
|
Natural gas production and sales (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
gross
|
|
net
|
|
gross
|
|
net
|
|
gross
|
|
net
|
|
gross
|
|
net
|
|
gross
|
|
net
|
|
|
(millions of cubic feet a day) |
Production (d) |
|
|
513 |
|
|
|
457 |
|
|
|
530 |
|
|
|
463 |
|
|
|
572 |
|
|
|
466 |
|
|
|
526 |
|
|
|
459 |
|
|
|
469 |
|
|
|
413 |
|
Production available for sale (b) |
|
|
446 |
|
|
|
390 |
|
|
|
463 |
|
|
|
396 |
|
|
|
482 |
|
|
|
376 |
|
|
|
345 |
|
|
|
277 |
|
|
|
300 |
|
|
|
244 |
|
Sales |
|
|
460 |
|
|
|
|
|
|
|
499 |
|
|
|
|
|
|
|
502 |
|
|
|
|
|
|
|
419 |
|
|
|
|
|
|
|
393 |
|
|
|
|
|
(a) |
|
Daily volumes are calculated by dividing total volumes for the year by the
number of days in the year. Gross production is the Companys share of
production (excluding purchases) before deducting the shares of mineral owners
or governments or both. Net production excludes those shares. |
|
(b) |
|
Production available for sale excludes amounts used for internal
consumption and amounts reinjected. Starting in 2001, production available for
sale reflects a change in the supply of natural gas to Company operations from
Company produced gas to third party purchased gas. |
|
(c) |
|
Includes natural gas condensate added to the Cold Lake bitumen to
facilitate transportation to market by pipeline. |
|
(d) |
|
Production of natural gas
includes amounts used for internal consumption with the exception of amounts
reinjected. |
Operating costs increased by 11 percent in 2003. The main factors were
increased costs associated with the newly completed phases 11 13 and
cogeneration facilities at Cold Lake, unplanned maintenance at Syncrude and
increased exploration costs.
Petroleum Products
Net earnings from petroleum products were a record $407 million or 1.3
cents a litre in 2003, up from $127 million or 0.4 cents a litre in 2002 (2001
$353 million or 1.2 cents a litre). Earnings improved mainly as a result of
the strengthening of industry petroleum product margins and increased sales
volumes, partly offset by the negative impact of a higher Canadian dollar.
Revenues were $16.1 billion, up from $14.4 billion in 2002 (2001 $14.4
billion).
23
Financial statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
Net earnings |
|
$ |
407 |
|
|
$ |
127 |
|
|
$ |
353 |
|
|
$ |
313 |
|
|
$ |
15 |
|
Revenues |
|
|
16,058 |
|
|
|
14,434 |
|
|
|
14,405 |
|
|
|
15,120 |
|
|
|
10,665 |
|
Sales of petroleum products
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions of litres a day (a)) |
Gasolines |
|
|
33.0 |
|
|
|
32.9 |
|
|
|
32.3 |
|
|
|
32.0 |
|
|
|
31.9 |
|
Heating,diesel and jet fuels |
|
|
26.2 |
|
|
|
25.0 |
|
|
|
26.5 |
|
|
|
27.5 |
|
|
|
26.9 |
|
Heavy fuel oils |
|
|
5.4 |
|
|
|
4.9 |
|
|
|
5.4 |
|
|
|
5.1 |
|
|
|
4.6 |
|
Lube oils and other products |
|
|
5.8 |
|
|
|
6.4 |
|
|
|
5.4 |
|
|
|
5.0 |
|
|
|
5.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net petroleum products sales |
|
|
70.4 |
|
|
|
69.2 |
|
|
|
69.6 |
|
|
|
69.6 |
|
|
|
69.2 |
|
Sales under purchase and sale agreements |
|
|
14.6 |
|
|
|
13.9 |
|
|
|
11.6 |
|
|
|
10.7 |
|
|
|
10.8 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales of petroleum products |
|
|
85.0 |
|
|
|
83.1 |
|
|
|
81.2 |
|
|
|
80.3 |
|
|
|
80.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total domestic sales of petroleum
products (percent) |
|
|
93.3 |
|
|
|
91.5 |
|
|
|
93.4 |
|
|
|
94.0 |
|
|
|
95.6 |
|
Refinery utilization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions of litres a day (a)) |
Total refinery throughput (b) |
|
|
71.6 |
|
|
|
71.2 |
|
|
|
71.4 |
|
|
|
71.6 |
|
|
|
70.1 |
|
Refinery capacity at December 31 |
|
|
79.9 |
|
|
|
79.4 |
|
|
|
79.1 |
|
|
|
78.7 |
|
|
|
78.7 |
|
Utilization of total refinery capacity (percent) |
|
|
90 |
|
|
|
90 |
|
|
|
90 |
|
|
|
91 |
|
|
|
89 |
|
(a) |
|
Volumes a day are calculated by dividing total volumes for the year by
the number of days in the year. |
|
(b) |
|
Crude oil and feedstocks sent directly to
atmospheric distillation units |
One thousand litres is approximately 6.3 barrels.
Margins were higher in the refining segment of the industry in 2003
compared with those in 2002, as international wholesale product prices
increased more than raw material costs. However, the effects of higher
international margins were reduced partially by a higher Canadian dollar.
The Companys total sales volumes, including those resulting from
reciprocal supply agreements with other companies, were 85 million litres a
day, compared with 83.1 million litres in 2002 (2001 81.2 million). Excluding
sales resulting from reciprocal agreements, sales were 70.4 million litres a
day, compared with 69.2 million litres in 2002 (2001 69.6 million).
Operating costs increased by about five percent in 2003 from the previous
year, mainly because of higher energy costs and expenses related to increased
sales volumes.
Chemicals
Earnings from chemical operations were $37 million in 2003, down from $52
million in 2002 (2001 $23 million). Reduced industry margins on sales of
polyethylene as a result of higher feedstock costs and weaker industry demand
were the main reasons for the decrease in earnings.
Total revenues from chemical operations were $1,232 million, compared with
$1,164 million in 2002 (2001 $1,175 million). Gains from higher prices for
polyethylene, intermediate chemicals and aromatics during 2003 more than offset
lower sales volumes.
Financial statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
Net earnings |
|
$ |
37 |
|
|
$ |
52 |
|
|
$ |
23 |
|
|
$ |
59 |
|
|
$ |
43 |
|
Revenues |
|
|
1,232 |
|
|
|
1,164 |
|
|
|
1,175 |
|
|
|
1,173 |
|
|
|
872 |
|
The average industry price of polyethylene was $1,415 a tonne in 2003, up
15 percent from $1,229 a tonne in 2002 (2001 $1,284). However, margins were
reduced because of higher feedstock costs, reflecting increased prices for
natural gas.
24
Sales of chemicals decreased to 3,300 tonnes a day from 3,500 tonnes in
2002 (2001 3,300 tonnes) as a result of reduced demand.
Sales volumes
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(thousands of tonnes a day (a) |
Polymers & basic chemicals |
|
|
2.4 |
|
|
|
2.5 |
|
|
|
2.4 |
|
|
|
2.2 |
|
|
|
2.0 |
|
Intermediates and other |
|
|
0.9 |
|
|
|
1.0 |
|
|
|
0.9 |
|
|
|
0.9 |
|
|
|
1.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total chemicals |
|
|
3.3 |
|
|
|
3.5 |
|
|
|
3.3 |
|
|
|
3.1 |
|
|
|
3.0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Volumes a day are calculated by dividing total volumes for the year by
the number of days in the year. One tonne is approximately 1.1 short tons or
0.98 long tons. |
Operating costs in the chemicals segment increased by about four percent
in 2003 mainly because of higher planned capital project related expenses.
Corporate and other
Earnings from corporate and other accounts were positive $99 million in
2003, compared with negative $11 million in 2002 (2001 negative $78 million).
The improvement was mainly attributable to favourable foreign exchange effects
on the Companys U.S. dollar denominated debt. The Company retired the
remaining balance of its U.S. dollar denominated debt in 2003.
Liquidity and capital resources
Cash flow from earnings was $2,354 million, up from $1,781 million in 2002
(2001 $2,016 million), mainly because of increased earnings. Cash provided
from operating activities was $2,194 million, compared with $1,676 million in
2002 (2001 $2,004 million). The increased cash inflow was mainly due to
higher earnings, timing of scheduled income tax payments and the effects of
commodity prices on receivable and payable balances, partly offset by
additional funding contributions to the Companys registered pension plan.
In June, the Company renewed the normal course issuer bid (share buyback
program) for another 12 months. During 2003, the Company purchased more than 16
million shares for $799 million. Since the Company initiated its first buyback
program in 1995, the Company has purchased 219 million shares representing
about 38 percent of the total outstanding at the start of the program with
resulting distributions to shareholders of $5,968 million.
The Company declared dividends totalling 87 cents a share in 2003, up from
84 cents in 2002 (2001 83 cents). Regular per share dividends paid have
increased in each of the past nine years and, since 1986, payments a share have
grown by more than 55 percent.
Following one of the largest capital investment programs in the Companys
history as well as funding contributions to the Companys registered pension
plan, the cash balance was $448 million at year end, compared with $766 million
at the end of 2002 (2001 $872 million).
In 2003, the Company retired its $600 million U.S. variable rate debt, due
in 2004, for $818 million (Cdn) and replaced it with $818 million of Canadian
dollar denominated variable rate loans from Exxon Overseas Corporation at
interest equivalent to Canadian market rates.
Total debt outstanding, excluding the Companys share of equity company
debt, at the end of 2003 was $1,432 million, compared with $1,538 million at
the end of 2002 (2001 $1,489 million). Debt represented 20 percent of the
Companys capital structure at the end of 2003, compared with 23 percent at the
end of 2002 (2001 26 percent).
Debt related interest expense paid in 2003 was $38 million, down from $40
million in 2002 (2001 $77 million). The retirement of the Companys long term
fixed rate debt during the past few years was the main reason for the
reduction. The average effective interest rate on the Companys debt was 2.9
percent in 2003, compared with 2.1 percent in 2002 (2001 5.1 percent).
25
Financial percentages, ratios and credit rating
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
Total debt as a percentage of capital (a) |
|
|
20 |
|
|
|
23 |
|
|
|
26 |
|
|
|
25 |
|
|
|
24 |
|
Interest coverage ratios
Earnings basis (b) |
|
|
63 |
|
|
|
46 |
|
|
|
26 |
|
|
|
23 |
|
|
|
9 |
|
Cash flow basis (c) |
|
|
79 |
|
|
|
63 |
|
|
|
36 |
|
|
|
29 |
|
|
|
14 |
|
(a) |
|
Current and long term portions of debt (page F-5) divided by debt and
shareholders equity (page F-5). |
|
(b) |
|
Net earnings (page F-3), debt related interest expense (page F-17, note 12)
and income taxes (page F-3) divided by debt related interest expense. |
|
(c) |
|
Cash flow from earnings (page F-4), current income tax expense (page F-12,
note 4) and debt related interest expense divided by debt related interest
expense. |
Capital and exploration expenditures
Total capital and exploration expenditures were $1,526 million in 2003,
down slightly from $1,600 million in 2002 (2001 $1,115 million).
The funds were used mainly to maintain and expand crude oil and natural
gas production capacity, to upgrade refineries to meet low sulphur gasoline
requirements and to enhance the Companys retail network.
The following table shows the Companys capital and exploration
expenditures for natural resources during the five years ending December 31,
2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
Exploration |
|
$ |
57 |
|
|
$ |
39 |
|
|
$ |
49 |
|
|
$ |
56 |
|
|
$ |
29 |
|
Production |
|
|
181 |
|
|
|
143 |
|
|
|
109 |
|
|
|
110 |
|
|
|
138 |
|
Heavy oil |
|
|
769 |
|
|
|
804 |
|
|
|
588 |
|
|
|
268 |
|
|
|
263 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
1,007 |
|
|
$ |
986 |
|
|
$ |
746 |
|
|
$ |
434 |
|
|
$ |
430 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the natural resources segment, about 90 percent of the capital and
exploration expenditures in 2003 was focused on growth opportunities. The
single largest investment during the year was the Companys share of the
Syncrude expansion. The remainder of 2003 investment was directed to advancing
the Mackenzie gas project, drilling for conventional oil and gas in Western
Canada, and East Coast development and deepwater exploration.
Planned capital and exploration expenditures in natural resources are
expected to total about $1 billion in 2004, with nearly 90 percent of the total
focused on growth opportunities. Much of the expenditure will be directed to
the expansion now underway at Syncrude. Investments are also planned for the
ongoing development drilling at Cold Lake, the Mackenzie gas project,
development of the Sable South Venture field and the Sable compression
platform, as well as further development drilling in Western Canada. Planned
expenditures for exploration and development drilling, as well as capacity
additions in conventional oil and gas operations, are expected to be about $320
million.
The following table shows the Companys capital expenditures in the
petroleum products segment during the five years ending December 31, 2003:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
Marketing |
|
$ |
91 |
|
|
$ |
133 |
|
|
$ |
171 |
|
|
$ |
121 |
|
|
$ |
80 |
|
Refining and supply |
|
|
368 |
|
|
|
399 |
|
|
|
118 |
|
|
|
100 |
|
|
|
114 |
|
Other (a) |
|
|
19 |
|
|
|
57 |
|
|
|
50 |
|
|
|
11 |
|
|
|
9 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
$ |
478 |
|
|
$ |
589 |
|
|
$ |
339 |
|
|
$ |
232 |
|
|
$ |
203 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Consists primarily of purchases of real estate. |
For the petroleum product segment, capital expenditures decreased to $478
million in 2003, compared with $589 million in 2002 (2001 $339 million),
primarily because of the completion of the project to significantly reduce
sulphur content in gasoline, which began in 2001. New investments in 2003
included the products segments $32 million share of capital expenditures on a
95 megawatt cogeneration facility to improve energy efficiency and reduce
emissions at the petroleum products and chemicals operations in Sarnia. In
addition, almost $60 million was spent on other refinery projects to improve
energy efficiency and increase yield. Major investments were also made to
upgrade the network of Esso retail outlets during the year.
26
Capital expenditures for the petroleum products segment in 2004 are
expected to be about $450 million. Major items include investment in refining
facilities to reduce the sulphur content in diesel to meet regulatory
requirement and continued enhancements to the Companys retail network.
The following table shows the Companys capital expenditures for the
chemicals operations during the five years ending December 31, 2003.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
Chemicals |
|
$ |
41 |
|
|
$ |
25 |
|
|
$ |
30 |
|
|
$ |
13 |
|
|
$ |
20 |
|
Of the capital expenditures for chemicals in 2003, the major investment
was the Sarnia cogeneration project, a joint development between the petroleum
products and chemicals operations at the site.
Planned capital expenditures for chemicals in 2004 will be about $20
million. Funds will be used largely to improve energy efficiency and yields.
Total capital and exploration expenditures for the Company in 2004, which
will focus mainly on growth and productivity improvements, are expected to
total about $1.5 billion and will be financed primarily from internally
generated funds.
During 2003, the Company spent more than $310 million on projects related
to reducing the environmental impact of its operations and improving safety.
This included investments of more than $260 million in the Companys four
refineries as part of the capital project to produce low sulphur gasoline and
diesel fuels.
Reporting investments in mineral interests in oil and gas properties
The accounting standards for business combinations and goodwill and other
intangible assets issued by the Canadian Institute of Chartered Accountants
(CICA) became effective for the Company of July 1, 2001, and January 1, 2002,
respectively. These Canadian standards are harmonized with specific U.S.
standards in these areas. Currently, the Emerging Issues Task Force (EITF) of
the Financial Accounting Standards Board (FASB) is considering the issue of
whether the U.S. standards require interests held under oil, gas and mineral
leases to be separately classified as intangible assets on the balance sheets
of companies in the extractive industries. If such interests were deemed to be
intangible assets by the EITF, mineral rights to extract oil and gas for both
undeveloped and developed leaseholds would be classified separately from oil
and gas properties as intangible assets on the Companys balance sheet. The
EITF interpretation could potentially have an impact on the Canadian standards
and the Companys financial reporting. Historically, in accordance with
Canadian generally accepted accounting principles (GAAP), the Company has
capitalized the cost of oil and gas leasehold interests and reported these
assets as part of tangible oil and gas property, plant and equipment.
This interpretation of the current U.S. standards would only affect the
classification of oil and gas leaseholds on the Companys balance sheet and
would not affect total assets, net worth or cash flows. The Companys results
of operations would not be affected, since these leasehold costs would continue
to be amortized in accordance with GAAP. The amount that is subject to
reclassification as of December 31, 2003, was $935 million and $1,109 million
as of December 31, 2002.
Pension
An independent actuarial valuation of the Companys registered pension
plan was completed in 2003. As a result of the valuation, the Company
contributed $500 million to the registered pension plan. While equity markets
improved in 2003 and the Companys contribution levels increased, the Company
plans to take a measured approach to the pace of funding, within the
requirements of pension regulations. However, pension liabilities need to be
assessed in light of the Companys strong credit position and prudent financial
management. The Company has in the past and expects to continue to use its
strong balance sheet to effectively manage pension liabilities. Future funding
requirements are not expected to affect the Companys existing capital
investment plans or its ability to pursue new investment opportunities.
Contractual obligations
To more fully explain the Companys financial position, the following
table shows the Companys contractual obligations outstanding at December 31,
2003. It brings together, for easier reference, data from the consolidated
balance sheet and from individual notes to consolidated financial statements.
27
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial |
|
Payment due by period
|
|
|
statement note |
|
|
|
|
|
2005 to |
|
2009 and |
|
Total |
millions of dollars
|
|
reference
|
|
2004
|
|
2008
|
|
beyond
|
|
amount
|
Long term debt & capital leases |
|
note 3 |
|
$ |
501 |
|
|
$ |
834 |
|
|
$ |
25 |
|
|
$ |
1,360 |
|
Companys share of equity company debt |
|
|
|
|
|
|
52 |
|
|
|
|
|
|
|
|
|
|
|
52 |
|
Operating leases |
|
note 9 |
|
|
72 |
|
|
|
185 |
|
|
|
114 |
|
|
|
371 |
|
Unconditional purchase obligations (a) |
|
note 9 |
|
|
90 |
|
|
|
161 |
|
|
|
98 |
|
|
|
349 |
|
Firm capital commitments (b) |
|
note 9 |
|
|
176 |
|
|
|
13 |
|
|
|
|
|
|
|
189 |
|
Pension obligations (c) |
|
note 5 |
|
|
138 |
|
|
|
100 |
|
|
|
318 |
|
|
|
556 |
|
Asset retirement obligations (d) |
|
note 6 |
|
|
34 |
|
|
|
112 |
|
|
|
181 |
|
|
|
327 |
|
Other long term agreements (e) |
|
note 9 |
|
|
260 |
|
|
|
500 |
|
|
|
277 |
|
|
|
1,037 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
$ |
1,323 |
|
|
$ |
1,905 |
|
|
$ |
1,013 |
|
|
$ |
4,241 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Unconditional purchase obligations mainly pertain to pipeline throughput
agreements. |
|
(b) |
|
Firm capital commitments related to capital projects, shown on an
undiscounted basis, totalled approximately $189 million at the end of 2003,
compared with $284 million at year end 2002. The largest commitment outstanding
at year end 2003 was associated with the Companys share of capital projects at
Syncrude ($56 million). |
|
(c) |
|
Pension obligations represent the amount by which
accumulated benefit obligations (ABO) exceeded the fair value of plan assets.
The ABO is less than the (projected) benefit obligation shown in note 5 to the
consolidated financial statements because it does not take into account future
compensation levels. It is used instead of the projected benefit obligation
because it more truly reflects the actual benefit obligation at the end of the
year. The payments by period include expected contributions to the Companys
registered pension plan in 2004 and estimated benefit payments for unfunded
plans in all years. The term ABO used here is consistent with the definition
under Statement of Financial Accounting Standards No. 87 issued by the
Financial Accounting Standards Board. |
|
(d) |
|
Asset retirement obligations represent the discounted present value of
legal obligations associated with site restoration on the retirement of assets
with determinable useful lives. |
|
(e) |
|
Other long term agreements include primarily raw material supply and
transportation services agreements. |
Critical accounting policies
The Companys financial statements have been prepared in accordance with
Canadian generally accepted accounting principles (GAAP) and include estimates
that reflect managements best judgments. The Companys accounting and
financial reporting fairly reflect its straightforward business model. The
Company does not use financing structures for the purpose of altering
accounting outcomes or removing debt from the balance sheet. The following
summary provides further information about the critical accounting policies and
the estimates that are made by the Company to apply those policies. It should
be read in conjunction with pages F-6 to F-8.
Oil and gas and synthetic crude oil reserves
Proved oil and gas and synthetic crude oil reserves quantities are used as
the basis of calculating unit of production rates for depreciation and
evaluating for impairment. These reserves are the estimated quantities of crude
oil, natural gas and natural gas liquids that geological and engineering data
demonstrate with reasonable certainty to be recoverable in future years from
known reservoirs and deposits under existing economic and operating conditions.
The estimation of reserves is an ongoing process based on rigorous technical
evaluations and extrapolations of appropriate information.
While proved reserves have a reasonable certainty of recovery, they are
based on estimates that are subject to some variability. The variability can
result in upward or downward revisions in the previously estimated volumes of
proved reserves for existing fields due to initial
study or restudy of (1) already available geologic, reservoir or
production data, or (2) new geologic or reservoir data obtained from wells.
Revisions can also include changes associated with improved recovery projects,
fiscal terms and significant changes in development strategy, oil and gas
prices or production equipment/facility capacity. Over time, revisions of
proved reserves for the Company have generally resulted in net upward
experience based changes through effective reservoir management and the
application of new technology. While revisions are an indicator of variability,
they have had little impact on the unit of production rates of depreciation and
on impairment testing because the revisions have been small compared to the
large proved reserves base.
Retirement benefits
The Companys pension plan is managed in compliance with the requirements
of governmental authorities and meets funding levels as determined by
independent third party actuaries. Pension accounting requires explicit
assumptions regarding, among others, the discount rate for the benefit
obligations, the expected rate of return on plan assets and the long term rate
of future compensation increases. All pension assumptions are reviewed annually
by senior financial management. These assumptions are adjusted only as
appropriate to reflect long term changes in market rates and outlook. The long
term expected rate of return on plan assets of 8.25 percent used in 2003
compares to actual returns of 9.5 percent and 10 percent achieved over the last
10 and 20 year periods ending December 31, 2003. If different assumptions are
used, the expense and obligations could increase or decrease as a result. The
Companys potential exposure to change in assumptions is summarized in footnote
(e)
28
of note 5 to the consolidated financial statements. At the Company, differences
between actual returns on plan assets versus long term expected returns are not
recorded in the year the differences occur, but rather are amortized in pension
expense as permitted by GAAP, along with other actuarial gains and losses over
the expected remaining service life of employees. The Company uses the fair
value of the plan assets at year end to determine the amount of the actual gain
or loss that will be amortized and does not use a moving average value of plan
assets. Pension expense represented about one percent of total expenses in
2003.
Asset retirement obligations and other environmental liabilities
Legal obligations associated with site restoration on the retirement of
assets with determinable useful lives are recognized when they are incurred,
which is typically at the time the assets are installed. The obligations are
initially measured at fair value and discounted to present value. Over time the
discounted asset retirement obligation amount will be accreted for the change
in its present value, with this effect included in operating expense. As
payments to settle the obligations occur on an ongoing basis and will continue
over the lives of the operating assets, which can exceed 25 years, the discount
rate will be adjusted only as appropriate to reflect long term changes in
market rates and outlook. In 2003, the obligations have been discounted at six
percent and the accretion expense was $20 million, which was significantly less
than one percent of total expenses in the year. There would be no material
impact on the Companys reported financial results if a different discount rate
had been used.
Asset retirement obligations are not recognized for assets with an
indeterminate useful life. For these and non-operating assets, the Company
accrues provisions for environmental liabilities when it is probable that
obligations have been incurred and the amount can be reasonably estimated.
Asset retirement obligations and other environmental liabilities are based
on engineering estimated costs, taking into account the anticipated method and
extent of remediation consistent with legal requirements, current technology
and the possible use of the location. Since these estimates are specific to the
locations involved, there are many individual assumptions underlying the
Companys total asset retirement obligations and provision for other
environmental liabilities. While these individual assumptions can be subject to
change, none of them is individually significant to the Companys reported
financial results.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.
The Company is exposed to a variety of financial, operating and market
risks in the course of its business. Some of these risks are within the
Companys control, while others are not. For those risks that can be
controlled, specific risk management strategies are employed to reduce the
likelihood of loss. Other risks, such as changes in international commodity
prices and currency exchange rates, are beyond the Companys control. The
Companys size, strong financial position and the complementary nature of its
natural resources, petroleum products and chemicals segments help mitigate the
Companys exposure to changes in these other risks. The Companys potential
exposure to these types of risk is summarized in the table below.
The Company does not use derivative markets to speculate on the future
direction of currency or commodity prices and does not sell forward any part of
production from any business segment.
The following table shows the estimated annual effect, under current
conditions, of certain sensitivities of the Companys after tax earnings.
|
|
|
|
|
|
|
|
|
|
|
millions of dollars after tax
|
Three dollars (U.S.) a barrel change in crude oil prices |
|
|
+(- |
) |
|
|
140 |
|
Sixty cents a thousand cubic feet change in natural gas prices |
|
|
+(- |
) |
|
|
40 |
|
One cent a litre change in sales margins for total petroleum products |
|
|
+(- |
) |
|
|
180 |
|
One cents (U.S.) a pound change in sales margins for polyethylene |
|
|
+(- |
) |
|
|
8 |
|
One quarter percent decrease (increase) in short term interest rates |
|
|
+(- |
) |
|
|
2 |
|
Eight cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar |
|
|
+(- |
) |
|
|
340 |
|
The amount quoted to illustrate the impact of each sensitivity represents
a change of about 10 percent in the value of the commodity or rate in question
at the end of 2003. Each sensitivity calculation shows the impact on annual
earnings that results from a change in one factor, after tax and royalties and
holding all other factors constant. While these sensitivities are applicable
under current conditions, they may not apply proportionately to larger
fluctuations.
The sensitivity to changes in the Canadian dollar versus the U.S.dollar
increased from 2002 by about $12 million (after tax) a year for each one cent
change. This is primarily a result of the retirement of the U.S. dollar
denominated debt which had previously moderated the impact of foreign exchange
rate changes on commodity prices and product margins.
The sensitivity to changes in crude oil prices decreased from 2002 by
about $13 million (after tax) for each one U.S. dollar difference. An increase
in the value of the Canadian dollar has lessened the impact of U.S. dollar
denominated crude oil prices on the Company s revenues and earnings.
29
Item 8. Financial Statements and Supplementary Data.
Reference is made to the Index to Financial Statements on page F-1 of this
report. The reconciliation to U.S. GAAP is in Item 6 of this report.
Syncrude Mining Operations
Syncrudes crude bitumen is contained within the unconsolidated sands of
the McMurray Formation. Ore bodies are buried beneath 15 to 45 metres (50 to
150 feet) of overburden, have bitumen grades ranging from 4 to 14 weight
percent and ore thickness of 35 to 50 metres (115 to 160 feet). Estimates of
synthetic crude oil reserves are based on detailed geological and engineering
assessments of in-place crude bitumen volume, the mining plan, historical
extraction recovery and upgrading yield factors, installed plant operating
capacity and operating approval limits. The in-place volume, depth and grade
are established through extensive and closely spaced core drilling. Proven
reserves include the operating Base and North mines and the Aurora mine. In
accordance with the approved mining plan, there are an estimated 2,990 million
tonnes (3,295 million tons) of extractable tar sands, in the Base and North
mines, with an average bitumen grade of 10.4 weight percent. In addition, at
the Aurora mine, there are an estimated 3,665 million tonnes (4,050 million
tons) of extractable tar sands at an average bitumen grade of 11.3 weight
percent. After deducting royalties payable to the Province of Alberta, the
Company estimates its 25 percent net share of proven reserves is equivalent to
124 million cubic metres (781 million barrels) of synthetic crude oil.
The following table sets forth the Companys share of net proven reserves
of Syncrude after deducting royalties payable to the Province of Alberta:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Synthetic Crude Oil
|
|
|
Base Mine and |
|
|
|
|
|
|
North Mine
|
|
Aurora Mine
|
|
Total
|
|
|
(millions of cubic metres) |
Beginning of year 2001 |
|
|
60 |
|
|
|
37 |
|
|
|
97 |
|
Revision of previous estimate |
|
|
|
|
|
|
37 |
|
|
|
37 |
|
Production |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2001 |
|
|
58 |
|
|
|
73 |
|
|
|
131 |
|
Revision of previous estimate |
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(3 |
) |
|
|
(1 |
) |
|
|
(4 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2002 |
|
|
55 |
|
|
|
72 |
|
|
|
127 |
|
Revision of previous estimate |
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(2 |
) |
|
|
(1 |
) |
|
|
(3 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2003 |
|
|
53 |
|
|
|
71 |
|
|
|
124 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Synthetic Crude Oil
|
|
|
Base Mine and |
|
|
|
|
|
|
North Mine
|
|
Aurora Mine
|
|
Total
|
|
|
(millions of barrels) |
Beginning of year 2001 |
|
|
373 |
|
|
|
237 |
|
|
|
610 |
|
Revision of previous estimate |
|
|
|
|
|
|
230 |
|
|
|
230 |
|
Production |
|
|
(15 |
) |
|
|
(4 |
) |
|
|
(19 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2001 |
|
|
358 |
|
|
|
463 |
|
|
|
821 |
|
Revision of previous estimate |
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(14 |
) |
|
|
(7 |
) |
|
|
(21 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2002 |
|
|
344 |
|
|
|
456 |
|
|
|
800 |
|
Revision of previous estimate |
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(13 |
) |
|
|
(6 |
) |
|
|
(19 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2003 |
|
|
331 |
|
|
|
450 |
|
|
|
781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil and Gas Producing Activities
The following information is provided in accordance with the United
States Statement of Financial Accounting Standards No. 69, Disclosures about
Oil and Gas Producing Activities.
30
Results of operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
(millions of dollars) |
Sales to customers |
|
$ |
1,816 |
|
|
$ |
1,381 |
|
|
$ |
1,306 |
|
Intersegment sales |
|
|
584 |
|
|
|
741 |
|
|
|
767 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total sales (1) |
|
$ |
2,400 |
|
|
$ |
2,122 |
|
|
$ |
2,073 |
|
Production expenses |
|
|
594 |
|
|
|
576 |
|
|
|
526 |
|
Exploration expenses |
|
|
55 |
|
|
|
30 |
|
|
|
45 |
|
Depreciation and depletion |
|
|
463 |
|
|
|
426 |
|
|
|
411 |
|
Income taxes |
|
|
364 |
|
|
|
350 |
|
|
|
340 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Results of operations |
|
$ |
924 |
|
|
$ |
740 |
|
|
$ |
751 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital and exploration expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
(millions of dollars) |
Property costs (2) |
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
$ |
|
|
|
$ |
13 |
|
|
$ |
|
|
Unproved |
|
|
2 |
|
|
|
5 |
|
|
|
5 |
|
Exploration costs |
|
|
55 |
|
|
|
34 |
|
|
|
44 |
|
Development costs |
|
|
339 |
|
|
|
469 |
|
|
|
489 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital and exploration expenditures |
|
$ |
396 |
|
|
$ |
521 |
|
|
$ |
538 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
|
(millions of dollars) |
Property costs (2) |
|
|
|
|
|
|
|
|
Proved |
|
$ |
3,332 |
|
|
$ |
3,338 |
|
Unproved |
|
|
163 |
|
|
|
155 |
|
Producing assets |
|
|
5,775 |
|
|
|
5,371 |
|
Support facilities |
|
|
125 |
|
|
|
126 |
|
Incomplete construction |
|
|
200 |
|
|
|
227 |
|
|
|
|
|
|
|
|
|
|
Total cost |
|
$ |
9,595 |
|
|
$ |
9,217 |
|
Accumulated depreciation and depletion |
|
|
6,012 |
|
|
|
5,528 |
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment |
|
$ |
3,583 |
|
|
$ |
3,689 |
|
|
|
|
|
|
|
|
|
|
(1) |
|
Sales of crude oil to consolidated affiliates are at market value, using
posted field prices. Sales of natural gas liquids to consolidated affiliates
are at prices estimated to be obtainable in a competitive, arms length
transaction.
Total sales exclude the sale of natural gas and natural gas liquids purchased
for resale. |
|
(2) |
|
Property costs are payments for rights to explore for petroleum and
natural gas and for purchased reserves (acquired tangible and intangible assets
such as gas plants, production facilities, and producing well costs are
included under Producing assets). Proved represents areas where successful
drilling has delineated a field capable of production. Unproved represents
all other areas. |
Net proved developed and undeveloped reserves (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids |
|
|
|
|
Conventional
|
|
Cold Lake
|
|
Total
|
|
Natural Gas
|
|
|
(millions of cubic metres) |
|
(billions of cubic meters) |
Beginning of year 2001 |
|
|
31 |
|
|
|
135 |
|
|
|
166 |
|
|
|
45 |
|
Revisions of previous estimates and improved recovery |
|
|
(1 |
) |
|
|
|
|
|
|
(1 |
) |
|
|
|
|
(Sale)/purchase of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discoveries and extensions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(4 |
) |
|
|
(7 |
) |
|
|
(11 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2001 |
|
|
26 |
|
|
|
128 |
|
|
|
154 |
|
|
|
40 |
|
Revisions of previous estimates and improved recovery |
|
|
|
|
|
|
5 |
|
|
|
5 |
|
|
|
|
|
(Sale)/purchase of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discoveries and extensions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(3 |
) |
|
|
(6 |
) |
|
|
(9 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2002 |
|
|
23 |
|
|
|
127 |
|
|
|
151 |
|
|
|
35 |
|
Revisions of previous estimates and improved recovery |
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
(1 |
) |
(Sale)/purchase of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discoveries and extensions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(3 |
) |
|
|
(7 |
) |
|
|
(10 |
) |
|
|
(5 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2003 |
|
|
20 |
|
|
|
121 |
|
|
|
141 |
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net reserves are the Companys share of reserves after deducting the
shares of mineral owners or governments or both. All reported reserves
are located in Canada. Reserves of natural gas are calculated at a
pressure of 101.325 kilopascals absolute at 15 degrees Celsius. |
31
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids |
|
|
|
|
Conventional
|
|
Cold Lake
|
|
Total
|
|
Natural Gas
|
|
|
(millions of barrels) |
|
(billions of cubic feet) |
Beginning of year 2001 |
|
|
196 |
|
|
|
851 |
|
|
|
1,047 |
|
|
|
1,572 |
|
Revisions of previous estimates and improved recovery |
|
|
(8 |
) |
|
|
|
|
|
|
(8 |
) |
|
|
9 |
|
(Sale)/purchase of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
Discoveries and extensions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Production |
|
|
(23 |
) |
|
|
(44 |
) |
|
|
(67 |
) |
|
|
(170 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2001 |
|
|
165 |
|
|
|
807 |
|
|
|
972 |
|
|
|
1,414 |
|
Revisions of previous estimates and improved recovery |
|
|
3 |
|
|
|
33 |
|
|
|
36 |
|
|
|
(26 |
) |
(Sale)/purchase of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2 |
|
Discoveries and extensions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3 |
|
Production |
|
|
(22 |
) |
|
|
(39 |
) |
|
|
(61 |
) |
|
|
(169 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2002 |
|
|
146 |
|
|
|
801 |
|
|
|
947 |
|
|
|
1,224 |
|
Revisions of previous estimates and improved recovery |
|
|
1 |
|
|
|
5 |
|
|
|
6 |
|
|
|
(40 |
) |
(Sale)/purchase of reserves in place |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discoveries and extensions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6 |
|
Production |
|
|
(21 |
) |
|
|
(43 |
) |
|
|
(64 |
) |
|
|
(167 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
End of year 2003 |
|
|
126 |
|
|
|
763 |
|
|
|
889 |
|
|
|
1,023 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
Net reserves are the Companys share of reserves after deducting the
shares of mineral owners or governments or both. All reported reserves
are located in Canada. Reserves of natural gas are calculated at a
pressure of 14.73 pounds per square inch at 60°F. |
Crude oil and natural gas reserve estimates are based on geological and
engineering data, which have demonstrated with reasonable certainty that these
reserves are recoverable in future years from known reservoirs under existing
economic and operating conditions, i.e. prices and costs as of the date the
estimate is made. Reserves of crude oil at Cold Lake are those estimated to be
recoverable from the existing experimental pilot plants and commercial stages 1
through 13.
Net proved reserves are determined by deducting the estimated future share
of mineral owners or governments or both. For conventional crude oil (excluding
enhanced oil recovery projects), and natural gas, net proved reserves are based
on estimated future royalty rates representative of those existing as of the
date the estimate is made. Actual future royalty rates may vary with production
and price. For enhanced oil recovery projects and Cold Lake, net proved
reserves are based on the Companys best estimate of average royalty rates over
the life of each project. Actual future royalty rates may vary with production,
price and costs.
Reserves data do not include certain resources of crude oil and natural
gas such as those discovered in the Beaufort Sea/Mackenzie Delta and the Arctic
Islands, or the resources contained in oil sands other than those attributable
to the Cold Lake pilot area and stages 1 through 13 of Cold Lake production
operations.
In 2003, the Companys net proved reserves of crude oil and natural gas
liquids decreased by about nine million cubic metres (58 million barrels),
while the proved reserves of natural gas decreased by about six billion cubic
metres (201 billion cubic feet). Production in 2003 totalled about 10 million
cubic metres (64 million barrels) of crude oil and natural gas liquids and
about five billion cubic metres (167 billion cubic feet) of natural gas.
Revisions of previous estimates and improved recovery increased reserves of
crude oil and natural gas liquids by about one million cubic metres (six
million barrels) and decreased reserves of natural gas by about one billion
cubic metres (40 billion cubic feet). Discoveries and extensions in 2003
totalled less than one billion cubic metres (six billion cubic feet) of natural
gas.
Net Proved Developed and Undeveloped Reserves of Crude Oil and Natural Gas (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
Crude Oil: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
20 |
|
|
|
23 |
|
|
|
26 |
|
|
|
31 |
|
|
|
36 |
|
Barrels |
|
|
126 |
|
|
|
146 |
|
|
|
165 |
|
|
|
196 |
|
|
|
225 |
|
Oil Sands (Cold Lake crude bitumen): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
121 |
|
|
|
127 |
|
|
|
128 |
|
|
|
135 |
|
|
|
139 |
|
Barrels |
|
|
763 |
|
|
|
801 |
|
|
|
807 |
|
|
|
851 |
|
|
|
878 |
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
141 |
|
|
|
151 |
|
|
|
154 |
|
|
|
166 |
|
|
|
175 |
|
Barrels |
|
|
889 |
|
|
|
947 |
|
|
|
972 |
|
|
|
1,047 |
|
|
|
1,103 |
|
Natural Gas: |
|
(billions) |
Cubic metres |
|
|
29 |
|
|
|
35 |
|
|
|
40 |
|
|
|
45 |
|
|
|
48 |
|
Cubic feet |
|
|
1,023 |
|
|
|
1,224 |
|
|
|
1,414 |
|
|
|
1,572 |
|
|
|
1,692 |
|
32
Net Proved Developed Reserves of Crude Oil and Natural Gas (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
|
|
(millions) |
|
Crude Oil: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
19 |
|
|
|
22 |
|
|
|
25 |
|
|
|
28 |
|
|
|
32 |
|
Barrels |
|
|
121 |
|
|
|
139 |
|
|
|
157 |
|
|
|
175 |
|
|
|
200 |
|
Oil Sands (Cold Lake crude bitumen): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
63 |
|
|
|
49 |
|
|
|
34 |
|
|
|
40 |
|
|
|
36 |
|
Barrels |
|
|
398 |
|
|
|
308 |
|
|
|
216 |
|
|
|
250 |
|
|
|
229 |
|
Total: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic metres |
|
|
82 |
|
|
|
71 |
|
|
|
59 |
|
|
|
68 |
|
|
|
68 |
|
Barrels |
|
|
519 |
|
|
|
447 |
|
|
|
373 |
|
|
|
425 |
|
|
|
429 |
|
Natural Gas: |
|
(billions) |
Cubic metres |
|
|
24 |
|
|
|
27 |
|
|
|
30 |
|
|
|
35 |
|
|
|
36 |
|
Cubic feet |
|
|
859 |
|
|
|
959 |
|
|
|
1,060 |
|
|
|
1,233 |
|
|
|
1,264 |
|
(1) |
|
Net reserves are the Companys share of reserves after deducting the shares of mineral owners or
governments or both. |
Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
(millions) |
Future cash flows |
|
$ |
27,611 |
|
|
$ |
35,811 |
|
|
$ |
17,936 |
|
Future production costs |
|
|
(10,871 |
) |
|
|
(8,940 |
) |
|
|
(7,107 |
) |
Future development costs |
|
|
(3,084 |
) |
|
|
(3,117 |
) |
|
|
(2,641 |
) |
Future income taxes |
|
|
(5,543 |
) |
|
|
(9,107 |
) |
|
|
(3,285 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Future net cash flows |
|
$ |
8,113 |
|
|
$ |
14,647 |
|
|
$ |
4,903 |
|
Annual discount of 10 percent for estimated
timing of cash flows |
|
|
(3,375 |
) |
|
|
(6,446 |
) |
|
|
(2,114 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Discounted future net cash flows |
|
$ |
4,738 |
|
|
$ |
8,201 |
|
|
$ |
2,789 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and
Gas Reserves (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
|
|
(millions) |
Balance at beginning of year |
|
$ |
8,201 |
|
|
$ |
2,789 |
|
|
$ |
5,987 |
|
Changes resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced, net of
production costs |
|
|
(2,075 |
) |
|
|
(1,645 |
) |
|
|
(1,698 |
) |
Net changes in prices, development costs and
production costs |
|
|
(4,395 |
) |
|
|
9,276 |
|
|
|
(6,477 |
) |
Extensions, discoveries, additions and improved recovery,
less related costs |
|
|
22 |
|
|
|
34 |
|
|
|
31 |
|
Purchase/(sales) of minerals in place |
|
|
|
|
|
|
4 |
|
|
|
5 |
|
Development costs incurred during the year |
|
|
281 |
|
|
|
432 |
|
|
|
504 |
|
Revisions of previous quantity estimates |
|
|
(368 |
) |
|
|
111 |
|
|
|
88 |
|
Accretion of discount |
|
|
1,108 |
|
|
|
423 |
|
|
|
1,030 |
|
Net change in income taxes |
|
|
1,964 |
|
|
|
(3,223 |
) |
|
|
3,319 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net Change |
|
$ |
(3,463 |
) |
|
$ |
5,412 |
|
|
$ |
(3,198 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Balance at end of year |
|
$ |
4,738 |
|
|
$ |
8,201 |
|
|
$ |
2,789 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
The schedules above are calculated using year-end prices, costs,
statutory tax rates and existing proved oil and gas reserves excluding
the Companys interest in Syncrude. The standardized measure includes
costs for future dismantlement, abandonment and rehabilitation
obligations. The Company
believes the standardized measure does not provide a reliable estimate of
the Companys expected future cash flows to be obtained from the
development and production of its oil and gas properties or of the value of
its proved oil and gas reserves. The standardized measure is prepared on
the basis of certain prescribed assumptions including year-end prices,
which represent a single point in time and therefore may cause significant
variability in cash flows from year to year as prices change. |
Within the past 12 months, the Company has not filed oil and gas reserve
estimates with any authority or agency of the United States.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
33
Item 9A. Controls and Procedures.
|
|
As indicated in the certifications in Exhibit 31.1 and 31.2 of this report,
the Companys principal executive officer and principal financial officer
have evaluated the Companys disclosure controls and procedures as of
December 31, 2003. Based on that evaluation, these officers have concluded
that the Companys disclosure controls and procedures are appropriate and
effective for the purpose of ensuring that material information relating to
the Company, including its consolidated subsidiaries, is made known to them
by others within those entities, particularly during the period in which
this annual report is being prepared. |
|
|
|
There has not been any change in the Companys internal control over
financial reporting that occurred during the Companys fourth fiscal quarter
of 2003 that has materially affected, or is reasonably likely to materially
affect, the Companys internal control over financial reporting. |
34
PART III
Item 10. Directors and Executive Officers of the Registrant.
The Company currently has nine directors. Each director is elected to hold
office until the close of the next annual meeting.
All of the nominees are now directors and have been since the dates
indicated.
The following table provides information on the nominees
for election as directors.
|
|
|
|
|
|
|
|
|
|
|
|
|
Last major |
|
|
|
|
|
|
|
|
|
|
position or office with the |
|
|
|
|
|
|
|
|
Name and current principal |
|
Company or Exxon Mobil |
|
|
|
|
|
|
|
|
occupation or employment
|
|
Corporation
|
|
Director since
|
|
Holdings(1)(2)
|
P. (Pierre) Des Marais II
President,
Gestion PDM Inc.
(management company)
|
|
|
|
April 22, 1977
|
|
Common shares of
Imperial Oil Limited
Deferred share units of
|
|
|
1,560 |
|
|
|
|
|
|
|
Imperial Oil Limited
|
|
|
4,234 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units of
Imperial Oil Limited
|
|
|
1,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of
Exxon Mobil Corporation
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
B.J. (Brian) Fischer
Senior vice-president,
products and chemicals division,
Imperial Oil Limited
|
|
Senior vice-president,
chemicals division,
Imperial Oil Limited
|
|
September 1, 1992
|
|
Common shares of
Imperial Oil Limited
|
|
|
33,698 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred share units of
Imperial Oil Limited
|
|
|
19,773 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units of
Imperial Oil Limited
|
|
|
48,400 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of
Exxon Mobil Corporation
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
T.J. (Tim) Hearn
Chairman, president and
chief executive officer,
Imperial Oil Limited
|
|
President,
Imperial Oil Limited
|
|
January 1, 2002
|
|
Common shares of
Imperial Oil Limited
|
|
|
23,095 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred share units of
Imperial Oil Limited
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units of
Imperial Oil Limited
|
|
|
110,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of
Exxon Mobil Corporation
|
|
|
9,274 |
|
|
|
|
|
|
|
|
|
|
|
|
R. (Roger) Phillips
Retired president and
chief executive officer,
IPSCO Inc.
(steel manufacturing)
|
|
|
|
April 23, 2002
|
|
Common shares of
Imperial Oil Limited
|
|
|
3,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred share units of
Imperial Oil Limited
|
|
|
2,316 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units of
Imperial Oil Limited
|
|
|
1,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of
Exxon Mobil Corporation
|
|
|
2,000 |
|
|
|
|
|
|
|
|
|
|
|
|
J.F. (Jim) Shepard
Retired chairman and
chief executive officer,
Finning International Inc.
(sale, lease, repair and financing
of heavy equipment)
|
|
|
|
October 21, 1997
|
|
Common shares of
Imperial Oil Limited
|
|
|
3,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred share units of
Imperial Oil Limited
|
|
|
4,878 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units of
Imperial Oil Limited
|
|
|
1,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of
Exxon Mobil Corporation
|
|
|
0 |
|
35
|
|
|
|
|
|
|
|
|
|
|
|
|
Last major |
|
|
|
|
|
|
|
|
|
|
position or office with the |
|
|
|
|
|
|
|
|
Name and current principal |
|
Company or Exxon Mobil |
|
|
|
|
|
|
|
|
occupation or employment
|
|
Corporation
|
|
Director since
|
|
Holdings(1)(2)
|
|
|
|
|
P.A. (Paul) Smith
Controller and
senior vice-president,
finance and administration,
Imperial Oil Limited
|
|
Corporate finance manager,
Exxon Mobil Corporation
|
|
February 1, 2002
|
|
Common shares of
Imperial Oil Limited
|
|
|
4,120 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred share units of
Imperial Oil Limited
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units of
Imperial Oil Limited
|
|
|
29,200 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of
Exxon Mobil Corporation
|
|
|
1,190 |
|
|
|
|
|
|
|
|
|
|
|
|
S.D. (Sheelagh) Whittaker
Managing Director,
public sector business
Electronic Data Systems Limited
(business and information
technology services)
|
|
|
|
April 19, 1996
|
|
Common shares of
Imperial Oil Limited
|
|
|
3,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred share units of
Imperial Oil Limited
|
|
|
7,313 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units of
Imperial Oil Limited
|
|
|
1,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of
Exxon Mobil Corporation
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
K.C. (K.C.) Williams
Senior vice-president,
resources division,
Imperial Oil Limited
|
|
Vice-president,
production,
Exxon Company,
International
|
|
January 1, 1999
|
|
Common shares of
Imperial Oil Limited
|
|
|
12,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred share units of
Imperial Oil Limited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units of
Imperial Oil Limited
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of
Exxon Mobil Corporation
|
|
|
73,045 |
|
|
|
|
|
|
|
|
|
|
|
|
V.L. (Victor) Young
Corporate director
of several corporations
|
|
|
|
April 23, 2002
|
|
Common shares of
Imperial Oil Limited
|
|
|
3,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Deferred share units of
Imperial Oil Limited
|
|
|
579 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted stock units of
Imperial Oil Limited
|
|
|
1,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares of
Exxon Mobil Corporation
|
|
|
0 |
|
(1) |
|
The information includes the beneficial ownership of common shares of
Imperial Oil Limited and shares of Exxon Mobil Corporation, which information
not being within the knowledge of the Company, has been provided by the
nominees individually. |
|
(2) |
|
The Companys plans for deferred share units and restricted stock units for
selected employees and nonemployee directors are described on pages 40 and 41. |
The ages of the directors, nominees for election as directors, and the
five senior executives of the Company are: Pierre Des Marais II 69, Brian J.
Fischer 57, Timothy J. Hearn 60, Roger Phillips 64, James F. Shepard 65, Paul
A. Smith 51, Sheelagh D. Whittaker 56, K.C. Williams 54, Victor L. Young 58,
and John F. Kyle 61.
Roger Phillips is a director of Canadian Pacific Railway Limited, Cleveland
Cliffs Inc., Inco Limited, and The Toronto Dominion Bank, and Victor L. Young
is a director of Royal Bank of Canada and BCE Inc., which companies are subject
to reporting requirements under the U.S. Securities Exchange Act of
1934.
36
All of the directors and nominees for election as directors, except for
Roger Phillips, Victor L. Young and James F. Shepard, have been engaged for
more than five years in their present principal occupations or in other
executive capacities with the same firm or affiliated firms. During the five
preceding years, Roger Phillips was president and chief executive officer of
IPSCO Inc. (steel manufacturing) until he retired on January 1, 2002. During
the five preceding years, Victor L. Young was chairman and chief executive
officer of Fishery Products International Limited (seafood products), until May
1, 2001 and is currently a director of Royal Bank of Canada, BCE Inc., McCain
Foods Limited, Aliant Inc., and Telesat Canada. For more than five years before
2000, James F. Shepards principal occupation was successively president and
chief executive officer, and from April 1996, chairman and chief executive
officer of Finning International Inc. (sale, lease, repair and financing of
heavy equipment) following which, in 2000, he retired.
The following table provides information on the senior executives of the
Company.
|
|
|
Name and Office
|
|
Office held since
|
Timothy J. Hearn
|
|
April 23, 2002 |
chairman of the board, president |
|
|
and chief executive officer |
|
|
|
|
|
Brian J. Fischer
|
|
February 1, 1994 |
senior vice-president, |
|
|
products and chemicals division |
|
|
|
|
|
Paul A. Smith
|
|
February 1, 2002 |
controller and senior vice-president, |
|
|
finance and administration |
|
|
|
|
|
K.C. Williams
|
|
January 1, 1999 |
senior vice-president, |
|
|
resources division |
|
|
|
|
|
John F. Kyle
|
|
June 1, 1991 |
vice-president and |
|
|
treasurer |
|
|
All of the above senior executives have been engaged for more than five
years at their current occupations or in other executive capacities with the
Company or its affiliates. All senior executives hold office until their
appointment is rescinded by the directors, or by the chief executive officer.
Audit committee
The Company has an audit committee of the board of directors. The
following directors are members of the audit committee: P. Des Marais II, R.
Phillips, J.F. Shepard, S.D. Whittaker and V.L. Young.
Audit committee financial expert
The Companys board of directors has determined that P. Des Marais II, R.
Phillips, S.D. Whittaker and V. L. Young meet the definition of audit
committee financial expert and are independent, as that term is defined by
both the Securities and Exchange Commission rules and the listing standards of
the American Stock Exchange and the New York Stock Exchange. The Securities and
Exchange Commission has indicated that the designation of an audit committee
financial expert does not make that person an expert for any purpose, or impose
any duties, obligations or liability on that person that are greater than those
imposed on members of the audit committee and board of directors in the absence
of such designation or identification.
Code of ethics
The Company has a code of ethics and conflict-of-interest guidelines that
apply to all employees, including its principal executive officer, principal
financial officer and principal accounting officer. The code of ethics and
conflict-of-interest guidelines are available at the Companys website
www.imperialoil.ca.
37
Item 11. Executive Compensation.
Directors compensation
Directors fees are paid only to nonemployee directors. For 2003,
nonemployee directors were paid an annual retainer of $35,000 for their
services as directors, plus an annual retainer of $4,500 for each committee on
which they served, an additional $5,000 for serving as chair of a committee and
$2,000 for each board and board committee meeting attended. Effective December
31, 2003, the annual board retainer was increased by the issuance of 1,000
restricted stock units to each nonemployee director. The restricted stock units
issued to nonemployee directors have the same features as the restricted stock
units for selected employees described on page 41.
Starting in 1999, the nonemployee directors have been able to receive all
or part of their directors fees in the form of deferred share units for
nonemployee directors. The purpose of the deferred share unit plan for
nonemployee directors is to provide them with additional motivation to promote
sustained improvement in the Companys business performance and shareholder
value by allowing them to have all or part of their directors fees tied to the
future growth in value of the Companys common shares. This plan is described
on pages 40 and 41.
While serving as directors in 2003, the aggregate cash remuneration paid
to nonemployee directors, as a group, was $346,500, and they received an
additional 5,006 deferred share units for nonemployee directors, as a group,
based on an aggregate of $250,000 of cash remuneration elected to be received
as deferred share units. The nonemployee directors, as a group, received an
additional 279 deferred share units granted as the equivalent to the cash
dividend paid on Company shares during 2003 for previously granted deferred
share units.
Senior executive compensation
Summary compensation table
The following table shows the compensation for the chief executive officer
and the four other senior executives of the Company who were serving as senior
executives at the end of 2003. This information includes the dollar value of
base salaries, cash bonus awards, and units of other long term incentive
compensation and certain other compensation.
38
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Annual Compensation
|
|
Long-Term Compensation
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Awards
|
|
Payouts
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Securities |
|
Restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Under |
|
Shares or |
|
|
|
|
Name and |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other Annual |
|
Options/SARs |
|
Restricted |
|
LTIP |
|
All Other |
Principal |
|
|
|
|
|
Salary |
|
Bonus (2) |
|
Compensation (3) |
|
Granted (4) |
|
Share Units (5) (6) (7) |
|
Payouts |
|
Compensation (9) |
Position
|
|
Year
|
|
($)
|
|
($)
|
|
($)
|
|
(#)
|
|
(#)
|
|
(8) ($)
|
|
($)
|
T.J. Hearn |
|
|
2003 |
|
|
|
825,000 |
|
|
|
750,000 |
|
|
|
182,072 |
|
|
|
|
|
|
|
60,000 |
|
|
|
738,000 |
|
|
|
24,750 |
|
Chairman, president and chief executive officer |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. 293,450 |
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
|
|
668,333 |
|
|
|
442,000 |
|
|
|
71,777 |
|
|
|
65,000 |
|
|
|
50,000 |
|
|
|
|
|
|
|
20,050 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. 328,796 |
|
|
stock |
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
options |
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2001 |
|
|
|
475,000 |
|
|
|
300,000 |
|
|
|
19,888 |
|
|
|
50,000 |
|
|
|
0 |
|
|
|
|
|
|
|
9,500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. (163,873 |
) |
|
incentive |
|
deferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
share units |
|
share units |
|
|
|
|
|
|
|
|
B.J. Fischer |
|
|
2003 |
|
|
|
530,833 |
|
|
|
357,000 |
|
|
|
24,815 |
|
|
|
|
|
|
|
26,700 |
|
|
|
486,000 |
|
|
|
31,850 |
|
Senior |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
vice-president, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
products and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
341 |
|
|
|
|
|
|
|
|
|
chemicals division |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
|
|
505,000 |
|
|
|
216,000 |
|
|
|
0 |
|
|
|
50,000 |
|
|
|
21,700 |
|
|
|
|
|
|
|
30,300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock |
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
options |
|
share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
358 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2001 |
|
|
|
475,000 |
|
|
|
67,500 |
|
|
|
2,935 |
|
|
|
50,000 |
|
|
|
5,039 |
|
|
|
|
|
|
|
23,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
incentive |
|
deferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
share units |
|
share units |
|
|
|
|
|
|
|
|
P.A. Smith |
|
|
2003 |
|
|
|
357,917 |
|
|
|
183,000 |
|
|
|
11,083 |
|
|
|
|
|
|
|
16,700 |
|
|
|
204,510 |
|
|
|
21,475 |
|
Controller and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
U.S. 72,891 |
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
senior vice-president, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
finance and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0 |
|
|
|
|
|
|
|
|
|
administration |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
|
|
331,667 |
|
|
|
94,500 |
|
|
|
U.S. 100,390 |
|
|
|
25,000 |
|
|
|
12,500 |
|
|
|
|
|
|
|
19,900 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock |
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
options |
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2001 |
|
|
|
291,666 |
|
|
|
110,000 |
|
|
|
U.S. 30,908 |
|
|
|
25,000 |
|
|
|
0 |
|
|
|
|
|
|
|
14,583 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
incentive |
|
deferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
share units |
|
share units |
|
|
|
|
|
|
|
|
K.C. Williams (1) |
|
|
2003 |
|
|
|
U.S. 431,667 |
|
|
|
U.S. 260,900 |
|
|
|
U.S. 530,391 |
|
|
|
|
|
|
|
|
|
|
|
U.S. 197,490 |
|
|
|
U.S. 27,900 |
|
Senior
vice-president,
resources division |
|
|
2002 |
|
|
|
U.S. 412,500 |
|
|
|
U.S. 158,000 |
|
|
|
U.S. 363,932 |
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
|
U.S. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
197,450 |
|
|
|
26,750 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2001 |
|
|
|
U.S. 382,750 |
|
|
|
U.S. 197,500 |
|
|
|
U.S. 144,175 |
|
|
|
|
|
|
|
|
|
|
|
U.S. |
|
|
|
U.S. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
97,515 |
|
|
|
24,665 |
|
J.F. Kyle |
|
|
2003 |
|
|
|
355,000 |
|
|
|
171,000 |
|
|
|
41,391 |
|
|
|
|
|
|
|
11,400 |
|
|
|
261,000 |
|
|
|
21,300 |
|
Vice-president |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
and treasurer |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2002 |
|
|
|
345,000 |
|
|
|
110,000 |
|
|
|
13,077 |
|
|
|
29,000 |
|
|
|
10,600 |
|
|
|
|
|
|
|
20,700 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock |
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
options |
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2001 |
|
|
|
325,000 |
|
|
|
150,000 |
|
|
|
15,107 |
|
|
|
29,000 |
|
|
|
0 |
|
|
|
|
|
|
|
16,250 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
incentive |
|
deferred |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
share units |
|
share units |
|
|
|
|
|
|
|
|
39
(1) |
|
K.C. Williams is on a loan assignment from Exxon Mobil Corporation to the
Company. His compensation was paid to him directly by Exxon Mobil Corporation
in United States dollars, and is disclosed in United States dollars. Also, he
received employee benefits under Exxon Mobil Corporations employee benefit
plans, and not under the Companys employee benefit plans. The Company
reimburses Exxon Mobil Corporation for the compensation paid and employee
benefits provided to him. |
|
(2) |
|
Any part of bonus elected to be received as deferred share units is
excluded. |
|
(3) |
|
Amounts under Other Annual Compensation, except for K.C. Williams,
consist of interest paid in respect of deferred payments for long term
incentive compensation, other than the Companys plan for deferred share units
for selected executives, described on pages 40 and 41, dividend equivalent
payments on restricted stock units, interest paid in respect of deferred
payments of bonuses and reimbursement for any income tax paid as a result of
use of Company aircraft. For T.J. Hearn the amounts also include a leased
automobile which in 2003 was $44,010 and financial counselling. For T.J. Hearn
and P.A. Smith, the U.S. dollar amounts are payments by the Company on account
of U.S. income taxes incurred while on assignment in the U.S.A. For K.C.
Williams, the amounts are the net payments by Exxon Mobil Corporation on
account of Canadian income taxes and other compensation for assignment outside
of the United States. Each year, while on assignment, T.J. Hearn and P.A. Smith
paid to the Company and K.C. Williams paid to Exxon Mobil Corporation amounts
that were approximate to the income taxes that would have been imposed if they
were resident in their originating country of employment. For T.J. Hearn for
2001, the negative amount was a net payment to the Company as a result of
differences in timing of the amounts paid by the Company on account of U.S.
income taxes and the amounts he paid to the Company to approximate the income
taxes that would have been imposed if he was resident in Canada. |
|
(4) |
|
For 2001, these are the number of units granted under the Companys plan
for incentive share units described on page 40. In 2002, the Company granted
instead stock options which are described on page 41. |
|
(5) |
|
These include the number of units granted under the Companys plan for
deferred share units for selected executives described on pages 40 and 41. The
values and number of these units, as at the end of 2003, were nil for T.J.
Hearn, $1,137,541 for 19,773 units for B.J. Fischer, and nil for P.A. Smith and
J.F. Kyle. These amounts include no deferred share units elected to be received
in lieu of bonus for 2003 and 2002, and 4,880 share units based on $202,500 of
bonus elected to be received as deferred share units for 2001 for B.J. Fischer. |
|
(6) |
|
These also include restricted stock units granted under the Companys plan
for restricted stock units for selected employees and nonemployee directors
described on page 41. The values and number of these units, as at the end of
2003, were $6,328,300 for 110,000 units for T.J. Hearn, $2,784,452 for 48,400
units for B.J. Fischer, $1,679,876 for 29,200 units for P.A. Smith and
$1,265,660 for 22,000 units for J.F. Kyle. The values of these units granted
for 2003, as at the end of 2003, were $3,451,800 for T.J. Hearn, $1,536,051 for
B.J. Fischer, $960,751 for P.A. Smith and $655,842 for J.F. Kyle. The values of
these units granted for 2002, as at the end of 2002, were $2,243,000 for T.J.
Hearn, $973,462 for B.J. Fischer, $560,750 for P.A. Smith and $475,516 for J.F.
Kyle. |
|
(7) |
|
K.C. Williams participates in Exxon Mobil Corporations restricted stock
plan which is similar to the Companys restricted stock unit plan. The value
and number of these units for K.C. Williams, as at the end of the year, were
U.S. $1,918,800 for 46,800 units. Under that plan, K.C. Williams was granted 23
400 units in 2003 whose value on the date of grant was U.S. $959,400 and 23 400
units in 2002 whose value on the date of grant was U.S. $810,576. |
|
(8) |
|
Payouts
were from 2001 and 2002 earnings bonus units that reached maximum value of
$3.00 per unit in 2003. That plan is described on page 41. |
|
(9) |
|
Amounts under All Other Compensation, except for K.C. Williams, are the
Companys contributions to the savings plan, which is a plan available to all
employees. Under one of the options of that plan to which the senior executives
subscribe, except for K.C. Williams, the Company matched employee contributions
up to six percent of base salary per year; however, an employee may elect to
receive an enhanced pension under the Companys pension plan by foregoing three
percent of the Companys matching contributions. The plan is intended to be
primarily for retirement savings, although employees may withdraw their
contributions prior to retirement. For K.C. Williams, the amounts are Exxon
Mobil Corporations contributions to its employee savings plan. |
Long term incentive compensation
Long term incentive compensation is granted to retain selected employees
and reward them for high performance. The compensation has generally been in
the form of units.
The Companys incentive share units give the recipient a
right to receive cash equal to the amount by which the market price of the
Companys common shares at the time of exercise exceeds the issue price of the
units, if exercised within the periods of eligibility. These units were granted
prior to 2002. The issue price of the units granted to executives was the
closing price of the Companys shares on the Toronto Stock Exchange on the
grant date. The periods of eligibility for the exercise of the units are as
follows: no units may be exercised before one year after the grant date; up to
50 percent of the units may be exercised on or after one year following the
grant date; an additional 25 percent of the units may be exercised on or after
two years following the grant date; and the remaining 25 percent of the units
may be exercised on or after three years following the grant date. Incentive
share units are eligible for exercise up to 10 years from issuance.
In 1998, an additional form of long term incentive compensation (deferred
share units) was made available to selected executives whereby they could
elect to receive all or part of their performance bonus compensation in the
form of such units. The number of units granted to an executive is determined
by dividing the amount of the executives bonus elected to be received as
deferred share units by the average of the
40
closing prices of the Companys shares on the Toronto Stock Exchange for the
five consecutive trading days (average closing price) immediately prior to
the date that the bonus would have been paid to the executive. Additional units
will be granted to recipients of these units based on the cash dividend payable
on the Company shares divided by the average closing price immediately prior to
the payment date for that dividend and multiplying the resulting number by the
number of deferred share units held by the recipient. An executive may not
exercise these units until after termination of employment with the Company and
must exercise the units no later than December 31 of the year following
termination of employment with the Company. The units held must all be
exercised on the same date. On the date of exercise, the cash value to be
received for the units will be determined by multiplying the number of units
exercised by the average closing price immediately prior to the date of
exercise.
Starting in 1999, a form of long term incentive compensation, similar to
the deferred share units for executives, was made available to nonemployee
directors in lieu of their receiving all or part of their directors fees. The
main differences between the two plans are that all nonemployee directors are
allowed to participate in the plan for nonemployee directors and that the
number of units granted to a nonemployee director is determined at the end of
each calendar quarter by dividing the amount of the directors fees for that
calendar quarter that the nonemployee director elected to receive as deferred
share units by the average closing price immediately prior to the last day of
the calendar quarter.
Starting in 2001, the earnings bonus unit plan was made available to
selected executives to promote individual contribution to sustained improvement
in the Companys business performance and shareholder value. Each earnings
bonus unit entitles the recipient to receive an amount equal to the Companys
cumulative net earnings per common share as announced each quarter beginning
after the grant. Payout occurs on the fifth anniversary of the grant or when
the maximum settlement value per unit is reached, if earlier.
Under the stock option plan, adopted by the Company in April 2002, a total
of 3,210,200 options were granted on April 30, 2002 for the purchase of the
Companys common shares at an exercise price of $46.50 per share. Up to 75
percent of the options were exercisable after January 1, 2004, and the
remaining 25 percent may be exercised on or after January 1, 2005. Any
unexercised options expire after April 29, 2012.
In December 2002, the Company introduced a restricted stock unit plan,
which will be the primary long term incentive compensation plan in future
years. The purpose of the plan is to align the interests of employees and
nonemployee directors directly with the interests of shareholders. Each unit
entitles the recipient the conditional right to receive from the Company, upon
exercise, an amount equal to the closing price of the Companys shares on the
exercise dates. Fifty percent of the units will be exercised on the third
anniversary of the grant date, and the remainder will be exercised on the
seventh anniversary of the grant date. The Company will pay the recipients cash
with respect to each unexercised unit granted to the recipient corresponding in
time and amount to the cash dividend that is paid by the Company on a common
share of the Company. The restricted stock units plan was amended for units
granted in 2003 and future years by providing that the recipient may receive
one common share of the Company per unit or elect to receive the cash payment
for the units to be exercised on the seventh anniversary of the grant date. A
total of 872,085 units were granted on December 31, 2003.
Earnings bonus unit plan awards in most recently completed financial year
The following table provides information on earnings bonus units granted
in 2003 to the named senior executives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance |
|
Estimated Future Payouts Under |
|
|
|
|
Securities Units or |
|
or Other Period Until |
|
Non-Securities-Price Based Plans
|
|
|
|
|
Other Rights |
|
Maturation or |
|
Threshold |
|
Target |
|
Maximum |
Name
|
|
(#)
|
|
Payout (1)
|
|
($)
|
|
($) (2)
|
|
($)(2)
|
T.J. Hearn |
|
|
250,000 |
|
|
Nov. 20, 2008 |
|
|
0 |
|
|
|
3.00 |
|
|
|
3.00 |
|
B.J. Fischer |
|
|
119,000 |
|
|
Nov. 20, 2008 |
|
|
0 |
|
|
|
3.00 |
|
|
|
3.00 |
|
P.A. Smith |
|
|
61,000 |
|
|
Nov. 20, 2008 |
|
|
0 |
|
|
|
3.00 |
|
|
|
3.00 |
|
K.C. Williams (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J.F. Kyle |
|
|
57,000 |
|
|
Nov. 20, 2008 |
|
|
0 |
|
|
|
3.00 |
|
|
|
3.00 |
|
(1) |
|
Payment will be made earlier when the cumulative net earnings per
outstanding common share reach the maximum settlement value per unit prior to
the fifth anniversary of the grant date. |
(2) |
|
This is the maximum settlement value payable per earnings bonus unit
granted in 2002. |
(3) |
|
K.C. Williams participates in Exxon Mobil Corporations earnings bonus unit
plan which is similar to the Companys earnings bonus unit plan. In 2003, K.C.
Williams was granted 86,960 units under that plan for which the maximum
settlement value payable per earnings bonus unit is U.S. $3.00. |
41
Aggregated option/SAR exercises during the most recently completed financial
year and financial year-end option/SAR values
The following table provides information on the exercise in 2003 and the
aggregate holdings at the end of 2003 of incentive share units (referred to in
the table as SARs) by the named senior executives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Value of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unexercised |
|
|
|
|
|
|
|
|
|
|
Unexercised |
|
in-the-Money |
|
|
|
|
|
|
Options/SARs |
|
Options/SARs |
|
|
|
|
|
|
at Financial |
|
at Financial |
|
|
Securities |
|
Aggregate |
|
Year-End |
|
Year-End |
|
|
Acquired on Exercise |
|
Value Realized |
|
(#)
|
|
($)
|
Name
|
|
(#)
|
|
($)
|
|
Exercisable
|
|
Unexercisable (1)
|
|
Exercisable
|
|
Unexercisable (1)
|
T.J. Hearn |
|
|
|
|
|
|
181,350 |
|
|
|
50,000 |
|
|
|
12,500 |
|
|
|
1,027,750 |
|
|
|
231,625 |
|
B.J. Fischer |
|
|
|
|
|
|
|
|
|
|
139,5000 |
|
|
|
25,000 |
|
|
|
3,583,535 |
|
|
|
564,500 |
|
P.A. Smith |
|
|
|
|
|
|
503,100 |
|
|
|
66,750 |
|
|
|
6,250 |
|
|
|
2,176,438 |
|
|
|
115,813 |
|
K.C. Williams |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J.F. Kyle |
|
|
|
|
|
|
626,570 |
|
|
|
81,750 |
|
|
|
7,250 |
|
|
|
2,108,728 |
|
|
|
134,343 |
|
(1) |
|
Unexercisable units are units for which the conditions for exercise
have not been met. |
The following table provides information on the exercise in 2003 and the
aggregate holdings at the end of 2003 of stock options by named senior
executives.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Value of |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unexercised |
|
|
|
|
|
|
|
|
|
|
Unexercised |
|
in-the-Money |
|
|
|
|
|
|
Options/SARs |
|
Options/SARs |
|
|
|
|
|
|
at Financial |
|
at Financial |
|
|
Securities |
|
Aggregate |
|
Year-End |
|
Year-End |
|
|
Acquired on Exercise |
|
Value Realized |
|
(#)
|
|
($)
|
Name
|
|
(#)
|
|
($)
|
|
Exercisable
|
|
Unexercisable (2)
|
|
Exercisable
|
|
Unexercisable (2)
|
T.J. Hearn |
|
|
|
|
|
|
|
|
|
|
32,500 |
|
|
|
32,500 |
|
|
|
358,475 |
|
|
|
358,475 |
|
B.J. Fischer |
|
|
|
|
|
|
|
|
|
|
25,000 |
|
|
|
25,000 |
|
|
|
275,750 |
|
|
|
275,750 |
|
P.A. Smith |
|
|
|
|
|
|
|
|
|
|
12,500 |
|
|
|
12,500 |
|
|
|
137,875 |
|
|
|
137,875 |
|
K.C. Williams (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J.F. Kyle |
|
|
|
|
|
|
|
|
|
|
14,500 |
|
|
|
14,500 |
|
|
|
159,935 |
|
|
|
159,935 |
|
(1) |
|
At the end of 2003, K.C. Williams held options to acquire 475,000 Exxon
Mobil Corporation shares of which all options were exercisable. The values of
K.C. Williamss exercisable options were U.S. $4,617,084 at the end of 2003. In
2003, K.C. Williams exercised 26,508 options and realized an aggregate value of
U.S. $573,059. |
|
(2) |
|
Unexercisable units are units for which the conditions for
exercise have not been met. |
42
Payments to employees who retire
Pension plan table
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remuneration for |
|
Estimated undiscounted payments |
determining payments on retirement |
|
on retirement at the age of 65 after years of service indicated below ($)
|
($)
|
|
20 Years
|
|
25 Years
|
|
30 Years
|
|
35 Years
|
|
40 Years
|
100,000 |
|
|
32,000 |
|
|
|
40,000 |
|
|
|
48,000 |
|
|
|
56,000 |
|
|
|
64,000 |
|
200,000 |
|
|
64,000 |
|
|
|
80,000 |
|
|
|
96,000 |
|
|
|
112,000 |
|
|
|
128,000 |
|
300,000 |
|
|
96,000 |
|
|
|
120,000 |
|
|
|
144,000 |
|
|
|
168,000 |
|
|
|
192,000 |
|
400,000 |
|
|
128,000 |
|
|
|
160,000 |
|
|
|
192,000 |
|
|
|
224,000 |
|
|
|
256,000 |
|
500,000 |
|
|
160,000 |
|
|
|
200,000 |
|
|
|
240,000 |
|
|
|
280,000 |
|
|
|
320,000 |
|
600,000 |
|
|
192,000 |
|
|
|
240,000 |
|
|
|
288,000 |
|
|
|
336,000 |
|
|
|
384,000 |
|
700,000 |
|
|
224,000 |
|
|
|
280,000 |
|
|
|
336,000 |
|
|
|
392,000 |
|
|
|
448,000 |
|
800,000 |
|
|
256,000 |
|
|
|
320,000 |
|
|
|
384,000 |
|
|
|
448,000 |
|
|
|
512,000 |
|
900,000 |
|
|
288,000 |
|
|
|
360,000 |
|
|
|
432,000 |
|
|
|
504,000 |
|
|
|
576,000 |
|
1,000,000 |
|
|
320,000 |
|
|
|
400,000 |
|
|
|
480,000 |
|
|
|
560,000 |
|
|
|
640,000 |
|
1,100,000 |
|
|
352,000 |
|
|
|
440,000 |
|
|
|
528,000 |
|
|
|
616,000 |
|
|
|
704,000 |
|
1,200,000 |
|
|
384,000 |
|
|
|
480,000 |
|
|
|
576,000 |
|
|
|
672,000 |
|
|
|
768,000 |
|
1,300,000 |
|
|
416,000 |
|
|
|
520,000 |
|
|
|
624,000 |
|
|
|
728,000 |
|
|
|
832,000 |
|
1,400,000 |
|
|
448,000 |
|
|
|
560,000 |
|
|
|
672,000 |
|
|
|
784,000 |
|
|
|
896,000 |
|
1,500,000 |
|
|
480,000 |
|
|
|
600,000 |
|
|
|
720,000 |
|
|
|
840,000 |
|
|
|
960,000 |
|
1,600,000 |
|
|
512,000 |
|
|
|
640,000 |
|
|
|
768,000 |
|
|
|
896,000 |
|
|
|
1,024,000 |
|
1,700,000 |
|
|
544,000 |
|
|
|
680,000 |
|
|
|
816,000 |
|
|
|
952,000 |
|
|
|
1,088,000 |
|
1,800,000 |
|
|
576,000 |
|
|
|
720,000 |
|
|
|
864,000 |
|
|
|
1,008,000 |
|
|
|
1,152,000 |
|
1,900,000 |
|
|
608,000 |
|
|
|
760,000 |
|
|
|
912,000 |
|
|
|
1,064,000 |
|
|
|
1,216,000 |
|
2,000,000 |
|
|
640,000 |
|
|
|
800,000 |
|
|
|
960,000 |
|
|
|
1,120,000 |
|
|
|
1,280,000 |
|
2,100,000 |
|
|
672,000 |
|
|
|
840,000 |
|
|
|
1,008,000 |
|
|
|
1,176,000 |
|
|
|
1,344,000 |
|
2,200,000 |
|
|
704,000 |
|
|
|
880,000 |
|
|
|
1,056,000 |
|
|
|
1,232,000 |
|
|
|
1,408,000 |
|
2,300,000 |
|
|
736,000 |
|
|
|
920,000 |
|
|
|
1,104,000 |
|
|
|
1,288,000 |
|
|
|
1,472,000 |
|
2,400,000 |
|
|
768,000 |
|
|
|
960,000 |
|
|
|
1,152,000 |
|
|
|
1,344,000 |
|
|
|
1,536,000 |
|
2,500,000 |
|
|
800,000 |
|
|
|
1,000,000 |
|
|
|
1,200,000 |
|
|
|
1,400,000 |
|
|
|
1,600,000 |
|
The Companys pension plan applies to almost all employees. The plan
provides an annual pension of a specific percentage of an employees final
three year average earnings, multiplied by the employees years of service,
subject to certain requirements concerning age and length of service. An
employee may elect to forego three of the six percent of the Companys
contributions to the savings plan under one of the options of that plan to
which the senior executives subscribe, except for K.C. Williams, to receive an
enhanced pension equal to 0.4 percent of the employees final three year
average earnings, multiplied by the employees years of service while
foregoing such Company contributions. In addition to the pension payable under
the plan, the Company has paid and may continue to pay a supplemental
retirement income to employees who have earned a pension in excess of the
maximum pension under the Income Tax Act. The pension plan table on this page
shows estimated undiscounted annual payments, consisting of pension and
supplemental retirement income, payable on retirement to employees including
the senior executives in specified classifications of remuneration and years of
service currently applicable to that group.
The remuneration used to determine the payments on retirement to the
individuals named in the summary compensation table on pages 39 and 40,
corresponds generally to the salary, bonus compensation, and bonus compensation
amount elected to be received as deferred share units in that table, and the
aggregate maximum settlement value that could be paid for earnings bonus units
granted shown in the table on page 41 is included in the employees final
three year average earnings for the year of grant of such units. As of
February 18, 2004, the number of completed years of service with Imperial Oil
Limited used to determine payments on retirement were 37 for T.J. Hearn, 35 for
B.J. Fischer, 24 for P.A. Smith and 27 for J.F. Kyle.
K.C. Williams is not a member of the Companys pension plan but is a
member of Exxon Mobil Corporations pension plan. Under that plan, K.C.
Williams has 31 years of service and he will receive a pension payable in U.S.
dollars. The remuneration used to determine the payment on retirement to him
also corresponds generally to his salary and bonus compensation in the summary
compensation table on pages 39, and 40, which remuneration may be applied to
the pension plan table above but with the dollars in that table representing
U.S. rather than Canadian dollars.
43
Composition of the Companys compensation committee
The executive resources committee of the board of directors, composed of
the nonemployee directors, is responsible for decisions on the compensation of
senior management above the level of vice-president and for reviewing the
executive development system, including specific succession plans for senior
management positions. It also reviews corporate policy on compensation. During
2003, the membership of the executive resources committee was as follows:
P. Des Marais II - Chair
R. Phillips - Vice-chair
J.F. Shepard
S.D. Whittaker
V.L. Young
T.J. Hearn periodically attends meetings at the request of the committee.
Executive resources committee report on executive compensation
The Companys executive compensation policy is designed to reinforce the
Companys orientation toward career employment and its emphasis on performance
as the primary determinant of advancement. This acknowledges the long term
nature of the Companys business and its philosophy that the experience, skill
and motivation of its senior executives are significant determinants of future
business success. The compensation program emphasizes competitive salaries and
performance based incentives as the primary instruments to develop and retain
key personnel.
In establishing levels of compensation for its senior executives, the
executive resources committee relies on market comparisons to other leading
Canadian employers, typically in the group of major companies with revenues in
excess of $1 billion a year. These market comparisons are prepared by
independent external compensation consultants. On a case by case basis,
depending on the scope of market coverage represented by a particular
comparison, compensation is targeted to a range between the mid-point and the
upper quartile of comparable employers, reflecting the Companys emphasis on
quality of management.
The Companys senior executive compensation policy has three main
elements: base salary, short term and long term incentive compensation. While
these elements are related to the extent that compensation policy is compared
in total to the competitive practices of other major Canadian employers,
individual decisions on base salary, short term and long term incentive
compensation are made independently of each other.
Base
salary
The Companys salary ranges for executives were increased by four and one
half percent in 2002, and three percent in 2003 and two and one half percent in
2004. High performing executives, and those recently promoted, whose salaries
were low relative to their level of responsibility, were given limited
additional salary increases. This included senior executives.
T.J. Hearns salary is currently assessed to be below the competitive
target for the Companys chief executive officer which is between the median
and upper quartile. The target is consistent with the executive resources
committees view that the chief executive officers salary should be above the
average of salaries for chief executive officers of major Canadian companies,
reflecting the Companys executive development philosophy and the significance
placed on experience and judgment in leading a large, complex operation.
Cash
bonus
Cash bonuses are typically granted to about 90 executives at the end of
each year, based on individual performance. The bonuses are drawn from an
aggregate bonus amount established annually by the executive resources
committee based on the Companys financial performance, and are granted in
tandem with the Companys earnings bonus units, which are described on page 41.
In 2003, the executive resources committee increased the bonus awards
including the grant of earnings bonus units to reflect the Companys record
financial results and in response to comparisons to other leading Canadian
employers.
In the case of T.J. Hearn, the committees approach to cash bonuses is
based on the Companys financial and operating performance and on the
committees assessment of T.J. Hearns effectiveness in leading the
organization. The continuing progress being made in focussing the organization
on advancing key strategic interests, safety, environmental performance,
productivity, cost effectiveness and asset management were primary
considerations in determining a cash bonus for the chief executive officer.
T.J. Hearns bonus including the grant of earnings bonus units was increased in
2003 to reflect his effectiveness in the position, the Companys record
financial results, and comparisons to other leading Canadian employers.
44
Long
term incentive compensation
Each year, the executive resources committee has approved long term
incentive awards for selected key employees. These awards were an added
incentive to promote individual contribution to sustained improvement in
business performance and shareholder value, and to encourage key employees to
remain with the Company. Individual awards reflected both level of
responsibility and performance, with an emphasis on ability to influence longer
term results. In each case, including senior executives and the chief executive
officer, award amounts took into account the competitive practices of other
major Canadian employers and were not influenced by prior years results or by
an individuals holdings of unexercised long term incentive compensation units.
Incentive awards also have been awarded selectively to the general
managerial, professional and technical (non-executive) workforce as a way of
delivering added financial incentive to selected high performing employees.
For selected executives, the executive resources committee allows cash
bonus awards to be elected to be received in the form of deferred share units
and also awards earnings bonus units as a means of providing additional
incentive to promote the Companys long term financial performance. Eligibility
to participate in the deferred share unit and earnings bonus plans is
restricted to those executives whose decisions are considered to have a direct
effect on the long term financial performance of the Company. In 2003, no
executives elected to receive deferred share units and 83 executives were
awarded earnings bonus units.
For many years, the Companys long term incentive compensation programs
have been cash based programs tied to earnings and share performance, and
incentive awards have been reported as expenses in the consolidated statement
of earnings. In 2002, to meet competitive practices, the Company introduced a
stock option program. However, recognizing current concerns over stock option
incentive programs and their proper accounting treatment, the Company decided
to return to straightforward, cash based incentive compensation programs that
will again be reported as expenses against earnings. There are no plans to
issue stock options in the future.
A total of 618 employees, including executives, were granted restricted stock
units in 2003.
Submitted on behalf of the executive resources committee:
|
|
P.Des Marais II - Chair
R. Phillips - Vice-chair
J.F. Shepard S.D. Whittaker
V.L. Young |
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
To the knowledge of the management of the Company, the only shareholder
who, as of February 18, 2004, owned beneficially, or exercised control or
direction over, more than five percent of the outstanding common shares of the
Company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard, Irving, Texas
75039-2298, which owns beneficially 251,464,070 common shares, representing
69.6 percent of the outstanding voting shares of the Company.
Reference is made to the security ownership information under the
preceding Items 10 and 11. As of February 18, 2004, John F. Kyle was the owner
of 3,551 common shares of the Company and held options to acquire 29,000 common
shares of the Company and restricted share units to acquire 5,700 common shares
of the Company.
The directors and the senior executives of the Company consist of 10
persons, who, as a group, own beneficially 90,024 common shares of the Company,
being approximately 0.02 percent of the total number of outstanding shares of
the Company, and 85,509 shares of Exxon Mobil Corporation. This information not
being within the knowledge of the Company has been provided by the directors
and the senior executives individually. As a group, the directors and senior
executives of the Company held options to acquire 314,000 common shares of the
Company and held restricted stock units to acquire 109,175 common shares of the
Company, as of February 18, 2004.
45
Equity Compensation Plan Information as of December 31, 2003
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Number of securities |
|
|
|
|
|
|
|
|
|
|
remaining available for future |
|
|
Number of securities to |
|
Weighted-average |
|
issuance under equity |
|
|
be issued upon exercise |
|
excercise price of |
|
compensation plans (excluding |
|
|
of outstanding options, |
|
outstanding options, |
|
securities reflected in |
|
|
warrants and rights |
|
warrants and rights |
|
column (a)) |
Plan category
|
|
(a)
|
|
(b)
|
|
(c)
|
Equity
compensation plans approved by
security holders (1) |
|
|
3,210,200 |
|
|
$ |
46.50 |
|
|
|
13,289,800 |
|
Equity compensation plans not approved
by security holders (2) |
|
|
321,162 |
|
|
not applicable |
|
|
3,178,838 |
|
Total |
|
|
3,531,362 |
|
|
|
|
|
|
|
16,468,638 |
|
(1) |
|
This is the stock option plan, which is described on page
41 of this report. |
|
(2) |
|
This is the restricted stock unit plan,
which is described on page 41 of this report. |
Item 13. Certain Relationships and Related Transactions.
On June 21, 2002, the Company implemented another 12-month normal course
share-purchase program under which it purchased 6,390,770 of its outstanding
shares between June 21, 2002, and June 20, 2003. On June 23, 2003, another
12-month normal course program was implemented under which the Company may
purchase up to 18,632,218 of its outstanding shares, less any shares purchased
by the employee savings plan and Company pension fund. Exxon Mobil Corporation
participated by selling shares to maintain its ownership at 69.6 percent. In
2003, such purchases cost $799 million, of which $555 million was received by
ExxonMobil.
During 2003, the Company borrowed $818 million from Exxon Overseas
Corporation under two long term loan agreements at interest equivalent to
Canadian market rates. Interest paid on the loans in 2003 was $14 million. The
average effective interest rates for the loans was 3.1 percent for 2003.
The amounts of purchases and sales by the Company and its subsidiaries for
other transactions in 2002 with Exxon Mobil Corporation and affiliates of Exxon
Mobil Corporation were $2,478 million and $950 million, respectively. These
transactions were conducted on terms as favorable as they would have been with
unrelated parties, and primarily consisted of the purchase and sale of crude
oil, petroleum and chemical products, as well as transportation, technical and
engineering services. Transactions with Exxon Mobil Corporation also include
amounts paid and received in connection with the Companys participation in a
number of natural resources joint venture operations in Canada.The Company has
an existing agreement with ExxonMobil Canada Ltd., to share common business and
operational support services that allow the companies to consolidate duplicate
work and systems.
Item 14. Principal Accountant Fees and Services.
The aggregate fees of the Companys auditors for professional services
rendered for the audit of the Companys financial statements and other services
for the fiscal years ended December 31, 2003 and December 31, 2002 were as
follows:
|
|
|
|
|
|
|
|
|
Dollars (thousands)
|
|
2003
|
|
2002
|
Audit Fees |
|
|
767 |
|
|
|
747 |
|
Audit-Related Fees |
|
|
62 |
|
|
|
111 |
|
Tax Fees |
|
|
395 |
|
|
|
255 |
|
All Other Fees |
|
|
Nil |
|
|
|
Nil |
|
Total Fees |
|
|
1,224 |
|
|
|
1,113 |
|
Audit fees include the audit of the Companys annual financial statements
and a review of the first three quarterly financial statements in 2003.
Audit-related fees include other assurance services including the audit of
the Companys retirement plan, the Imperial Oil Foundation, and royalty
statement audits for oil and gas producing entities.
Tax fees are mainly tax services for employees on foreign loan assignments.
All other fees would include other services including financial systems
consulting and implementation. The Company did not engage the auditors for
these types of services.
46
The audit committee recommends the external auditors to be appointed by
the shareholders, fixes their remuneration and oversees their work. The audit
committee also approves the proposed current year audit program of the
auditors, assesses the results of the program after the end of the program
period and approves in advance any non-audit services to be performed by the
auditors after considering the effect of such services on their independence.
All of the services rendered by the auditors to the Company were approved by
the audit committee.
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K.
Reference is made to the Index to Financial Statements on page F-1 of this
report.
The following exhibits numbered in accordance with Item 601 of Regulation
S-K are filed as part of this report:
|
|
|
|
|
|
|
(3)
|
|
(i)
|
|
Restated certificate and articles of incorporation of the Company
(Incorporated herein by reference to Exhibit (3) to the Companys Quarterly
Report on Form 10-Q for the quarter ended June 30, 1998 (File No. 0-12014)). |
|
|
|
|
|
|
|
|
(ii)
|
|
By-laws of the Company (Incorporated herein by reference to Exhibit
(3)(ii) to the Companys Quarterly Report on Form 10-Q for the quarter ended
March 31, 2003 (File No. 0-12014)). |
|
|
|
|
|
|
(4)
|
|
|
|
The Companys long term debt authorized under any instrument does not
exceed 10 percent of the Companys consolidated assets. The Company agrees to
furnish to the Commission upon request a copy of any such instrument. |
|
|
|
|
|
|
|
|
|
|
|
(10)
|
|
(ii)
|
|
|
(1 |
) |
|
Alberta Crown Agreement, dated February 4, 1975, relating to the
participation of the Province of Alberta in Syncrude (Incorporated herein by
reference to Exhibit 13(a) of the Companys Registration Statement on Form S-1,
as filed with the Securities and Exchange Commission on August 21, 1979 (File
No. 2-65290)). |
(2) |
|
Amendment to Alberta Crown Agreement, dated January 1, 1983
(Incorporated herein by reference to Exhibit (10)(ii)(2) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1983 (File No.
2-9259)). |
|
(3) |
|
Syncrude Ownership and Management Agreement, dated February 4, 1975
(Incorporated herein by reference to Exhibit 13(b) of the Companys
Registration Statement on Form S-1, as filed with the Securities and Exchange
Commission on August 21, 1979 (File No. 2-65290)). |
|
(4) |
|
Letter Agreement, dated
February 8, 1982, between the Government of Canada and Esso Resources Canada
Limited, amending Schedule C to the Syncrude Ownership and Management
Agreement filed as Exhibit (10)(ii)(2) (Incorporated herein by reference to
Exhibit (20) of the Companys Annual Report on Form 10-K for the year ended
December 31, 1981 (File No. 2-9259)). |
|
(5) |
|
Norman Wells Pipeline Agreement, dated January 1, 1980, relating to the
operation, tolls and financing of the pipeline system from the Norman Wells
field (Incorporated herein by reference to Exhibit 10(a)(3) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1981 (File No.
2-9259)). |
|
(6) |
|
Norman Wells Pipeline Amending Agreement, dated April 1, 1982
(Incorporated herein by reference to Exhibit (10)(ii)(5) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1982 (File No.
2-9259)). |
|
(7) |
|
Letter Agreement clarifying certain provisions to the Norman Wells Pipeline
Agreement, dated August 29, 1983 (Incorporated herein by reference to Exhibit
(10)(ii)(7) of the Companys Annual Report on Form 10-K for the year ended
December 31, 1983 (File No. 2-9259)). |
|
(8) |
|
Norman Wells Pipeline Amending
Agreement, made as of February 1, 1985, relating to certain amendments ordered
by the National Energy Board (Incorporated herein by reference to Exhibit
(10)(ii)(8) of the Companys Annual Report on Form 10-K for the year ended
December 31, 1986 (File No. 0-12014)). |
47
(9) |
|
Norman Wells Pipeline Amending Agreement, made as of April 1, 1985,
relating to the definition of Operating Year (Incorporated herein by
reference to Exhibit (10)(ii)(9) of the Companys Annual Report on Form 10-K
for the year ended December 31, 1986 (File No. 0-12014)). |
|
(10) |
|
Norman Wells
Expansion Agreement, dated October 6, 1983, relating to the prices and
royalties payable for crude oil production at Norman Wells (Incorporated herein
by reference to Exhibit (10)(ii)(8) of the Companys Annual Report on Form 10-K
for the year ended December 31, 1983 (File No. 2-9259)). |
|
(11) |
|
Alberta Cold Lake Crown Agreement, dated June 25, 1984, relating to the
royalties payable and the assurances given in respect of the Cold Lake
production project (Incorporated herein by reference to Exhibit (10)(ii)(11)
of the Companys Annual Report on Form 10-K for the year ended December 31,
1986 (File No. 0-12014)). |
|
(12) |
|
Amendment to Alberta Crown Agreement, dated January 1, 1986
(Incorporated herein by reference to Exhibit (10)(ii)(12) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1987 (File No.
0-12014)). |
|
(13) |
|
Amendment to Alberta Crown Agreement, dated November 25, 1987
(Incorporated herein by reference to Exhibit (10)(ii)(13) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1987 (File No.
0-12014)). |
|
(14) |
|
Amendment to Syncrude Ownership and Management Agreement, dated March
10, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(14) of the
Companys Annual Report on Form 10-K for the year ended December 31, 1989
(File No. 0-12014)). |
|
(15) |
|
Amendment to Alberta Crown Agreement, dated August 1, 1991 (Incorporated
herein by reference to Exhibit (10)(ii)(15) of the Companys Annual Report on
Form 10-K for the year ended December 31, 1991 (File No. 0-12014))) |
|
(16) |
|
Norman
Wells Settlement Agreement, dated July 31, 1996. (Incorporated herein by
reference to Exhibit (10)(ii)(16) of the Companys Annual Report on Form 10-K
for the year ended December 31, 1996 (File No. 0-12014)). |
|
(17) |
|
Amendment to Alberta Crown Agreement, dated January 1, 1997.
(Incorporated herein by reference to Exhibit (10)(ii)(17) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1996 (File No.
0-12014)). |
|
(18) |
|
Norman Wells Pipeline Amending Agreement, dated December 12, 1997.
(Incorporated herein by reference to Exhibit (10)(ii)(18) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1998 (File No.
0-12014)). |
|
(19) |
|
Norman Wells Pipeline 1999 Amending Agreement, dated May 1, 1999.
(Incorporated herein by reference to Exhibit (10)(ii)(19) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1999 (File No.
0-12014)). |
|
(20) |
|
Alberta Cold Lake Transition Agreement, effective January 1, 2000,
relating to the royalties payable in respect of the Cold Lake production
project and terminating the Alberta Cold Lake Crown Agreement. (Incorporated
herein by reference to Exhibit (10)(ii)(20) of the Companys Annual Report
on Form 10-K for the year ended December 31, 2001 (File No. 0-12014)). |
|
(21) |
|
Amendment to Alberta Crown Agreement effective January 1, 2001
(Incorporated herein by reference to Exhibit (10)(ii)(21) of the Companys
Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No.
0-12014)). |
|
(22) |
|
Amendment to Syncrude Ownership and Management Agreement effective
January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(22) of
the Companys Quarterly Report on Form 10-Q for the quarter ended June 30,
2002 (File No. 0-12014)). |
|
(23) |
|
Amendment to Syncrude Ownership and Management Agreement effective
September 16, 1994 (Incorporated herein by reference to Exhibit (10)(ii)(23)
of the Companys Quarterly Report on Form 10-Q for the quarter ended June
30, 2002 (File No. 0-12014)). |
|
(24) |
|
Amendment to Alberta Crown Agreement dated November 29, 1995
(Incorporated herein by reference to Exhibit (10)(ii)(24) of the Companys
Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No.
0-12014)). |
|
|
|
(iii)(A)(1)
|
|
Form of Letter relating to Supplemental Retirement Income
(Incorporated herein by reference to Exhibit (10)(c)(3) of the Companys Annual
Report on Form 10-K for the year ended December 31, 1980 (File No. 2-9259)). |
48
(2) |
|
Incentive Share Unit Plan and Incentive Share Units granted in 2001
are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the
Companys Annual Report on Form 10-K for the year ended December 31,
2001. Units granted in 2000 are incorporated herein by reference to
Exhibit (10)(iii)(A)(2) of the Companys Annual Report on Form 10-K for
the year ended December 31, 2000 (File No. 0-12014); units granted in
1999 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of
the Companys Annual Report on Form 10-K for the year ended December 31,
1999 (File No. 0-12014); units granted in 1998 are incorporated herein by
reference to Exhibit (10)(iii)(A)(3) of the Companys Annual Report on
Form 10-K for the year ended December 31, 1998 (File No. 0-12014); units
granted in 1997 are incorporated herein by reference to Exhibit
(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year
ended December 31, 1997 (File No. 0-12014); units granted in 1996 are
incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the
Companys Annual Report on Form 10-K for the year ended December 31, 1996
(File No. 0-12014); units granted in 1995 are incorporated herein by
reference to Exhibit (10)(iii)(A)(3) of the Companys Annual Report on
Form 10-K for the year ended December 31, 1995 (File No. 0-12014); and
units granted in 1994 are incorporated herein by reference to Exhibit
(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year
ended December 31, 1994 (File No. 0-12014). |
|
(3) |
|
Deferred Share Unit Plan. (Incorporated herein by reference to
Exhibit(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for the
year ended December 31, 1998 (File No. 0-12014)). |
|
(4) |
|
Deferred Share Unit Plan for Nonemployee Directors. (Incorporated
herein by reference to Exhibit (10)(iii)(A)(6) of the Companys Annual
Report on Form 10-K for the year ended December 31, 1998 (File No.
0-12014)). |
|
(5) |
|
Earnings Bonus Units granted in 2003; Earnings Bonus Unit Plan and
units granted in 2002 are (incorporated herein by reference to Exhibit
(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for the year
ended December 31, 2002 (File No. 0-12014)) and Earnings Bonus Unit Plan
and units granted in 2001 are incorporated herein by reference to Exhibit
(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for the year
ended December 31, 2000 (File No. 0-12014). |
|
(6) |
|
Incentive Stock Option Plan and Incentive Stock Options granted in
2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the
Companys Quarterly Report on Form 10-Q for the quarter ended June 30,
2002 (File No. 0-12014)). |
|
(7) |
|
Restricted Stock Unit Plan and Restricted Stock Units granted in 2002
(incorporated herein by reference to Exhibit (10)(iii)(A)(7) of the
Companys Annual Report on Form 10-K for the year ended December 31, 2002
(File No. 0-12014)). |
|
(8) |
|
Restricted Stock Unit Plan and Restricted Stock Units granted in 2003. |
|
|
|
|
|
|
|
|
|
|
|
|
|
(21)
|
Imperial Oil Resources Limited, McColl-Frontenac Petroleum Inc., Imperial
Oil Resources N.W.T.
Limited and Imperial Oil Resources Ventures Limited, all incorporated in
Canada, are wholly-owned subsidiaries of the Company. The names of all other
subsidiaries of the Company are omitted because, considered in the aggregate
as a single subsidiary, they would not constitute a significant subsidiary
as of December 31, 2003. |
|
|
|
|
|
|
|
|
(23)
|
|
(ii)
|
|
(A)
|
|
Consent of PricewaterhouseCoopers LLP. |
|
|
|
|
|
|
|
|
|
|
|
|
(B)
|
|
Consent of Chief Engineering Officer. |
(31.1) |
|
Certification by principal executive officer of Periodic Financial
Report pursuant to Rule 13a-14(a) |
|
(31.2) |
|
Certification by principal financial
officer of Periodic Financial Report pursuant to Rule 13a-14(a). |
|
(32.1) |
|
Certification by chief executive officer of Periodic Financial Report pursuant
to Rule 13a-14(b) and 18 U.S.C. Section 1350. |
|
(32.2) |
|
Certification by chief financial officer of Periodic Financial Report
pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350. |
Copies of Exhibits may be acquired upon written request of any shareholder
to the investor relations manager, Imperial Oil Limited, 111 St. Clair Avenue
West, Toronto, Ontario, Canada M5W 1K3, and payment of processing and mailing
costs.
Except for a report on Form 8-K dated October 28, 2003, the Company did
not file any other reports on Form 8-K during the fourth quarter of 2003. By
the report on Form 8-K dated October 28, 2003, the Company submitted to the
Securities and Exchange Commission a press release of the Company on October
23, 2003 disclosing information relating to the Companys financial condition
and results of operations for the fiscal quarter ended September 30, 2003.
49
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 on March 11, 2004 by the undersigned, thereunto duly authorized.
|
|
|
|
|
|
|
IMPERIAL OIL LIMITED |
|
|
|
|
|
|
|
By |
|
/s/ T.J. Hearn |
|
|
|
|
|
|
|
|
|
(Timothy J. Hearn, Chairman of the Board,
President and Chief Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below on March 11, 2004 by the following persons on
behalf of the registrant and in the capacities indicated.
|
|
|
Signature
|
|
Title
|
|
/s/ T.J. Hearn |
|
|
(Timothy J. Hearn)
|
|
Chairman of the Board, President,
Chief Executive Officer and Director
(Principal Executive Officer) |
|
/s/ Paul A. Smith |
|
|
(Paul A. Smith)
|
|
Controller and Senior Vice-President,
Finance and Administration and Director
(Principal Accounting Officer and
Principal Financial Officer) |
|
/s/ Pierre Des Marais II |
|
|
(Pierre Des Marais II)
|
|
Director |
|
/s/ Brian J. Fischer |
|
|
(Brian J. Fischer)
|
|
Director |
|
/s/ Roger Phillips |
|
|
(Roger Phillips)
|
|
Director |
|
/s/ J. Shepard |
|
|
(James F. Shepard)
|
|
Director |
|
/s/ Sheelagh D. Whittaker |
|
|
(Sheelagh D. Whittaker)
|
|
Director |
|
/s/ K. C. Williams |
|
|
(K.C. Williams)
|
|
Director |
|
/s/ Victor L. Young |
|
|
(Victor L. Young)
|
|
Director |
50
INDEX TO FINANCIAL STATEMENTS
|
|
|
|
|
Pages in this |
|
|
Report
|
Auditors report |
|
F-2 |
Financial statements: |
|
|
Consolidated statement of earnings for the years 1999,
2000, 2001, 2002 and 2003 |
|
F-3 |
Consolidated statement of cash flows for the years 1999,
2000, 2001, 2002 and 2003 |
|
F-4 |
Consolidated balance sheet as at December 31, 1999, 2000,
2001, 2002 and 2003 |
|
F-5 |
Summary of significant accounting policies |
|
F-6 F-8 |
Notes to the consolidated financial statements |
|
F-9 F18 |
F-1
Auditors Report
To the Directors of
Imperial Oil Limited
We have audited the consolidated balance sheets of Imperial Oil Limited as at
December 31, 2003 and 2002 and the consolidated statements of earnings and cash
flows for each of the three years in the period ended December 31, 2003. These
financial statements are the responsibility of the Companys management. Our
responsibility is to express an opinion on these financial statements based on
our audits.
We conducted our audits in accordance with auditing standards generally
accepted in Canada and the United States. 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,
2003 and 2002 and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003 in accordance with
Canadian generally accepted accounting principles.
We have also audited the Reconciliation of Canadian and United States
generally accepted accounting principles in Item 6 of this 10-K as at December
31, 2003 and 2002 and for each of the three years in the period ended December
31, 2003. In our opinion, the Reconciliation of Canadian and United States
generally accepted accounting principles is presented fairly, in all material
respects, when read in conjunction with the related consolidated financial
statements.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLP
Chartered Accountants
Toronto, Ontario
February 18, 2004
F-2
Consolidated statement of earnings (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars |
|
|
|
|
|
|
|
|
|
|
For the years ended December 31
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues (b) |
|
|
19,094 |
|
|
|
16,890 |
|
|
|
17,153 |
|
|
|
17,829 |
|
|
|
12,763 |
|
Investment and other income |
|
|
114 |
|
|
|
152 |
|
|
|
100 |
|
|
|
222 |
|
|
|
90 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
19,208 |
|
|
|
17,042 |
|
|
|
17,253 |
|
|
|
18,051 |
|
|
|
12,853 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
55 |
|
|
|
30 |
|
|
|
45 |
|
|
|
35 |
|
|
|
28 |
|
Purchases of crude oil and products |
|
|
11,580 |
|
|
|
10,155 |
|
|
|
10,134 |
|
|
|
10,772 |
|
|
|
7,091 |
|
Operating |
|
|
2,025 |
|
|
|
1,865 |
|
|
|
1,830 |
|
|
|
1,554 |
|
|
|
1,511 |
|
Selling and general |
|
|
1,269 |
|
|
|
1,222 |
|
|
|
1,280 |
|
|
|
1,271 |
|
|
|
1,251 |
|
Federal excise tax (b) |
|
|
1,254 |
|
|
|
1,231 |
|
|
|
1,180 |
|
|
|
1,194 |
|
|
|
1,188 |
|
Depreciation and depletion |
|
|
750 |
|
|
|
705 |
|
|
|
718 |
|
|
|
726 |
|
|
|
736 |
|
Financing costs (note 12) |
|
|
(87 |
) |
|
|
32 |
|
|
|
152 |
|
|
|
163 |
|
|
|
38 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
16,846 |
|
|
|
15,240 |
|
|
|
15,339 |
|
|
|
15,715 |
|
|
|
11,843 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings before income taxes |
|
|
2,362 |
|
|
|
1,802 |
|
|
|
1,914 |
|
|
|
2,336 |
|
|
|
1,010 |
|
Income taxes (note 4) |
|
|
680 |
|
|
|
578 |
|
|
|
659 |
|
|
|
926 |
|
|
|
382 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
1,682 |
|
|
|
1,224 |
|
|
|
1,255 |
|
|
|
1,410 |
|
|
|
628 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per-share information (dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings
basic and diluted (note 10) |
|
|
4.52 |
|
|
|
3.23 |
|
|
|
3.19 |
|
|
|
3.38 |
|
|
|
1.46 |
|
Dividends |
|
|
0.87 |
|
|
|
0.84 |
|
|
|
0.83 |
|
|
|
0.78 |
|
|
|
0.75 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Business segments are reported in note 1. |
|
(b) |
|
Operating revenues include
federal excise tax of $1,254 million (2002
$1,231 million; 2001 $1,180
million). |
The information on pages F-6
through F-18 is part of these
consolidated financial
statements. Certain figures for
prior years have been
reclassified in the financial
statements to conform with the
current years presentation. The
effects of new accounting
standards on the consolidated
statement of earnings and balance
sheet are described in note 2.
F-3
Consolidated statement of cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars |
|
|
|
|
|
|
|
|
|
|
inflow (outflow) |
|
|
|
|
|
|
|
|
|
|
For the years ended December 31
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
Operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
1,682 |
|
|
|
1,224 |
|
|
|
1,255 |
|
|
|
1,410 |
|
|
|
628 |
|
Depreciation and depletion |
|
|
750 |
|
|
|
705 |
|
|
|
718 |
|
|
|
726 |
|
|
|
736 |
|
(Gain)/loss on asset sales, after tax |
|
|
(10 |
) |
|
|
(4 |
) |
|
|
(7 |
) |
|
|
(96 |
) |
|
|
(17 |
) |
Future income taxes and other |
|
|
(68 |
) |
|
|
(144 |
) |
|
|
50 |
|
|
|
(175 |
) |
|
|
(324 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from earnings (note 11) |
|
|
2,354 |
|
|
|
1,781 |
|
|
|
2,016 |
|
|
|
1,865 |
|
|
|
1,023 |
|
Accounts receivable |
|
|
33 |
|
|
|
(356 |
) |
|
|
504 |
|
|
|
(358 |
) |
|
|
(124 |
) |
Inventories and prepaids |
|
|
31 |
|
|
|
51 |
|
|
|
(11 |
) |
|
|
(6 |
) |
|
|
(16 |
) |
Income taxes payable |
|
|
38 |
|
|
|
(225 |
) |
|
|
(408 |
) |
|
|
503 |
|
|
|
225 |
|
Accounts payable and other (a) |
|
|
(262 |
) |
|
|
425 |
|
|
|
(97 |
) |
|
|
85 |
|
|
|
362 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in operating assets and liabilities |
|
|
(160 |
) |
|
|
(105 |
) |
|
|
(12 |
) |
|
|
224 |
|
|
|
447 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash from operating activities |
|
|
2,194 |
|
|
|
1,676 |
|
|
|
2,004 |
|
|
|
2,089 |
|
|
|
1,470 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property, plant
and equipment and intangibles |
|
|
(1,449 |
) |
|
|
(1,552 |
) |
|
|
(1,070 |
) |
|
|
(644 |
) |
|
|
(625 |
) |
Proceeds from asset sales |
|
|
56 |
|
|
|
61 |
|
|
|
46 |
|
|
|
274 |
|
|
|
88 |
|
Proceeds from marketable securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
116 |
|
|
|
59 |
|
Additions to marketable securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(58 |
) |
|
|
(88 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash from (used in) investing activities |
|
|
(1,393 |
) |
|
|
(1,491 |
) |
|
|
(1,024 |
) |
|
|
(312 |
) |
|
|
(566 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
debt net |
|
|
|
|
|
|
(388 |
) |
|
|
385 |
|
|
|
75 |
|
|
|
|
|
Long-term debt issued |
|
|
818 |
|
|
|
500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Repayment of long-term debt |
|
|
(818 |
) |
|
|
(71 |
) |
|
|
(379 |
) |
|
|
(68 |
) |
|
|
(379 |
) |
Issuance of common shares
under stock option plan |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares purchased (note 10) |
|
|
(799 |
) |
|
|
(13 |
) |
|
|
(812 |
) |
|
|
(1,208 |
) |
|
|
|
|
Dividends paid |
|
|
(322 |
) |
|
|
(319 |
) |
|
|
(322 |
) |
|
|
(331 |
) |
|
|
(319 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash from (used in) financing activities |
|
|
(1,119 |
) |
|
|
(291 |
) |
|
|
(1,128 |
) |
|
|
(1,532 |
) |
|
|
(698 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash |
|
|
(318 |
) |
|
|
(106 |
) |
|
|
(148 |
) |
|
|
245 |
|
|
|
206 |
|
Cash at beginning of year |
|
|
766 |
|
|
|
872 |
|
|
|
1,020 |
|
|
|
775 |
|
|
|
569 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash at end of year (b) |
|
|
448 |
|
|
|
766 |
|
|
|
872 |
|
|
|
1,020 |
|
|
|
775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Includes contribution to
registered pension plans of $511
million (2002 $19 million; 2001
$6 million). |
(b) |
|
Cash is composed of cash in
bank and cash equivalents at cost.
Cash equivalents are all highly
liquid securities with a
maturity of three months or less
when purchased. |
The information on pages F-6
through F-18 is part of these
consolidated financial
statements. Certain figures for
prior years have been
reclassified in the financial
statements to conform with the
current years presentation.
F-4
Consolidated balance sheet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars |
|
|
|
|
|
|
|
|
|
|
At December 31
|
|
2003
|
|
2002
|
|
2001
|
|
2000
|
|
1999
|
Assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash |
|
|
448 |
|
|
|
766 |
|
|
|
872 |
|
|
|
1,020 |
|
|
|
775 |
|
Marketable securities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
59 |
|
Accounts receivable (note 11) |
|
|
1,315 |
|
|
|
1,348 |
|
|
|
992 |
|
|
|
1,496 |
|
|
|
1,138 |
|
Inventories of crude oil and products (note 11) |
|
|
407 |
|
|
|
433 |
|
|
|
478 |
|
|
|
421 |
|
|
|
451 |
|
Materials, supplies and prepaid expenses |
|
|
105 |
|
|
|
110 |
|
|
|
116 |
|
|
|
162 |
|
|
|
125 |
|
Future income tax assets (note 4) |
|
|
353 |
|
|
|
323 |
|
|
|
227 |
|
|
|
377 |
|
|
|
285 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current assets |
|
|
2,628 |
|
|
|
2,980 |
|
|
|
2,685 |
|
|
|
3,476 |
|
|
|
2,833 |
|
Investments and other
long-term assets (note 5) |
|
|
259 |
|
|
|
134 |
|
|
|
139 |
|
|
|
127 |
|
|
|
172 |
|
Property, plant and equipment (note 1) |
|
|
9,218 |
|
|
|
8,525 |
|
|
|
7,722 |
|
|
|
7,391 |
|
|
|
7,549 |
|
Goodwill (note 1) |
|
|
204 |
|
|
|
204 |
|
|
|
204 |
|
|
|
232 |
|
|
|
260 |
|
Other intangible assets (note 1) |
|
|
52 |
|
|
|
51 |
|
|
|
31 |
|
|
|
18 |
|
|
|
14 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (note 1) |
|
|
12,361 |
|
|
|
11,894 |
|
|
|
10,781 |
|
|
|
11,244 |
|
|
|
10,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Short-term debt |
|
|
72 |
|
|
|
72 |
|
|
|
460 |
|
|
|
75 |
|
|
|
|
|
Accounts payable and accrued
liabilities (note 13) |
|
|
2,222 |
|
|
|
2,114 |
|
|
|
1,791 |
|
|
|
1,866 |
|
|
|
1,731 |
|
Income taxes payable |
|
|
595 |
|
|
|
557 |
|
|
|
774 |
|
|
|
1,182 |
|
|
|
666 |
|
Current portion of long-term debt |
|
|
501 |
|
|
|
|
|
|
|
|
|
|
|
300 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total current liabilities |
|
|
3,390 |
|
|
|
2,743 |
|
|
|
3,025 |
|
|
|
3,423 |
|
|
|
2,397 |
|
Long-term debt (note 3) |
|
|
859 |
|
|
|
1,466 |
|
|
|
1,029 |
|
|
|
1,037 |
|
|
|
1,352 |
|
Other long-term obligations (note 6) |
|
|
972 |
|
|
|
1,207 |
|
|
|
1,098 |
|
|
|
1,104 |
|
|
|
1,172 |
|
Future income tax liabilities (note 4) |
|
|
1,362 |
|
|
|
1,262 |
|
|
|
1,306 |
|
|
|
1,476 |
|
|
|
1,580 |
|
Commitments and contingent liabilities (note 9) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities |
|
|
6,583 |
|
|
|
6,678 |
|
|
|
6,458 |
|
|
|
7,040 |
|
|
|
6,501 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Common shares at stated value (note 10) |
|
|
1,859 |
|
|
|
1,939 |
|
|
|
1,941 |
|
|
|
2,039 |
|
|
|
2,209 |
|
Net earnings retained and
used in the business |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At beginning of year |
|
|
3,277 |
|
|
|
2,382 |
|
|
|
2,165 |
|
|
|
2,118 |
|
|
|
1,814 |
|
Net earnings for the year |
|
|
1,682 |
|
|
|
1,224 |
|
|
|
1,255 |
|
|
|
1,410 |
|
|
|
628 |
|
Share purchases (note 10) |
|
|
(717 |
) |
|
|
(11 |
) |
|
|
(714 |
) |
|
|
(1,038 |
) |
|
|
|
|
Dividends |
|
|
(323 |
) |
|
|
(318 |
) |
|
|
(324 |
) |
|
|
(325 |
) |
|
|
(324 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
At end of year |
|
|
3,919 |
|
|
|
3,277 |
|
|
|
2,382 |
|
|
|
2,165 |
|
|
|
2,118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total shareholders equity |
|
|
5,778 |
|
|
|
5,216 |
|
|
|
4,323 |
|
|
|
4,204 |
|
|
|
4,327 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders equity |
|
|
12,361 |
|
|
|
11,894 |
|
|
|
10,781 |
|
|
|
11,244 |
|
|
|
10,828 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The information on pages F-6
through F-18 is part of these
consolidated financial
statements. Certain figures for
prior years have been
reclassified in the financial
statements to conform with the
current years presentation. The
effects of new accounting
standards on the consolidated
statement of earnings and balance
sheet are described in note 2.
Approved by the directors
|
|
|
/s/ T.J. Hearn
|
|
/s/ P.A. Smith |
Chairman, president and
|
|
Controller and senior vice-president, |
chief executive officer
|
|
finance and administration |
F-5
Summary of significant accounting policies
Principles of consolidation
The consolidated financial statements include the accounts of the Company
and its subsidiaries. Intercompany accounts and transactions are eliminated.
Subsidiaries include those companies in which the Company has both an equity
interest and the continuing ability to unilaterally determine strategic
operating, investing and financing policies. Significant subsidiaries included
in the consolidated financial statements include Imperial Oil Resources
Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures
Limited and McColl-Frontenac Petroleum Inc. All of the above companies are
wholly owned. A significant portion of the Companys activities in natural
resources is conducted jointly with other companies. The accounts reflect the
Companys proportionate interest in such activities, including its 25-percent
interest in the Syncrude joint venture and its nine-percent interest in the
Sable offshore energy project.
Segment reporting
The Company operates its business in Canada in the following segments:
Natural resources includes the exploration for and production of crude oil
and natural gas.
Petroleum products comprises the refining of crude oil into petroleum
products and the distribution and marketing of these products.
Chemicals includes the manufacturing and marketing of various
hydrocarbon-based chemicals and chemical products.
Corporate and other includes
assets and liabilities that do not specifically relate to business
segments
primarily cash, marketable securities and long-term debt. Net earnings in this
category primarily include debt-related charges and interest income.
Segment accounting policies are the same as those described in this
summary of significant accounting policies. Natural resources, petroleum
products and chemicals expenses include amounts allocated from the corporate
and other segment. The allocation is based on a combination of fee for
service, proportional segment expenses and a three-year average of capital
expenditures. Transfers of assets between segments are recorded at book
amounts. Items included in capital employed that are not identifiable by
segment are allocated according to their nature.
Accounts receivable
Accounts receivable arise mainly from customer purchases of the Companys
products. Interest is accrued on overdue accounts (generally those over 30
days) and is reported in investment and other income in the consolidated
statement of earnings. Interest accrual will be suspended if collection becomes
doubtful. An allowance for doubtful accounts is established based upon an
assessment of the collectability of individual larger account balances and upon
historical experience, economic and judgmental factors collectively for groups
of smaller homogeneous accounts. Accounts are written off when judged to be
uncollectable.
Inventories
Inventories are recorded at the lower of cost or net realizable value. The
cost of crude oil and products is determined primarily using the last-in,
first-out (LIFO) method. LIFO was selected over the alternative first-in,
first-out and average cost methods because it provides a better matching of
current costs with the revenues generated in the period.
Inventory costs include expenditures and other charges, including
depreciation, directly or indirectly incurred in bringing the inventory to its
existing condition and final storage prior to delivery to a customer. Selling
and general expenses are reported as period costs and excluded from inventory
cost.
Investments
The principal investments in companies other than subsidiaries are
accounted for using the equity method. They are recorded at the original cost
of the investment plus the Companys share of earnings since the investment was
made, less dividends received. The Companys share of the after-tax earnings of
these companies is included in investment and other income in the
consolidated statement of earnings. Other investments are recorded at cost.
Dividends from these other investments are included in investment and other
income.
These investments represent interests in non-publicly traded pipeline
companies that facilitate the sale and purchase of crude oil and natural gas in
the conduct of the Company operations. Other parties who also have an equity
interest in these companies share in the risks and rewards according to their
percentage of ownership. The Companys does not invest in these companies in
order to remove liabilities from its balance sheet.
F-6
Property, plant and equipment
Property, plant and equipment are recorded at cost.
Investment tax credits and other similar grants are treated as a reduction
of the capitalized cost of the asset to which they apply.
The Company follows the successful-efforts method of accounting for its
exploration and development activities. Under this method, costs of exploration
acreage are capitalized and amortized over the period of exploration or until a
discovery is made. Costs of exploration wells are capitalized until their
success can be determined. If the well is successful, the costs remain
capitalized; otherwise they are expensed. Capitalized exploration costs are
re-evaluated annually. All other exploration costs are expensed as incurred.
Development costs, including the cost of natural
gas and natural gas liquids used as injectants in enhanced (tertiary)
oil-recovery projects, are capitalized.
The Company selected the successful-efforts method over the alternative
full-cost method of accounting because it provides a more timely accounting of
the success or failure of exploration and production activities.
Maintenance and repair costs, including planned major maintenance, are
expensed as incurred. Improvements that increase or prolong the service life or
capacity of an asset are capitalized.
Production costs are expensed as incurred. Production involves lifting the
oil and gas to the surface and gathering, treating, field processing and field
storage of the oil and gas. The production function normally terminates at the
outlet valve on the lease or field production storage tank. Production costs
are those incurred to operate and maintain the Companys wells and related
equipment and facilities. They become part of the cost of oil and gas produced.
Depreciation and depletion for assets associated with producing properties
begins at the time when production commences on a regular basis. Depreciation
for other assets begin when the asset is in place and ready for its intended
use. Assets under construction are not depreciated or depleted. Depreciation
and depletion are calculated using the unit-of-production method for producing
properties, including capitalized exploratory drilling and development costs.
Depreciation of other plant and equipment is calculated using the straight-line
method, based on the estimated service life of the asset. In general,
refineries are depreciated over 25 years; other major assets, including
chemical plants and service stations, are depreciated over 20 years.
Proved oil and gas properties held and used by the Company are reviewed
for impairment whenever events or changes in circumstances indicate that the
carrying amounts may not be recoverable. Assets are grouped at the lowest level
for which there are identifiable cash flows that are largely independent of the
cash flows of other groups of assets.
The Company estimates the future undiscounted cash flows of the affected
properties to judge the recoverability of carrying amounts. Cash flows used in
impairment evaluations are developed using annually updated corporate plan
investment evaluation assumptions for crude oil commodity prices and
foreign-currency exchange rates. Annual volumes are based on individual field
production profiles, which are also updated annually. Prices for natural gas
and other products sold under contract are based on corporate plan assumptions
developed annually by major contracts and also for investment evaluation
purposes.
Gains or losses on assets sold are included in investment and other income
in the consolidated statement of earnings.
Goodwill and other intangible assets
Goodwill and intangible assets with indefinite lives are not subject to
amortization. These assets are tested for impairment annually or more
frequently if events or circumstances indicate the assets might be impaired.
Impairment losses are recognized in current period earnings. The evaluation for
impairment of goodwill is based on a comparison of the carrying values of
goodwill and associated operating assets with the estimated present value of
net cash flows from those operating assets.
Intangible assets with determinable useful lives are amortized over the
estimated service lives of the assets. Computer software development costs are
amortized over a maximum of 15 years and customer lists are amortized over a
maximum of 10 years. The amortization is included in depreciation and
depletion in the consolidated statement of earnings.
Asset retirement obligations and other environmental liabilities
Legal obligations associated with site restoration on the retirement of
assets with determinable useful lives are recognized when they are incurred,
which is typically at the time the assets are installed. The obligations are
initially measured at fair value and discounted to present value. A
corresponding amount equal to that of the initial obligation is added to the
capitalized costs of the related asset. Over time the discounted asset
retirement obligation amount will be accreted for the change in its present
value, and the initial capitalized costs will be depreciated over the useful
lives of the related assets.
No asset retirement obligations are set up for assets with an
indeterminate useful life. Provision for environmental liabilities of these and
non-operating assets is made when it is probable that obligations have been
incurred and the amount can be reasonably estimated. The fair values of asset
retirement obligations and other provisions for environmental liabilities are
determined based on engineering estimated costs, taking into account the
anticipated method and extent of remediation consistent with legal
requirements, current technology and the possible use of the location.
Foreign-currency translation
Monetary assets and liabilities in foreign currencies have been translated
at the rates of exchange prevailing on December 31. Any exchange gains or
losses are recognized in earnings.
F-7
Financial instruments
Financial instruments are initially recorded at historical cost. If
subsequent circumstances indicate that a decline in the fair value of a
financial asset is other than temporary, the financial asset is written down to
its fair value. Unless otherwise indicated, the fair values of financial
instruments approximate their recorded amounts.
The fair values of cash, marketable securities, accounts receivable and
current liabilities approximate recorded amounts because of the short period to
receipt or payment of cash. The fair value of the Companys long-term debt is
estimated based on quoted market prices for the same or similar issues or on
the current rates offered to the Company for debt of the same duration to
maturity. The fair values of other financial instruments held by the Company
are estimated primarily by discounting future cash flows, using current rates
for similar financial instruments under similar credit risk and maturity
conditions.
The Company does not use financing structures for the purpose of altering
accounting outcomes or removing debt from the balance sheet. The Company makes
limited use of derivatives. Derivative instruments are not held for trading
purposes.
Revenues
Revenues associated with sales of crude oil, natural gas, petroleum and
chemical products and other items are recorded when the products are delivered.
Delivery occurs when the customer has taken title and has assumed the risks and
rewards of ownership, prices are fixed or determinable and collectability is
reasonably assured. The Company does not enter into ongoing arrangements
whereby it is required to repurchase its products, nor does the Company provide
the customer with a right of return.
Revenues include amounts billed to customers for shipping and handling.
Shipping and handling costs incurred up to the point of final storage prior to
delivery to a customer are included in purchases of crude oil and products in
the consolidated statement of earnings. Delivery costs from final storage to
customers are recorded as a marketing expense in selling and general expenses.
Stock-based compensation
The Company accounts for its stock-based compensation programs, except for
the incentive stock options granted in April 2002, by using the
fair-value-based method. Under this method, compensation expense related to the
units of these programs is measured by the fair value of the unit and is
recorded in the consolidated statement of earnings over the vesting period.
As permitted by the new Canadian Institute of Chartered Accountants (CICA)
standard on accounting for stock-based compensation, the Company continues to
apply the intrinsic-value-based method of accounting for the incentive stock
options granted in April 2002. Under this method, compensation expense is not
recognized on the issuance of stock options as long as the exercise price is
equal to the market value at the date of grant.
Consumer taxes
Taxes levied on the consumer and collected by the Company are excluded
from the consolidated statement of earnings. These are primarily provincial
taxes on motor fuels and the federal goods and services tax.
Interest costs
Interest costs are expensed as incurred and included in financing costs in
the consolidated statement of earnings.
Accounting principles
The consolidated financial statements have been prepared in accordance
with generally accepted accounting principles (GAAP) in Canada. Form 10-K,
filed with the United States Securities and Exchange Commission, includes a
description of the differences between GAAP in Canada and in the United States
as they apply to the Company.
Effective January 1, 2003, the Company has adopted the new CICA standards
on accounting for asset retirement obligations. The impact of adopting this new
standard is described in note 2 to the consolidated financial statements on
page F-10. The Company has early adopted the additional disclosure requirements
by the CICA on employee future benefits, as shown in note 5 on page F-12. The
Company has also early adopted the new CICA standard on stock-based
compensation with no impact on its accounting or reporting.
F-8
Notes to consolidated financial statements
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural resources (a) |
|
Petroleum products |
|
Chemicals |
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
|
2003
|
|
2002
|
|
2001
|
|
2003
|
|
2002
|
|
2001
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External sales (c) |
|
|
3,390 |
|
|
|
2,573 |
|
|
|
3,144 |
|
|
|
14,710 |
|
|
|
13,362 |
|
|
|
13,079 |
|
|
|
994 |
|
|
|
955 |
|
|
|
930 |
|
Intersegment sales |
|
|
2,224 |
|
|
|
2,217 |
|
|
|
2,166 |
|
|
|
1,294 |
|
|
|
1,038 |
|
|
|
1,300 |
|
|
|
238 |
|
|
|
209 |
|
|
|
245 |
|
Investment and other income |
|
|
34 |
|
|
|
104 |
|
|
|
11 |
|
|
|
54 |
|
|
|
34 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
5,648 |
|
|
|
4,894 |
|
|
|
5,321 |
|
|
|
16,058 |
|
|
|
14,434 |
|
|
|
14,405 |
|
|
|
1,232 |
|
|
|
1,164 |
|
|
|
1,175 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
55 |
|
|
|
30 |
|
|
|
45 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of crude oil and products |
|
|
2,357 |
|
|
|
1,814 |
|
|
|
2,444 |
|
|
|
12,066 |
|
|
|
10,974 |
|
|
|
10,505 |
|
|
|
911 |
|
|
|
830 |
|
|
|
895 |
|
Operating |
|
|
1,093 |
|
|
|
990 |
|
|
|
952 |
|
|
|
810 |
|
|
|
761 |
|
|
|
755 |
|
|
|
124 |
|
|
|
115 |
|
|
|
124 |
|
Selling and general (d) |
|
|
28 |
|
|
|
21 |
|
|
|
30 |
|
|
|
1,123 |
|
|
|
1,076 |
|
|
|
1,134 |
|
|
|
118 |
|
|
|
115 |
|
|
|
97 |
|
Federal excise tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,254 |
|
|
|
1,231 |
|
|
|
1,180 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and depletion (e) (f) |
|
|
517 |
|
|
|
479 |
|
|
|
457 |
|
|
|
211 |
|
|
|
203 |
|
|
|
238 |
|
|
|
22 |
|
|
|
23 |
|
|
|
23 |
|
Financing costs (note 12) |
|
|
1 |
|
|
|
1 |
|
|
|
2 |
|
|
|
2 |
|
|
|
1 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
4,051 |
|
|
|
3,335 |
|
|
|
3,930 |
|
|
|
15,466 |
|
|
|
14,246 |
|
|
|
13,814 |
|
|
|
1,175 |
|
|
|
1,083 |
|
|
|
1,139 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings before income taxes |
|
|
1,597 |
|
|
|
1,559 |
|
|
|
1,391 |
|
|
|
592 |
|
|
|
188 |
|
|
|
591 |
|
|
|
57 |
|
|
|
81 |
|
|
|
36 |
|
Income taxes (note 4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
535 |
|
|
|
517 |
|
|
|
556 |
|
|
|
66 |
|
|
|
172 |
|
|
|
125 |
|
|
|
13 |
|
|
|
40 |
|
|
|
11 |
|
Future |
|
|
(77 |
) |
|
|
(14 |
) |
|
|
(122 |
) |
|
|
119 |
|
|
|
(111 |
) |
|
|
113 |
|
|
|
7 |
|
|
|
(11 |
) |
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
458 |
|
|
|
503 |
|
|
|
434 |
|
|
|
185 |
|
|
|
61 |
|
|
|
238 |
|
|
|
20 |
|
|
|
29 |
|
|
|
13 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
1,139 |
|
|
|
1,056 |
|
|
|
957 |
|
|
|
407 |
|
|
|
127 |
|
|
|
353 |
|
|
|
37 |
|
|
|
52 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from earnings |
|
|
1,576 |
|
|
|
1,526 |
|
|
|
1,287 |
|
|
|
719 |
|
|
|
216 |
|
|
|
700 |
|
|
|
66 |
|
|
|
63 |
|
|
|
49 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital and exploration expenditures (g) |
|
|
1,007 |
|
|
|
986 |
|
|
|
746 |
|
|
|
478 |
|
|
|
589 |
|
|
|
339 |
|
|
|
41 |
|
|
|
25 |
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost |
|
|
12,610 |
|
|
|
11,672 |
|
|
|
10,785 |
|
|
|
6,069 |
|
|
|
5,827 |
|
|
|
5,462 |
|
|
|
609 |
|
|
|
579 |
|
|
|
554 |
|
Accumulated depreciation and depletion |
|
|
6,813 |
|
|
|
6,303 |
|
|
|
5,871 |
|
|
|
2,856 |
|
|
|
2,867 |
|
|
|
2,842 |
|
|
|
401 |
|
|
|
383 |
|
|
|
366 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment (h) |
|
|
5,797 |
|
|
|
5,369 |
|
|
|
4,914 |
|
|
|
3,213 |
|
|
|
2,960 |
|
|
|
2,620 |
|
|
|
208 |
|
|
|
196 |
|
|
|
188 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (f) |
|
|
6,434 |
|
|
|
6,014 |
|
|
|
5,385 |
|
|
|
5,341 |
|
|
|
5,048 |
|
|
|
4,348 |
|
|
|
446 |
|
|
|
418 |
|
|
|
373 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital employed |
|
|
3,784 |
|
|
|
3,325 |
|
|
|
2,580 |
|
|
|
2,784 |
|
|
|
2,484 |
|
|
|
2,148 |
|
|
|
246 |
|
|
|
178 |
|
|
|
195 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and other |
|
Consolidated (b) |
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
|
2003
|
|
2002
|
|
2001
|
Revenues |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External sales (c) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,094 |
|
|
|
16,890 |
|
|
|
17,153 |
|
Intersegment sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment and other income |
|
|
26 |
|
|
|
14 |
|
|
|
63 |
|
|
|
114 |
|
|
|
152 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total revenues |
|
|
26 |
|
|
|
14 |
|
|
|
63 |
|
|
|
19,208 |
|
|
|
17,042 |
|
|
|
17,253 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
55 |
|
|
|
30 |
|
|
|
45 |
|
Purchases of crude oil and products |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
11,580 |
|
|
|
10,155 |
|
|
|
10,134 |
|
Operating |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2,025 |
|
|
|
1,865 |
|
|
|
1,830 |
|
Selling and general (d) |
|
|
|
|
|
|
10 |
|
|
|
19 |
|
|
|
1,269 |
|
|
|
1,222 |
|
|
|
1,280 |
|
Federal excise tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,254 |
|
|
|
1,231 |
|
|
|
1,180 |
|
Depreciation and depletion (e) (f) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
750 |
|
|
|
705 |
|
|
|
718 |
|
Financing costs (note 12) |
|
|
(90 |
) |
|
|
30 |
|
|
|
148 |
|
|
|
(87 |
) |
|
|
32 |
|
|
|
152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
(90 |
) |
|
|
40 |
|
|
|
167 |
|
|
|
16,846 |
|
|
|
15,240 |
|
|
|
15,339 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings before income taxes |
|
|
116 |
|
|
|
(26 |
) |
|
|
(104 |
) |
|
|
2,362 |
|
|
|
1,802 |
|
|
|
1,914 |
|
Income taxes (note 4) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(4 |
) |
|
|
(11 |
) |
|
|
(13 |
) |
|
|
610 |
|
|
|
718 |
|
|
|
679 |
|
Future |
|
|
21 |
|
|
|
(4 |
) |
|
|
(13 |
) |
|
|
70 |
|
|
|
(140 |
) |
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense |
|
|
17 |
|
|
|
(15 |
) |
|
|
(26 |
) |
|
|
680 |
|
|
|
578 |
|
|
|
659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
99 |
|
|
|
(11 |
) |
|
|
(78 |
) |
|
|
1,682 |
|
|
|
1,224 |
|
|
|
1,255 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash flow from earnings |
|
|
(7 |
) |
|
|
(24 |
) |
|
|
(20 |
) |
|
|
2,354 |
|
|
|
1,781 |
|
|
|
2,016 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Capital and exploration expenditures (g) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,526 |
|
|
|
1,600 |
|
|
|
1,115 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Property, plant and equipment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
19,288 |
|
|
|
18,078 |
|
|
|
16,801 |
|
Accumulated depreciation and depletion |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,070 |
|
|
|
9,553 |
|
|
|
9,079 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net property, plant and equipment (h) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
9,218 |
|
|
|
8,525 |
|
|
|
7,722 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total assets (f) |
|
|
448 |
|
|
|
766 |
|
|
|
873 |
|
|
|
12,361 |
|
|
|
11,894 |
|
|
|
10,781 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total capital employed |
|
|
448 |
|
|
|
816 |
|
|
|
918 |
|
|
|
7,262 |
|
|
|
6,803 |
|
|
|
5,841 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Continued on following page)
F-9
(a) |
|
A significant portion of activities in the natural resources segment
is conducted jointly with other companies. The segment includes the
Companys proportionate share of joint-venture activities, as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
Total revenues |
|
|
2,494 |
|
|
|
2,357 |
|
|
|
2,689 |
|
Total expenses |
|
|
1,577 |
|
|
|
1,520 |
|
|
|
1,733 |
|
Net earnings, after income taxes |
|
|
664 |
|
|
|
557 |
|
|
|
637 |
|
Total current assets |
|
|
302 |
|
|
|
321 |
|
|
|
232 |
|
Long-term assets |
|
|
3,553 |
|
|
|
3,038 |
|
|
|
2,750 |
|
Total current liabilities |
|
|
913 |
|
|
|
669 |
|
|
|
919 |
|
Other long-term obligations |
|
|
302 |
|
|
|
268 |
|
|
|
262 |
|
Cash flow from earnings |
|
|
868 |
|
|
|
767 |
|
|
|
828 |
|
Cash flow from operating activities |
|
|
883 |
|
|
|
615 |
|
|
|
850 |
|
Cash from (used in) investing activities |
|
|
(754 |
) |
|
|
(601 |
) |
|
|
(301 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
(b) |
|
Information is presented as though each segment were a separate business activity. Intersegment sales are made essentially at prevailing market prices.
Consolidated amounts exclude intersegment transactions, as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
Purchases of crude oil and products |
|
|
3,754 |
|
|
|
3,463 |
|
|
|
3,710 |
|
Operating expense |
|
|
2 |
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total intersegment sales |
|
|
3,756 |
|
|
|
3,464 |
|
|
|
3,711 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Intersegment receivables and payables |
|
|
308 |
|
|
|
352 |
|
|
|
198 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(c) |
|
Includes export sales to the United States, as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
Natural resources |
|
|
1,304 |
|
|
|
942 |
|
|
|
1,018 |
|
Petroleum products |
|
|
792 |
|
|
|
723 |
|
|
|
770 |
|
Chemicals |
|
|
567 |
|
|
|
520 |
|
|
|
503 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total export sales |
|
|
2,663 |
|
|
|
2,185 |
|
|
|
2,291 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(d) |
|
Consolidated selling and general expenses include delivery
costs from final storage to customers of $285 million (2002
$216 million; 2001 $244 million). |
|
(e) |
|
Goodwill was not amortized in 2003 and 2002 (amortization
expense in 2001 $28 million). All goodwill has been assigned to the petroleum products segment. There
have been no goodwill acquisitions, impairment losses or write-offs due to sales in the past three years. |
|
(f) |
|
Total assets include amortized intangible assets, consisting primarily of acquired customer lists and capitalized computer-software development costs, as follows: |
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
Cost |
|
|
87 |
|
|
|
81 |
|
Accumulated amortization |
|
|
35 |
|
|
|
30 |
|
|
|
|
|
|
|
|
|
|
Net intangible assets |
|
|
52 |
|
|
|
51 |
|
|
|
|
|
|
|
|
|
|
|
|
Customer lists acquired in 2003 were $1 million (2002
$5 million), those
disposed of or retired were $1 million (2002 $1 million) and no gain or loss
was recognized. Capitalized computer-software development costs in 2003 were $6
million (2002 $20 million). The estimated annual amortization expense for
intangible assets in each of the next five years is $8 million. |
|
(g) |
|
Capital and exploration expenditures of the petroleum products segment
include non-cash capital leases of $22 million in 2003 (2002
$18 million). |
|
(h) |
|
Includes property, plant and equipment under construction of $1,426
million (2002 $1,275 million). |
Effective January 1, 2003, the Company implemented reporting changes to
reflect the new accounting standard of the Canadian Institute of Chartered
Accountants (CICA) dealing with accounting for asset retirement obligations.
The new CICA standard changes the method of accruing for certain
site-restoration costs. Under the new standard, the fair values of asset
retirement obligations are recorded as liabilities on a discounted basis when
they are incurred, which is typically at the time the related assets are
installed. Amounts recorded for the related assets are increased by the amount
of these obligations. Over time the liabilities will be accreted for the
change in their present value, and the initial capitalized costs will be
depreciated over the useful lives of the related assets. There are no asset
retirement liabilities set up for those assets that have an indeterminate
useful life.
Estimated cash flows have been discounted at six percent. Implementation
of the new standard has reduced environmental liabilities by $28 million to
$462 million as of December 31, 2003. The total undiscounted amount of the
estimated cash flows required to settle the obligations is $895 million.
Payments to settle the obligations occur on an ongoing basis and will continue
over the lives of the operating assets, which can exceed 25 years. This change
in accounting standard has no impact on the cash flow profile of the Company.
The new standard has been applied retroactively, and the financial statements
of prior periods have been restated.
(Continued on following page)
F-10
The impact of adopting the new standard of accounting for asset retirement
obligations on the consolidated balance sheet and statement of earnings is:
Changes in consolidated balance sheet
|
|
|
|
|
|
|
|
|
millions of dollars increase/(decrease)
|
|
2003
|
|
2002
|
Property, plant and equipment |
|
|
24 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
Total assets |
|
|
24 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
Other long-term obligations |
|
|
(28 |
) |
|
|
20 |
|
Future income tax liabilities |
|
|
18 |
|
|
|
2 |
|
Retained earnings |
|
|
34 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders equity |
|
|
24 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
Changes in consolidated statement of earnings
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars increase/(decrease)
|
|
2003
|
|
2002
|
|
2001
|
Operating expense |
|
|
(48 |
) |
|
|
(23 |
) |
|
|
(25 |
) |
Depreciation and depletion expense |
|
|
2 |
|
|
|
2 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
(46 |
) |
|
|
(21 |
) |
|
|
(23 |
) |
Income taxes |
|
|
16 |
|
|
|
7 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net earnings |
|
|
30 |
|
|
|
14 |
|
|
|
16 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share basic and diluted (dollars) |
|
|
0.08 |
|
|
|
0.04 |
|
|
|
0.04 |
|
The change in asset retirement obligations liability is as follows:
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
Asset retirement obligations liability at January 1 |
|
|
341 |
|
|
|
334 |
|
Additions |
|
|
|
|
|
|
8 |
|
Accretion |
|
|
20 |
|
|
|
20 |
|
Settlements |
|
|
(34 |
) |
|
|
(21 |
|
|
|
|
|
|
|
|
|
|
Asset retirement obligations liability at December 31 |
|
|
327 |
|
|
|
341 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
issued
|
|
maturity date
|
|
interest rate
|
|
millions of dollars
|
1989 |
|
September 1, 2004 (2002 $600 million (U.S.))(a) |
|
Variable |
|
|
|
|
|
|
946 |
|
2002 |
|
May 7, 2004 (b) |
|
Variable |
|
|
|
|
|
|
500 |
|
2003 |
|
$250 million due May 26, 2005 and |
|
|
|
|
|
|
|
|
|
|
|
|
$250 million due August 26, 2005(a) |
|
Variable |
|
|
500 |
|
|
|
|
|
2003 |
|
January 19, 2006(a) |
|
Variable |
|
|
318 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Long-term debt (at period-end exchange rates)(c) |
|
|
|
|
818 |
|
|
|
1,446 |
|
Capital leases(d) |
|
|
|
|
41 |
|
|
|
20 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total long-term debt(e) |
|
|
|
|
859 |
|
|
|
1,466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
During the first half of 2003, the company redeemed the $600-million (U.S.)
variable-rate debt for $818 million (Cdn) and replaced it with long-term
variable-rate loans of $818 million (Cdn) from Exxon Overseas Corporation at
interest equivalent to Canadian market rates. The average effective interest
rate for the loans was 3.1 percent for 2003. |
|
(b) |
|
Principal payments on medium-term notes of $500 million, which have been
reclassified to current portion of long-term debt in the balance sheet, are due
in 2004. |
|
|
|
These notes are extendable up to May 7, 2007, at note holders discretion. |
|
(c) |
|
The estimated fair value of the long-term debt at December 31, 2003, was
$818 million (2002 $1,446 million). |
|
(d) |
|
These obligations primarily relate to the capital lease for marine
services, which are to be provided by the lessor commencing in 2004 for a
period of 10 years, extendable for an additional five years. The obligations
recorded to date represent the costs incurred by the lessor for the
construction of the related marine assets. |
|
(e) |
|
Principal payments on long-term loans of $500 million are due in 2005 and
$318 million are due in 2006. Principal payments on capital leases of
approximately $4 million a year are due in each of the next five years. |
F-11
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
Current income tax expense |
|
|
610 |
|
|
|
718 |
|
|
|
679 |
|
Future income tax expense (a) |
|
|
70 |
|
|
|
(140 |
) |
|
|
(20 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Total income tax expense (b) |
|
|
680 |
|
|
|
578 |
|
|
|
659 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Statutory corporate tax rate (percent) |
|
|
38.5 |
|
|
|
42.0 |
|
|
|
42.7 |
|
Increase/(decrease) resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
Non-deductible royalty payments to governments |
|
|
5.0 |
|
|
|
5.4 |
|
|
|
7.9 |
|
Resource allowance in lieu of royalty deduction |
|
|
(7.5 |
) |
|
|
(11.8 |
) |
|
|
(11.4 |
) |
Manufacturing and processing credit |
|
|
0.2 |
|
|
|
(0.3 |
) |
|
|
(1.3 |
) |
Non-deductible depreciation and amortization |
|
|
|
|
|
|
|
|
|
|
0.6 |
|
Enacted tax rate change |
|
|
(3.1 |
) |
|
|
(0.9 |
) |
|
|
(2.1 |
) |
Other |
|
|
(4.3 |
) |
|
|
(2.3 |
) |
|
|
(2.0 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Effective income tax rate |
|
|
28.8 |
|
|
|
32.1 |
|
|
|
34.4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Future income taxes are based on differences between the accounting and
tax values of assets and liabilities. These differences in value are remeasured
at each period-end using the tax rates and tax laws expected to apply when
those differences are realized or settled in the future. Components of future
income tax liabilities and assets as at December 31 were:
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
Depreciation and amortization |
|
|
1,233 |
|
|
|
1,098 |
|
Successful drilling and land acquisitions |
|
|
495 |
|
|
|
660 |
|
Pension and benefits |
|
|
(137 |
) |
|
|
(229 |
) |
Site restoration |
|
|
(167 |
) |
|
|
(186 |
) |
Net tax loss carryforwards (c) |
|
|
(57 |
) |
|
|
(37 |
) |
Other |
|
|
(5 |
) |
|
|
(44 |
) |
|
|
|
|
|
|
|
|
|
Total future income tax liabilities |
|
|
1,362 |
|
|
|
1,262 |
|
|
|
|
|
|
|
|
|
|
LIFO inventory valuation |
|
|
(268 |
) |
|
|
(271 |
) |
Other |
|
|
(85 |
) |
|
|
(52 |
) |
|
|
|
|
|
|
|
|
|
Total future income tax assets |
|
|
(353 |
) |
|
|
(323 |
) |
|
|
|
|
|
|
|
|
|
Net future income tax liabilities |
|
|
1,009 |
|
|
|
939 |
|
|
|
|
|
|
|
|
|
|
(a) |
|
The future income tax expense for the year is the difference in net future
income tax liabilities at the beginning and end of the year. |
|
(b) |
|
Net cash outflow from income taxes, plus investment credits earned, were
$573 million in 2003 (2002 $935 million; 2001 $1,086 million). |
|
(c) |
|
Tax
losses can be carried forward indefinitely. |
The operations of the Company are complex, and related tax
interpretations, regulations and legislation are continually changing. As a
result, there are usually some tax matters in question. The Company believes
the provision made for income taxes is adequate.
5. |
|
Employee retirement benefits |
Retirement benefits, which cover almost all retired employees and their
surviving spouses, include pension-income and certain health-care and
life-insurance benefits. They are met through funded registered
retirement plans and through unfunded supplementary benefits that are
paid directly to recipients. Funding of registered retirement plans
complies with federal and provincial pension regulations, and the Company
makes contributions to the plans based upon an independent actuarial
valuation.
Pension-income benefits consist mainly of company-paid defined benefit plans
that are based on years of service and final average earnings. The
Company shares in the cost of health-care and life-insurance benefits.
The Companys benefit obligations are based on the projected benefit
method of valuation which includes employee service to date and present
compensation levels as well as a projection of salaries and service to
retirement.
The expense and obligations for both funded and unfunded benefits are
determined in accordance with generally accepted Canadian accounting
principles and actuarial procedures. The process for determining
retirement-income expense and related obligations includes making certain
long-term assumptions regarding the discount rate, rate of return on plan
assets and rate of compensation increases.
The total obligation for employee retirement benefits exceeded the fair
value of plan assets at December 31, 2003, by
$1,357 million (2002
$1,780 million), 975 million (2002 $1,426 million) of which was related
to pension benefits and $382 million (2002 354 million) was related to
other post-retirement benefits. The obligation and pension expense can
vary significantly with changes in the assumptions used to estimate the
obligation and the expected return on plan assets.
(Continued on following page)
F-12
Details of the employee retirement benefits plans are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Pension benefits
|
|
Other post-retirement benefits
|
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
|
2003
|
|
2002
|
|
2001
|
Components of net benefit expense |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current service cost |
|
|
71 |
|
|
|
64 |
|
|
|
57 |
|
|
|
5 |
|
|
|
4 |
|
|
|
4 |
|
Interest cost |
|
|
219 |
|
|
|
222 |
|
|
|
215 |
|
|
|
22 |
|
|
|
21 |
|
|
|
21 |
|
Expected return on plan assets |
|
|
(179 |
) |
|
|
(191 |
) |
|
|
(257 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
Amortization of prior service cost |
|
|
25 |
|
|
|
25 |
|
|
|
23 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Recognized actuarial loss/(gain) |
|
|
69 |
|
|
|
34 |
|
|
|
|
|
|
|
3 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net benefit expense(a)(e) |
|
|
205 |
|
|
|
154 |
|
|
|
38 |
|
|
|
30 |
|
|
|
26 |
|
|
|
25 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in benefit obligation |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at January 1 |
|
|
3,530 |
|
|
|
3,248 |
|
|
|
|
|
|
|
354 |
|
|
|
323 |
|
|
|
|
|
Current service cost |
|
|
71 |
|
|
|
64 |
|
|
|
|
|
|
|
5 |
|
|
|
4 |
|
|
|
|
|
Interest cost |
|
|
219 |
|
|
|
222 |
|
|
|
|
|
|
|
22 |
|
|
|
21 |
|
|
|
|
|
Amendments |
|
|
|
|
|
|
27 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actuarial loss/(gain) |
|
|
171 |
|
|
|
196 |
|
|
|
|
|
|
|
19 |
|
|
|
25 |
|
|
|
|
|
Benefits paid |
|
|
(230 |
) |
|
|
(227 |
) |
|
|
|
|
|
|
(18 |
) |
|
|
(19 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at December 31(b)(e) |
|
|
3,761 |
|
|
|
3,530 |
|
|
|
|
|
|
|
382 |
|
|
|
354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Change in plan assets |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at January 1 |
|
|
2,104 |
|
|
|
2,390 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Actual return on plan assets |
|
|
377 |
|
|
|
(107 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company contributions (b) |
|
|
511 |
|
|
|
19 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Payments directly to participants |
|
|
24 |
|
|
|
29 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefits paid |
|
|
(230 |
) |
|
|
(227 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair value of plan assets at December 31(b) |
|
|
2,786 |
|
|
|
2,104 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Excess/(deficiency) of plan assets
over benefit obligation |
|
|
(975 |
) |
|
|
(1,426 |
) |
|
|
|
|
|
|
(382 |
) |
|
|
(354 |
) |
|
|
|
|
Unrecognized net actuarial (gain)/loss (c) |
|
|
829 |
|
|
|
924 |
|
|
|
|
|
|
|
52 |
|
|
|
36 |
|
|
|
|
|
Unrecognized prior service cost (c) |
|
|
89 |
|
|
|
114 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total net liability |
|
|
(57 |
) |
|
|
(388 |
) |
|
|
|
|
|
|
(330 |
) |
|
|
(318 |
) |
|
|
|
|
Less: Prepaid benefit cost (d) |
|
|
162 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability recognized (note 6) |
|
|
(219 |
) |
|
|
(388 |
) |
|
|
|
|
|
|
(330 |
) |
|
|
(318 |
) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The benefit obligation at year-end includes
funded and unfunded plans, as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Funded plans |
|
|
3,464 |
|
|
|
3,230 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unfunded plans |
|
|
297 |
|
|
|
300 |
|
|
|
|
|
|
|
382 |
|
|
|
354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Benefit obligation at December 31 |
|
|
3,761 |
|
|
|
3,530 |
|
|
|
|
|
|
|
382 |
|
|
|
354 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions
The discount rate used for year-end employee retirement liabilities
reflects the rate at which employee retirement liabilities could be effectively
settled and is based on the year-end rate of interest on a portfolio of
high-quality bonds.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions used to determine benefit
obligations at December 31 (percent) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
6.25 |
|
|
|
6.25 |
|
|
|
|
|
|
|
6.25 |
|
|
|
6.25 |
|
|
|
|
|
Long-term rate of compensation increase |
|
|
3.50 |
|
|
|
3.50 |
|
|
|
|
|
|
|
3.50 |
|
|
|
3.50 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Assumptions used to determine net benefit
expense for years ended December 31 (percent) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Discount rate |
|
|
6.25 |
|
|
|
6.75 |
|
|
|
7.00 |
|
|
|
6.25 |
|
|
|
6.75 |
|
|
|
7.00 |
|
Long-term rate of compensation increase |
|
|
3.50 |
|
|
|
3.50 |
|
|
|
3.50 |
|
|
|
3.50 |
|
|
|
3.50 |
|
|
|
3.50 |
|
Long-term rate of return on plan assets |
|
|
8.25 |
|
|
|
8.25 |
|
|
|
10.00 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Continued on following page)
F-13
Plan assets
|
|
The Companys pension plan asset allocation at December 31, 2002 and 2003, and
target allocation for 2004 are as follows: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Percentage of |
|
|
Target |
|
plan assets |
|
|
allocation
|
|
at December 31
|
Asset category (percent)
|
|
2004
|
|
2003
|
|
2002
|
Equities |
|
|
50 - 75 |
|
|
|
62 |
|
|
|
60 |
|
Fixed income |
|
|
25 - 50 |
|
|
|
38 |
|
|
|
40 |
|
Other |
|
|
0 - 10 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
|
|
|
|
100 |
|
|
|
100 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
The Company establishes the long-term expected rate of return by
developing a forward-looking long-term return assumption for each asset class,
taking into account factors such as the expected real return for the specific
asset class and inflation. A single, long-term rate of return is then
calculated as the weighted average of the target asset allocation and the
long-term return assumption for each asset class. The 2003 long-term expected
rate of return of 8.25 percent used in the calculations of pension expense
compares to an actual rate of return over the past decade of 9.5 percent.
The Companys investment strategy for benefit plan assets reflects a
long-term view, a careful assessment of the risks inherent in various asset
classes and broad diversification to reduce the risk of the total portfolio.
The Company primarily invests in funds that follow an index-based strategy to
achieve its objectives of diversifying risk while minimizing costs. The fund
holds the Companys common shares only to the extent necessary to replicate the
relevant equity index. Asset-liability studies, or simulations of the
interaction of cash flows associated with both assets and liabilities, are
periodically used to establish the preferred target asset allocation. The
target asset allocation for equity securities reflects the long-term nature of
the liability. The balance of the fund is targeted to debt securities.
(a) |
|
Additional expenses include contributions to defined contribution plans,
primarily the employee savings plan, of $31 million in 2003
(2002 $30
million; 2001 $23 million). |
|
(b) |
|
The most recent independent actuarial
valuation was as at June 30, 2003. The measurement date used to determine the
plan assets and the benefit obligations was December 31, 2003. |
|
(c) |
|
Unrecorded assets/(liabilities) are amortized over the average remaining
service life of employees, which for 2004 and subsequent years is 13 years
(2003 13.5 years; 2002 13.5 years). |
|
(d) |
|
Prepaid benefit costs are included in investments and other
long-term assets on the consolidated balance sheet. |
|
(e) |
|
A one-percent
change in the assumptions at which retirement liabilities could be
effectively settled is as follows: |
|
|
|
|
|
|
|
|
|
|
|
One-percent |
|
One-percent |
millions of dollars
|
|
increase
|
|
decrease
|
Rate of return on plan assets: |
|
|
|
|
|
|
|
|
Effect on net benefits expenses |
|
|
(20 |
) |
|
|
20 |
|
Discount rate: |
|
|
|
|
|
|
|
|
Effect on net benefits expenses |
|
|
(35 |
) |
|
|
40 |
|
Effect on benefits obligations |
|
|
(440 |
) |
|
|
540 |
|
Rate of compensation increases: |
|
|
|
|
|
|
|
|
Effect on net benefits expenses |
|
|
25 |
|
|
|
(25 |
) |
Effect on benefits obligations |
|
|
130 |
|
|
|
(115 |
) |
|
|
For measurement purposes, a five-percent health-care cost trend rate was
assumed for 2003 and thereafter. A one-percent change in the assumed
health-care cost trend rate would have the following effects: |
|
|
|
|
|
|
|
|
|
|
|
One-percent |
|
One-percent |
millions of dollars
|
|
increase
|
|
decrease
|
Effect on service and interest cost components |
|
|
3 |
|
|
|
(2 |
) |
Effect on other post-retirement benefit obligation |
|
|
35 |
|
|
|
(30 |
) |
6. |
|
Other long-term obligations |
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
Employee retirement benefits (note 5)(a) |
|
|
505 |
|
|
|
671 |
|
Asset
retirement obligations and other environmental liabilities (b) |
|
|
393 |
|
|
|
454 |
|
Other obligations |
|
|
74 |
|
|
|
82 |
|
|
|
|
|
|
|
|
|
|
Total other long-term obligations |
|
|
972 |
|
|
|
1,207 |
|
|
|
|
|
|
|
|
|
|
(a) |
|
Total recorded employee retirement benefits obligations also include $44
million in current liabilities (2002 $35 million). |
|
(b) |
|
Total asset retirement obligations and other environmental liabilities
also include $69 million in current liabilities (2002 $71 million). |
7. |
|
Derivative financial instruments |
No significant energy derivatives, foreign-exchange forward contracts or
currency and interest-rate swaps were transacted in the past three years. The
Company maintains a system of controls that includes a policy covering the
authorization, reporting and monitoring of derivative activity.
F-14
8. |
|
Incentive compensation programs |
Incentive compensation programs are designed to retain selected employees,
reward them for high performance and promote individual contribution to
sustained improvement in the Companys future business performance and
shareholder value.
|
|
Incentive share units, deferred share units, earnings bonus units and
restricted stock units |
Incentive share units have value if the market price of the Companys
common shares when the unit is exercised exceeds the market value when the unit
was issued. The issue price of incentive share units is the closing price of
the Companys shares on the Toronto Stock Exchange on the grant date. Up to 50
percent of the units may be exercised after one year from issuance; an
additional 25 percent may be exercised after two years; and the remaining 25
percent may be exercised after three years. Incentive share units are eligible
for exercise up to 10 years from issuance. The units may expire earlier if
employment is terminated other than by retirement, death or disability.
The deferred share unit plan is made available to selected executives and
nonemployee directors. The selected executives can elect to receive all or part
of their performance bonus compensation in units and the nonemployee directors
can elect to receive all or part of their directors fees in units. The number
of units granted to executives is determined by dividing the amount of the
bonus elected to be received as deferred share units by the average of the
closing prices of the Companys shares on the Toronto Stock Exchange for the
five consecutive trading days immediately prior to the date that the bonus
would have been paid. The number of units granted to a nonemployee director is
determined at the end of each calendar quarter by dividing the amount of
directors fees for the calendar quarter that the nonemployee director elected
to receive as deferred share units by the average closing price of the
Companys shares for the five consecutive trading days immediately prior to the
last day of the calendar quarter. Additional units are granted based on the
cash dividend payable on the Companys shares divided by the average closing
price immediately prior to the payment date for that dividend and multiplying
the resulting number by the number of deferred share units held by the
recipient.
Deferred share units cannot be exercised until after termination of
employment with the Company or resignation as a director and must be exercised
no later than December 31 of the year following termination or resignation. On
the exercise date, the cash value to be received for the units is determined
based on the average closing price of the Companys shares for the five
consecutive trading days immediately prior to the date of exercise.
The earnings bonus unit plan is available to selected executives. Each
earnings bonus unit entitles the recipient to receive an amount equal to the
Companys cumulative net earnings per common share as announced each quarter
beginning after the grant. Payout occurs on the fifth anniversary of the grant
or when the maximum settlement value per unit is reached, if earlier. Earnings
bonus units may expire if employment is terminated other than by death or
disability.
Under the restricted stock unit plan, each unit entitles the recipient to
the conditional right to receive from the Company, upon exercise, an amount
equal to the closing price of the Companys common shares on the Toronto Stock
Exchange on the exercise dates. Fifty percent of the units are exercised three
years following the grant date, and the remainder are exercised seven years
following the grant date.
All units require settlement by cash payments with one exception. The
restricted stock unit plan was amended for units granted in 2003 and future
years by providing that the recipient may receive one common share of the
Company per unit or elect to receive the cash payment for the units to be
exercised on the seventh anniversary of the grant date.
For deferred share units, a charge is made to expense in the year of grant
equal to the cash performance bonus payment and directors fees foregone. The
Company records expense for incentive share, deferred share and restricted
stock units based on changes in the price of common shares in the year. Expense
for earnings bonus units is recorded based on the cumulative net earnings per
outstanding common share from issue date, up to the maximum settlement value
for the units.
In April 2002, incentive stock options were granted for the purchase of
the Companys common shares at an exercise price of $46.50 per share. Up to 50
percent of the options may be exercised on or after January 1, 2003, a further
25 percent may be exercised on or after January 1, 2004, and the remaining 25
percent may be exercised on or after January 1, 2005. Any unexercised options
expire after April 29, 2012. The Company did not issue incentive stock options
in 2003 and has no plans to issue incentive stock options in the future.
The Company does not recognize compensation expense on the issuance of
stock options because the exercise price is equal to the market value at the
date of grant. If the fair-value-based method of accounting had been adopted,
net income and earnings per share (on both a basic and diluted basis) for 2003
would have been reduced by $5 million or $0.01 per share (2002
$16 million or
$0.04 per share). The average fair value of each option granted during 2002 was
$12.70. The fair value was estimated at the grant date using an option-pricing
model with the following weighted average assumptions: risk-free interest rate
of 5.7 percent, expected life of five years, volatility of 25 percent and a
dividend yield of 1.9 percent.
The Company has purchased shares on the market to fully offset the
dilutive effects from the exercise of stock options. The practice is expected
to continue.
(Continued on following page)
F-15
A summary of the incentive compensation is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Granted in period |
|
Number |
|
|
|
|
|
Obligations |
|
|
|
|
of units |
|
Expensed |
|
outstanding at |
|
|
Number |
|
To number |
|
To number of |
|
outstanding at |
|
in period |
|
December 31 |
|
|
of units
|
|
of employees
|
|
nonemployees
|
|
December 31
|
|
(millions of dollars)
|
|
(millions of dollars)
|
Incentive share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
6,889,330 |
|
|
|
109 |
|
|
|
216 |
|
2002 |
|
|
7,000 |
|
|
|
3 |
|
|
|
|
|
|
|
8,012,250 |
|
|
|
39 |
|
|
|
142 |
|
2001 |
|
|
2,752,700 |
|
|
|
744 |
|
|
|
|
|
|
|
8,823,125 |
|
|
|
51 |
|
|
|
129 |
|
Deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
8,253 |
|
|
|
5 |
|
|
|
6 |
|
|
|
43,911 |
|
|
|
1 |
|
|
|
3 |
|
2002 |
|
|
7,479 |
|
|
|
6 |
|
|
|
7 |
|
|
|
85,523 |
|
|
|
|
|
|
|
4 |
|
2001 |
|
|
15,222 |
|
|
|
2 |
|
|
|
5 |
|
|
|
87,897 |
|
|
|
1 |
|
|
|
4 |
|
Earnings bonus units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
2,221,580 |
|
|
|
84 |
|
|
|
|
|
|
|
3,234,250 |
|
|
|
3 |
|
|
|
3 |
|
2002 |
|
|
1,036,500 |
|
|
|
75 |
|
|
|
|
|
|
|
2,169,040 |
|
|
|
3 |
|
|
|
3 |
|
2001 |
|
|
1,132,540 |
|
|
|
21 |
|
|
|
|
|
|
|
1,132,540 |
|
|
|
|
|
|
|
|
|
Incentive stock options |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,136,150 |
|
|
|
|
|
|
|
|
|
2002 |
|
|
3,210,200 |
|
|
|
765 |
|
|
|
|
|
|
|
3,196,700 |
|
|
|
|
|
|
|
|
|
Restricted stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003 |
|
|
872,085 |
|
|
|
613 |
|
|
|
5 |
|
|
|
1,660,555 |
|
|
|
11 |
|
|
|
11 |
|
2002 |
|
|
791,890 |
|
|
|
690 |
|
|
|
5 |
|
|
|
791,890 |
|
|
|
|
|
|
|
|
|
9. |
|
Commitments and contingent liabilities |
At December 31, 2003, the Company had commitments for noncancellable
operating leases and other long-term agreements that require the
following minimum future payments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2004
|
|
2005
|
|
2006
|
|
2007
|
|
2008
|
|
After 2008
|
Operating leases (a) |
|
|
72 |
|
|
|
59 |
|
|
|
49 |
|
|
|
43 |
|
|
|
34 |
|
|
|
114 |
|
Unconditional purchase obligations (b) |
|
|
90 |
|
|
|
47 |
|
|
|
38 |
|
|
|
38 |
|
|
|
38 |
|
|
|
98 |
|
Firm capital commitments (c) |
|
|
176 |
|
|
|
8 |
|
|
|
5 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term agreements (d) |
|
|
260 |
|
|
|
235 |
|
|
|
151 |
|
|
|
57 |
|
|
|
57 |
|
|
|
277 |
|
(a) |
|
Total rental expense incurred for operating leases in 2003 was $124 million
(2002 $124 million; 2001 $122 million). Operating lease commitments related
to joint-venture activities are not material. |
(b) |
|
Unconditional purchase obligations are those long-term commitments that are
noncancellable or cancellable only under certain conditions. These mainly
pertain to pipeline throughput agreements. Total payments under unconditional
purchase obligations were $114 million in 2003 (2002 $115 million; 2001
$179 million). |
|
(c) |
|
Firm capital commitments related to capital projects, shown
on an undiscounted basis, totalled approximately $189 million at the end of
2003 (2002 $284 million). The largest commitments outstanding at year-end
2003 were associated with the Companys share of capital projects at Syncrude
of $56 million and offshore East Coast of $50 million. |
(d) |
|
Other long-term agreements include primarily raw material supply and
transportation services agreements. Total payments under other long-term
agreements were $332 million in 2003 (2002 $288 million; 2001 $264
million). Payments under other long-term agreements related to joint-venture
activities are approximately $44 million per year. |
|
|
Other commitments arising in the normal course of business for operating
and capital needs do not materially affect the Companys consolidated financial
position. |
|
|
|
The Company was contingently liable at December 31, 2003, for a maximum of
$163 million relating to guarantees for purchasing operating equipment and
other assets from its rural marketing agents upon expiry of the agency
agreement or the death or resignation of the agent. The Company expects that
the fair value of the operating equipment and other assets so purchased would
cover the maximum potential amount of future payment under the guarantees. |
|
|
|
The Company provides in its financial statements for asset retirement
obligations and other environmental liabilities (see accounting policies on
page F-6). Provision is not made with respect to those manufacturing,
distribution and marketing facilities with indeterminate useful lives for which
estimates of these future costs cannot be reasonably determined. These are
primarily currently operated sites. These costs are not expected to have a
material effect on the Companys current consolidated financial position. |
|
|
|
Various lawsuits are pending against the Company and its subsidiaries. The
actual liability with respect to these lawsuits is not determinable, but
management believes, based on the opinion of counsel, that any liability will
not materially affect the Companys consolidated financial position. |
F-16
|
|
The number of authorized common shares of the Company as at December 31,
2003 was 450,000,000, unchanged from December 31, 2002 and December 31,
2001. |
|
|
|
From 1995 to 2002, the Company purchased shares under eight 12-month
normal course share purchase programs, as well as an auction tender. On
June 23, 2003, another 12-month normal course share purchase program was
implemented with an allowable purchase of 18.6 million shares (five
percent of the total at June 19, 2003), less any shares purchased by the
employee savings plan and Company pension fund. The results of these
activities are shown below. |
|
|
|
|
|
|
|
|
|
|
|
Purchased |
|
Millions of |
Year
|
|
shares
|
|
dollars
|
1995 to 2001 |
|
|
202,365,149 |
|
|
|
5,156 |
|
2002 |
|
|
296,052 |
|
|
|
13 |
|
2003 |
|
|
16,259,538 |
|
|
|
799 |
|
|
|
|
|
|
|
|
|
|
Cumulative purchases to date |
|
|
218,920,739 |
|
|
|
5,968 |
|
|
|
|
|
|
|
|
|
|
|
|
Exxon Mobil Corporations participation in the above maintained its ownership
interest in the Company at 69.6 percent. |
|
|
|
The excess of the purchase cost over the stated value of shares purchased has
been recorded as a distribution of retained earnings. |
|
|
|
The Companys common
share activity is summarized below: |
|
|
|
|
|
|
|
|
|
|
|
Thousands of |
|
At stated value, |
|
|
shares
|
|
millions of dollars
|
Balance as at December 31, 2001 |
|
|
379,159 |
|
|
|
1,941 |
|
Issued for cash under stock option plan |
|
|
|
|
|
|
|
|
Purchases |
|
|
(296 |
) |
|
|
(2 |
) |
|
|
|
|
|
|
|
|
|
Balance as at December 31, 2002 |
|
|
378,863 |
|
|
|
1,939 |
|
Issued for cash under stock option plan |
|
|
49 |
|
|
|
2 |
|
Purchases |
|
|
(16,260 |
) |
|
|
(82 |
) |
|
|
|
|
|
|
|
|
|
Balance as at December 31, 2003 |
|
|
362,652 |
|
|
|
1,859 |
|
|
|
|
|
|
|
|
|
|
|
|
The following table provides the calculation of basic and diluted earnings per share: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2003
|
|
2002
|
|
2001
|
Net earnings (millions of dollars) |
|
|
1,682 |
|
|
|
1,224 |
|
|
|
1,255 |
|
Average number of common shares outstanding, weighted monthly (thousands) |
|
|
372,011 |
|
|
|
378,875 |
|
|
|
393,121 |
|
Plus: average number of shares issued on assumed exercise of stock options (thousands) |
|
|
143 |
|
|
|
1 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted average number of diluted common shares (thousands) |
|
|
372,154 |
|
|
|
378,876 |
|
|
|
393,121 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings per share basic (dollars) |
|
|
4.52 |
|
|
|
3.23 |
|
|
|
3.19 |
|
Earnings per share diluted (dollars) |
|
|
4.52 |
|
|
|
3.23 |
|
|
|
3.19 |
|
11. |
|
Miscellaneous financial information |
|
|
In 2003, net earnings included an after-tax gain of $9 million (2002 $2 million loss; 2001 $18 million gain) attributable to the effect of
changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at
December 31, 2003, by $797 million (2002 $941 million). Inventories of crude oil and products at year-end consisted of the following: |
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
Crude oil |
|
|
161 |
|
|
|
148 |
|
Petroleum products |
|
|
175 |
|
|
|
198 |
|
Chemical products |
|
|
57 |
|
|
|
70 |
|
Natural gas and other |
|
|
14 |
|
|
|
17 |
|
|
|
|
|
|
|
|
|
|
Total inventories of crude oil and products |
|
|
407 |
|
|
|
433 |
|
|
|
|
|
|
|
|
|
|
|
|
Research and development costs in 2003 were $63 million (2002 $64
million; 2001 $71 million) before investment tax credits earned on these
expenditures of $10 million (2002 $10 million; 2001 $6 million). The net
costs are included in expenses due to the uncertainty of future benefits. |
|
|
|
Cash flow from earnings included dividends of $15 million received from equity
investments in 2003 (2002 $18 million; 2001 $10 million). |
|
|
|
Accounts
receivable included allowance for doubtful accounts of $13 million in 2003
(2002 $13 million). |
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
Debt-related interest |
|
|
38 |
|
|
|
40 |
|
|
|
77 |
|
Other interest |
|
|
4 |
|
|
|
2 |
|
|
|
4 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total interest expense (a) |
|
|
42 |
|
|
|
42 |
|
|
|
81 |
|
Foreign-exchange expense (gain) on long-term debt |
|
|
(129 |
) |
|
|
(10 |
) |
|
|
71 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total financing costs |
|
|
(87 |
) |
|
|
32 |
|
|
|
152 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
Cash interest payments in 2003 were $38 million (2002 $41 million;
2001 $99 million). The weighted-average interest rate on short-term
debt in 2003 was 3.1 percent (2002 2.4 percent). The average effective
interest rate on the Companys debt was 2.9 percent in 2003 (2002 2.1
percent). |
F-17
13. |
|
Transactions with Exxon Mobil Corporation and affiliated companies
(ExxonMobil) |
|
|
Revenues and expenses of the Company also include the results of transactions
with ExxonMobil in the normal course of operations. These were conducted
on terms as favourable as they would have been with unrelated parties
and primarily consisted of the purchase and sale of crude oil, petroleum
and chemical products, as well as transportation, technical and
engineering services. Transactions with ExxonMobil also included amounts
paid and received in connection with the Companys participation in a
number of natural resources joint-venture operations in Canada. The
Company has an existing agreement with ExxonMobil Canada to share common
business and operational support services that allow the companies to
consolidate duplicate work and systems. The amounts paid or received
have been reflected in the statement of earnings as shown in the table
below. |
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
Operating revenues |
|
|
950 |
|
|
|
1036 |
|
|
|
664 |
|
Purchases of crude oil and products |
|
|
2,464 |
|
|
|
2,134 |
|
|
|
1,873 |
|
Operating expense |
|
|
14 |
|
|
|
57 |
|
|
|
47 |
|
|
|
Accounts payable due to Exxon Mobil Corporation at December 31, 2003, with
respect to the above transactions were $167 million (2002 $146 million). |
|
|
During 2003, the Company borrowed $818 million (Cdn) from Exxon Overseas
Corporation under two long-term loan agreements as described in note 3.
Interest paid on the loans in 2003 was $14 million. |
14. |
|
Net payments to governments |
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of dollars
|
|
2003
|
|
2002
|
|
2001
|
Current income tax expense (note 4) |
|
|
610 |
|
|
|
718 |
|
|
|
679 |
|
Federal excise tax |
|
|
1,254 |
|
|
|
1,231 |
|
|
|
1,180 |
|
Property taxes included in expenses |
|
|
80 |
|
|
|
85 |
|
|
|
86 |
|
Payroll and other taxes included in expenses |
|
|
52 |
|
|
|
51 |
|
|
|
47 |
|
GST/QST/HST collected (a) |
|
|
2,015 |
|
|
|
1,717 |
|
|
|
1,749 |
|
GST/QST/HST input tax credits (a) |
|
|
(1,705 |
) |
|
|
(1,368 |
) |
|
|
(1,384 |
) |
Other consumer taxes collected |
|
|
1,662 |
|
|
|
1,589 |
|
|
|
1,585 |
|
Crown royalties |
|
|
418 |
|
|
|
314 |
|
|
|
460 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total paid or payable to governments |
|
|
4,386 |
|
|
|
4,337 |
|
|
|
4,402 |
|
Less investment tax credits and other receipts |
|
|
30 |
|
|
|
12 |
|
|
|
7 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net payments to governments |
|
|
4,356 |
|
|
|
4,325 |
|
|
|
4,395 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net payments to: |
|
|
|
|
|
|
|
|
|
|
|
|
Federal government |
|
|
2,061 |
|
|
|
2,171 |
|
|
|
2,160 |
|
Provincial governments |
|
|
2,215 |
|
|
|
2,069 |
|
|
|
2,149 |
|
Local governments |
|
|
80 |
|
|
|
85 |
|
|
|
86 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net payments to governments |
|
|
4,356 |
|
|
|
4,325 |
|
|
|
4,395 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(a) |
|
The abbreviations refer to the federal goods and services tax, the Quebec
sales tax and the federal/provincial harmonized sales tax, respectively. The
HST is applicable in the provinces of Nova Scotia, New Brunswick and
Newfoundland and Labrador. |
15. |
|
Reporting investments in mineral interests in oil and gas properties |
|
|
Statements of Financial Accounting Standards No. 141 (FAS 141),
Business Combinations and No. 142 (FAS 142), Goodwill and Other intangible
Assets were issued by the Financial Accounting Standards Board (FASB) in
June 2001 and became effective for the Company on July 1, 2001 and January 1,
2002, respectively. Currently, the Emerging Issues Task Force (EITF) is
considering the issue of whether FAS 141 and 142 require interests held under
oil, gas and mineral leases to be separately classified as intangible assets
on the balance sheets of companies in the extractive industries. If such
interests were deemed to be intangible assets by the EITF, mineral rights to
extract oil and gas for both undeveloped and developed leaseholds would be
classified separately from oil and gas properties as intangible assets on the
Companys balance sheet. Historically, the Company has capitalized the cost
of oil and gas leasehold interests in accordance with statement of Financial
Accounting Standard No. 19 (FAS 19), Financial Accounting and Reporting by
Oil and Gas Producing Companies. Also, consistent with industry practice,
the Company has reported these assets as part of tangible oil and gas
property, plant and equipment. |
|
|
|
This interpretation of FAS 141 and 142 would only affect the
classification of oil and gas leaseholds on the Companys balance sheet and
would not affect total assets, net worth or cash flows. The Companys results
of operations would not be affected, since these leasehold costs would
continue to be amortized in accordance with FAS 19. The amount that is
subject to reclassification as of December 31, 2003 was $935 million and
$1,109 million as of December 31, 2002. |
F-18
INDEX TO EXHIBITS
The following exhibits numbered in accordance with Item 601 of Regulation S-K
are filed as part of this report:
(3) |
|
(i) Restated certificate and articles of incorporation of the Company
(Incorporated herein by reference to Exhibit (3) to the Companys Quarterly
Report on Form 10-Q for the quarter ended June 30, 1998 (File No. 0-12014)).
|
(ii) |
|
By-laws of the Company (Incorporated herein by reference to Exhibit
(3)(ii) to the Companys Quarterly Report on Form 10-Q for the quarter ended
March 31, 2003 (File No. 0-12014)). |
(4) |
|
The Companys long term debt authorized under any instrument does not
exceed 10 percent of the Companys consolidated assets. The Company agrees to
furnish to the Commission upon request a copy of any such instrument. |
(10) |
|
(ii) (1) Alberta Crown Agreement, dated February 4, 1975, relating to
the participation of the Province of Alberta in Syncrude (Incorporated
herein by reference to Exhibit 13(a) of the Companys Registration
Statement on Form S-1, as filed with the Securities and Exchange Commission
on August 21, 1979 (File No. 2-65290)). |
(2) |
|
Amendment to Alberta Crown Agreement, dated January 1, 1983
(Incorporated herein by reference to Exhibit (10)(ii)(2) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1983 (File No.
2-9259)). |
|
(3) |
|
Syncrude Ownership and Management Agreement, dated February 4, 1975
(Incorporated herein by reference to Exhibit 13(b) of the Companys
Registration Statement on Form S-1, as filed with the Securities and
Exchange Commission on August 21, 1979 (File No. 2-65290)). |
|
(4) |
|
Letter Agreement, dated February 8, 1982, between the Government of
Canada and Esso Resources Canada Limited, amending Schedule C to the
Syncrude Ownership and Management Agreement filed as Exhibit (10)(ii)(2)
(Incorporated herein by reference to Exhibit (20) of the Companys Annual
Report on Form 10-K for the year ended December 31, 1981 (File No.
2-9259)). |
|
(5) |
|
Norman Wells Pipeline Agreement, dated January 1, 1980, relating to the
operation, tolls and financing of the pipeline system from the Norman Wells
field (Incorporated herein by reference to Exhibit 10(a)(3) of the
Companys Annual Report on Form 10-K for the year ended December 31, 1981
(File No. 2-9259)). |
|
(6) |
|
Norman Wells Pipeline Amending Agreement, dated April 1, 1982
(Incorporated herein by reference to Exhibit (10)(ii)(5) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1982 (File No.
2-9259)). |
|
(7) |
|
Letter Agreement clarifying certain provisions to the Norman Wells
Pipeline Agreement, dated August 29, 1983 (Incorporated herein by reference
to Exhibit (10)(ii)(7) of the Companys Annual Report on Form 10-K for the
year ended December 31, 1983 (File No. 2-9259)). |
|
(8) |
|
Norman Wells Pipeline Amending Agreement, made as of February 1, 1985,
relating to certain amendments ordered by the National Energy Board
(Incorporated herein by reference to Exhibit (10)(ii)(8) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1986 (File No.
0-12014)). |
|
(9) |
|
Norman Wells Pipeline Amending Agreement, made as of April 1, 1985,
relating to the definition of Operating Year (Incorporated herein by
reference to Exhibit (10)(ii)(9) of the Companys Annual Report on Form
10-K for the year ended December 31, 1986 (File No. 0-12014)). |
|
(10) |
|
Norman Wells Expansion Agreement, dated October 6, 1983, relating to
the prices and royalties payable for crude oil production at Norman Wells
(Incorporated herein by reference to Exhibit (10)(ii)(8) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1983 (File No.
2-9259)). |
|
(11) |
|
Alberta Cold Lake Crown Agreement, dated June 25, 1984, relating to
the royalties payable and the assurances given in respect of the Cold Lake
production project (Incorporated herein by reference to Exhibit
(10)(ii)(11) of the Companys Annual Report on Form 10-K for the year ended
December 31, 1986 (File No. 0-12014)). |
(12) |
|
Amendment to Alberta Crown Agreement, dated January 1, 1986
(Incorporated herein by reference to Exhibit (10)(ii)(12) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1987 (File No.
0-12014)). |
|
(13) |
|
Amendment to Alberta Crown Agreement, dated November 25, 1987
(Incorporated herein by reference to Exhibit (10)(ii)(13) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1987 (File No.
0-12014)). |
|
(14) |
|
Amendment to Syncrude Ownership and Management Agreement, dated March
10, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(14) of the
Companys Annual Report on Form 10-K for the year ended December 31, 1989
(File No. 0-12014)). |
|
(15) |
|
Amendment to Alberta Crown Agreement, dated August 1, 1991
(Incorporated herein by reference to Exhibit (10)(ii)(15) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1991 (File No.
0-12014))). |
|
(16) |
|
Norman Wells Settlement Agreement, dated July 31, 1996. (Incorporated
herein by reference to Exhibit (10)(ii)(16) of the Companys Annual Report
on Form 10-K for the year ended December 31, 1996 (File No. 0-12014)). |
|
(17) |
|
Amendment to Alberta Crown Agreement, dated January 1, 1997.
(Incorporated herein by reference to Exhibit (10)(ii)(17) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1996 (File No.
0-12014)). |
|
(18) |
|
Norman Wells Pipeline Amending Agreement, dated December 12, 1997.
(Incorporated herein by reference to Exhibit (10)(ii)(18) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1998 (File No.
0-12014)). |
|
(19) |
|
Norman Wells Pipeline 1999 Amending Agreement, dated May 1, 1999.
(Incorporated herein by reference to Exhibit (10)(ii)(19) of the Companys
Annual Report on Form 10-K for the year ended December 31, 1999 (File No.
0-12014)). |
|
(20) |
|
Alberta Cold Lake Transition Agreement, effective January 1, 2000,
relating to the royalties payable in respect of the Cold Lake production
project and terminating the Alberta Cold Lake Crown Agreement.
(Incorporated herein by reference to Exhibit (10)(ii)(20) of the Companys
Annual Report on Form 10-K for the year ended December 31, 2001 (File No.
0-12014)). |
|
(21) |
|
Amendment to Alberta Crown Agreement effective January 1, 2001
(Incorporated herein by reference to Exhibit (10)(ii)(21) of the Companys
Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No.
0-12014)). |
|
(22) |
|
Amendment to Syncrude Ownership and Management Agreement effective
January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(22)
of the Companys Quarterly Report on Form 10-Q for the quarter ended June
30, 2002 (File No. 0-12014)). |
|
(23) |
|
Amendment to Syncrude Ownership and Management Agreement effective
September 16, 1994 (Incorporated herein by reference to Exhibit
(10)(ii)(23) of the Companys Quarterly Report on Form 10-Q for the quarter
ended June 30, 2002 (File No. 0-12014)). |
|
(24) |
|
Amendment to Alberta Crown Agreement dated November 29, 1995
(Incorporated herein by reference to Exhibit (10)(ii)(24) of the Companys
Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No.
0-12014)). |
|
(iii)(A)(1) |
|
Form of Letter relating to Supplemental Retirement Income
(Incorporated herein by reference to Exhibit (10)(c)(3) of the Companys Annual
Report on Form 10-K for the year ended December 31, 1980 (File No. 2-9259)). |
(2) |
|
Incentive Share Unit Plan and Incentive Share Units granted in 2001
are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the
Companys Annual Report on Form 10-K for the year ended December 31,
2001. Units granted in 2000 are incorporated herein by reference to
Exhibit (10)(iii)(A)(2) of the Companys Annual Report on Form 10-K for
the year ended December 31, 2000 (File No. 0-12014); units granted in
1999 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of
the Companys Annual Report on Form 10-K for the year ended December 31,
1999 (File No. 0-12014); units granted in 1998 are incorporated herein
by reference to Exhibit (10)(iii)(A)(3) of the Companys Annual Report
on Form 10-K for the year ended December 31, 1998 (File No. 0-12014);
units granted in 1997 are incorporated herein by reference to Exhibit
(10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for the year
ended December 31, 1997 (File No. 0-12014); units granted in 1996 are
incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the
Companys Annual Report on Form 10-K for the year ended December 31,
1996 (File No. 0-12014); units granted in 1995 are incorporated herein
by reference to Exhibit (10)(iii)(A)(3) of the Companys Annual Report
on Form 10-K for the year ended December 31, 1995 (File No. 0-12014);
and units granted in 1994 are incorporated herein by reference to
Exhibit (10)(iii)(A)(3) of the Companys Annual Report on Form 10-K for
the year ended December 31, 1994 (File No. 0-12014). |
|
(3) |
|
Deferred Share Unit Plan. (Incorporated herein by reference to
Exhibit(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for
the year ended December 31, 1998 (File No. 0-12014)). |
|
(4) |
|
Deferred Share Unit Plan for Nonemployee Directors. (Incorporated
herein by reference to Exhibit (10)(iii)(A)(6) of the Companys Annual
Report on Form 10-K for the year ended December 31, 1998 (File No.
0-12014)). |
|
(5) |
|
Earnings Bonus Units granted in 2003; Earnings Bonus Unit Plan and
units granted in 2002 are (incorporated herein by reference to Exhibit
(10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for the year
ended December 31, 2002 (File No. 0-12014)) and Earnings Bonus Unit Plan
and units granted in 2001 are incorporated herein by reference to
Exhibit (10)(iii)(A)(5) of the Companys Annual Report on Form 10-K for
the year ended December 31, 2000 (File No. 0-12014). |
|
(6) |
|
Incentive Stock Option Plan and Incentive Stock Options granted in
2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the
Companys Quarterly Report on Form 10-Q for the quarter ended June 30,
2002 (File No. 0-12014)). |
|
(7) |
|
Restricted Stock Unit Plan and Restricted Stock Units granted in
2002 (incorporated herein by reference to Exhibit (10)(iii)(A)(7) of the
Companys Annual Report on Form 10-K for the year ended December 31,
2002 (File No. 0-12014)). |
|
(8) |
|
Restricted Stock Unit Plan and Restricted Stock Units granted in
2003. |
(21) |
|
Imperial Oil Resources Limited, McColl-Frontenac Petroleum Inc., Imperial
Oil Resources N.W.T. Limited and Imperial Oil Resources Ventures Limited, all
incorporated in Canada, are wholly-owned subsidiaries of the Company. The names
of all other subsidiaries of the Company are omitted because, considered in the
aggregate as a single subsidiary, they would not constitute a significant
subsidiary as of December 31, 2003. |
(23) |
|
(ii) |
|
(A) |
|
Consent of PricewaterhouseCoopers LLP. |
|
|
|
|
(B) |
|
Consent of Chief Engineering Officer. |
(31.1) |
|
Certification by principal executive officer of Periodic Financial
Report pursuant to Rule 13a-14(a). |
|
(31.2) |
|
Certification by principal financial
officer of Periodic Financial Report pursuant to Rule 13a-14(a). |
|
(32.1) |
|
Certification by chief executive officer of Periodic Financial Report pursuant
to Rule 13a-14(b) and 18 U.S.C. Section 1350. |
|
(32.2) |
|
Certification by chief financial officer of Periodic Financial Report
pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350. |
EX-10.III.A.5
3
t12211exv10xiiiyxayx5y.htm
EX-10(III)(A)(5)
exv10xiiiyxayx5y
Exhibit (10)(iii)(A)(5)
PRIVATE
|
|
|
|
|
|
|
IMPERIAL OIL LIMITED
|
|
2003 |
|
|
EARNINGS BONUS UNIT AWARD |
|
|
Name of Grantee: |
|
Grant Date: Nov. 20, 2003 |
Number of IEBUs: |
|
IEBU No: |
Maximum Settlement Value per IEBU: $3.00 |
|
Empl. No: |
Maximum Settlement Value of Award: |
|
|
This IMPERIAL EARNINGS BONUS UNIT (IEBU) AWARD is granted by Imperial Oil
Limited (the Company) effective November 20, 2003, (the Grant Date). This
Award is subject to the provisions herein stated and the Imperial Oil Limited
Earnings Bonus Unit Plan (the Plan) and is granted on the conditions that
Grantee accepts such provisions. The Grant Instrument incorporates by
reference the provisions of the Plan, as it may be amended from time to time,
including without limitation the definitions of terms used in this Grant
Instrument and defined in the Plan.
|
|
This incentive is provided by the grant of Imperial Oil Limited Earnings
Bonus Units (IEBUs), which gives the Grantee the right, subject to the
terms and conditions herein, to receive a cash payment from the Company
equal to the Maximum Settlement Value per IEBU, when the cumulative basic
net earnings per common share of the Company reach at least the Maximum
Settlement Value per IEBU prior to the fifth anniversary of the Grant
Date, or equal to the cumulative basic net earnings per common share
ending on the last full quarter that precedes the fifth anniversary of the
Grant Date if the cumulative basic net earnings per common share do not
reach the Maximum Settlement Value per IEBU. |
2. |
|
SETTLEMENT DATE AND DEFERRED PAYMENTS |
|
|
The Settlement Date of these IEBUs shall be the earlier of the fifth
anniversary of the Grant Date, or the date of publication of the Companys
quarterly earnings statements which bring the cumulative basic net
earnings per common share as initially published commencing with the first
full quarter following the Grant Date to an amount at least equal to the
Maximum Settlement Value per IEBU specified above; provided, however, in
the discretion of the Company, payment may be deferred as specified by the
Grantee based on options for such deferral provided to the Grantee by the
Company. |
|
|
No right created by the granting of an IEBU can be pledged in any
circumstance, nor can it be assigned except in the case of death. Any
attempt to pledge or assign may, in the discretion of the Company, result
in forfeiture of the rights created herein. |
|
|
|
|
|
IMPERIAL OIL LIMITED |
|
|
![-s- T.J. Hearn](t12211t1221104.gif) |
|
|
Chairman, President and
Chief Executive Officer |
EX-10.III.A.8
4
t12211exv10xiiiyxayx8y.htm
EX-10(III)(A)(8)
exv10xiiiyxayx8y
Exhibit (10)(iii)(A)(8)
PRIVATE
RESTRICTED STOCK UNIT PLAN
|
|
The purpose of the Restricted Stock Unit Plan (the Plan) is to provide
an incentive to selected key employees and to nonemployee directors to
promote optimum individual contribution to sustained improvement in the
Companys business performance and shareholder value, and to motivate
them to remain with the Company, its wholly owned subsidiaries or a
Designated Employer, as these terms are defined in clause 4 of this Plan
document. |
|
|
This incentive is provided by the grant of Restricted Stock Units
(RSU), which give the Plan participant the right, subject to the terms
and conditions herein, on the first Exercise Date, as defined in clause
4, to receive from the Company, upon exercise in the prescribed manner,
an amount in respect of each RSU, which is equal to the Exercise Price,
as defined in clause 4 and on the last Exercise Date to receive from the
Company, upon exercise in the prescribed manner, Common Shares, as
defined in clause 4, or to elect to receive a cash amount in respect of
each RSU, which is equal to the Exercise Price. |
3. |
|
Eligibility and Awards: |
|
|
RSUs will be granted only to key employees and to nonemployee directors
of the Company or to key employees of a Designated Employer, as defined
in clause 4. Frequency and level of awards to individual participants
will be determined by the Company. Individual awards under this plan
will not necessarily be granted annually. The entitlement to the formula
amounts of benefits in clause 2 and clause 6 arises from past services
rendered from the Grant Date to the date of vesting of the RSU. |
|
|
In this Plan document, except where the context otherwise indicates, the
following definitions apply: |
|
(a) |
|
Company means Imperial Oil Limited. |
|
(b) |
|
Common Share means a common share in the capital of the Company. |
|
(c) |
|
Continued Employment means continued employment after the
RSU Grant Date with any one or more of the Company, its wholly owned
subsidiaries or a Designated Employer, and for nonemployee directors
means the period of time while serving as a director of Imperial Oil
Limited. |
|
(d) |
|
Designated Employer means an employer which is an affiliate
of the Company and which is designated as such for the purposes of
this Plan by the Company. |
|
(e) |
|
Exercise Date means, in respect of an RSU being exercised
pursuant to clause 8, the dates on which the RSU is vested, the
date of death of a Grantee or the date of deferral of exercise, as
applicable. |
|
(f) |
|
Exercise Price for a particular RSU means the closing price
of Common Shares of the Company on the Toronto Stock Exchange on the
Exercise Date, or if there is no closing price on the Exercise Date,
the last preceding closing price on the Toronto Stock Exchange. |
|
(g) |
|
Grant Date means the date specified in the Grant Instrument
that an RSU is granted under the Plan. |
|
(h) |
|
Grant Instrument means the document given by the Company to
an employee and nonemployee director governing a grant of Restricted
Stock Units. |
|
(i) |
|
Grantee means the recipient of a Grant Instrument. |
|
(j) |
|
Dividend Equivalents means cash payments pursuant to clause
6 corresponding in amount and timing to the cash dividend that is
paid by the Company on a common share of the Company. |
|
(j) |
|
Legal Representatives means a Grantees executors or
administrators. |
|
|
Subject to the restrictions in clause 7 or the deferral of exercise in
clause 8, the total RSUs granted under a particular Grant Instrument
vest and become exercisable in accordance with the following schedule: |
|
(a) |
|
50% of the RSUs will be exercised on the third anniversary following
the Grant Date; and |
|
(b) |
|
the remaining 50% of the RSUs will be exercised on the
seventh anniversary following the Grant date. |
|
|
The Company will pay the Grantee cash with respect to each unexercised
RSU granted to the Grantee corresponding in amount and timing to the cash
dividend that is paid by the Company on a Common Share of the Company. |
7. |
|
Restrictions on Exercise: |
|
(a) |
|
No RSU will be exercised other than in accordance with the
provisions of clauses 5, 7 and 8. |
|
(b) |
|
Except as provided hereinafter, an RSU will be exercised only
during Continued Employment. |
|
(c) |
|
In case the Grantee becomes entitled on or after the Grant
Date to payment of
extended disability benefits under the Companys extended
disability benefit plan, the RSUs or the balance remaining will
be exercised in accordance with the provisions of clause 5. |
|
(d) |
|
In case of death of the Grantee, the unexercised RSUs will
be exercised by the Company as of the date of death and paid to the
Grantees Legal Representatives. |
|
(e) |
|
In case the Grantees Continued Employment terminates on or
after, the third anniversary of the Grant Date and the Grantee
becomes entitled to an annuity under section 2 of the Companys
retirement plan (or the provision in any plan or plans of the
Company substituted therefor), the RSUs or the balance remaining
will be exercised by the Company in accordance with the provisions
of clauses 5, 7 and 8. |
|
(f) |
|
Notwithstanding anything to the contrary in this Plan, the
Company, at its discretion, may determine that the Grantees RSUs,
or the balance remaining, are forfeited and are not exercisable as a
consequence of any of the following situations: |
- 2 -
|
(i) |
|
the Company believes that the Grantee intends
to terminate Continued Employment and sub-clauses 7(c), 7(d)
and 7(e) would not be applicable, or |
|
(ii) |
|
during Continued Employment or during the
period of 24 months after the termination of the Grantees
Continued Employment, the Grantee, without the written
consent of the Company, directly or indirectly is employed
in, or as principal, agent, partner or otherwise engages in
any business that is in competition with the Company, as
determined by the Company, or otherwise engages in any
activity that is detrimental to the Company, as determined by
the Company. |
|
(g) |
|
Except as provided in sub-clauses 7(c), 7(d), and 7(e), the
RSUs, or the balance remaining, if not forfeited earlier, will be
forfeited and will not be exercisable after the last day of
Continued Employment. |
|
(h) |
|
Notwithstanding any other provision of this clause 7, the
Company may determine that a Grantees RSUs will not be forfeited
in whole or in part after the cessation of Continued Employment. |
8. |
|
Method and Deferral of Exercise: |
|
|
The RSUs will be exercised by the Company in accordance with clauses 5
and 7, provided however, the Company may, at its discretion, defer the
exercise of any RSUs to a later date in the event that a ban on trading,
imposed by the Company or applicable law, in Common Shares of the Company
by a director of the Company or an employee of the Company, its wholly
owned subsidiaries or a Designated Employer is in effect on the exercise
dates described in clauses 5 and 7. |
9. |
|
Issue of Common Shares |
|
(a) |
|
One Common Share will be issued by the Company for each RSU
that is exercised on the last Exercise Date unless the Grantee
notifies the Company, in such manner and within such period of time
as may be determined by the Company from time-to-time, that the
Grantee elects to receive a cash payment for the RSUs equal to the
Exercise Price for each RSU exercised. |
|
(b) |
|
The aggregate number of Common Shares that may be issued
pursuant to the exercise of RSUs shall not exceed 3.5 million
Common Shares. |
|
(a) |
|
The issue of share certificates or the cash payment of the benefit
arising on the exercise of an RSU will normally be made as soon as
practicable after the Exercise Date. |
|
(b) |
|
Cash payment of the Dividend Equivalents described in clause
6 will be made as soon as practicable after the Company pays a
dividend on the common shares of the Company. |
|
(c) |
|
Payments will be reduced by any amount required to be
withheld by any government authority. |
|
|
Notwithstanding the exercise of an RSU by the Company, in the event any
of the situations described in sub-clause 7(f)(ii) are applicable to the
Grantee, the Company, at its discretion, may require the Grantee to pay
to the Company a cash amount equal to the |
- 3 -
|
|
Exercise Price for each RSU
exercised during a period up to 180 days prior to termination of the
Grantees Continued Employment. |
|
|
In the case of any subdivision, consolidation, or reclassification of the
shares of the Company or other relevant change in the capitalization of
the Company, the Company, in its discretion, may make appropriate
adjustments in the number of Common Shares to be issued and the
calculation of the cash amount payable per RSU, and an adjustment by the
Company shall be conclusive as to the amount payable per RSU and shall be
final and binding upon all persons. |
|
(a) |
|
An RSU award does not carry any benefits associated with the
Companys benefit plans. |
|
(b) |
|
No right created by the granting of an RSU can be pledged in
any circumstance, nor can it be assigned. Any attempt to pledge or
assign may, in the discretion of the Company, result in forfeiture
of the rights created herein. |
|
(c) |
|
A Restricted Stock Unit means a unit equivalent in value to a
common share of the Company, credited by means of a book entry on
the Companys books. |
|
(d) |
|
Under no circumstances shall the RSUs be considered Common
Shares or other securities of the Company, nor shall they entitle
any Grantee to exercise voting rights or any other rights attaching
to the ownership of the common shares or other securities of the
Company, nor shall any grantee be considered the owner of the common
shares by virtue of the award of the RSUs. |
|
(e) |
|
The Company will determine conclusively all questions arising
in the administration or interpretation of this Plan and such a
determination shall be final and binding upon all persons. |
|
(f) |
|
The Companys obligation to issue Common Shares in accordance
with the Plan is subject to compliance with applicable securities
laws and the rules and regulations of applicable securities
regulatory authorities and stock exchanges regarding the issuance
and distribution of such Common Shares and to the listing of such
additional Common Shares on any stock exchange on which the Common
Shares are then listed. |
Imperial Oil Limited
December, 2003
- 4 -
|
|
|
|
|
|
|
|
|
PRIVATE |
|
|
IMPERIAL OIL LIMITED
|
|
Exhibit (10)(iii)(A)(8) |
|
|
2003 RESTRICTED STOCK UNITS |
|
|
|
|
Grant Date: December 31, 2003 |
|
|
Name of Grantee: |
|
Number of Units: |
Grant No: |
|
Empl. No: |
The following is a summary of the provisions of the Restricted Stock Unit
Plan. In all cases, the text of the Plan will govern in the event of any
discrepancy, inconsistency or omission between this Grant Instrument and the
Plan text.
|
|
The Company hereby grants to you, as of the date hereof, the number of 2003
Restricted Stock Units (RSU) as set out above, subject to the terms and
conditions of the Restricted Stock Unit Plan. |
|
|
Each 2003 RSU granted to you gives you the conditional right to receive from
the Company, upon exercise, |
|
|
(a) for the 50% of the RSUs exercised on December 31, 2006, an amount equal
to the Exercise Price, and
|
|
|
(b) for the 50% of the RSUs exercised on December 31, 2010, a common share
in the capital of the Company, or if you notify the Company, in such manner
and within such period of time as may be determined by the Company from
time-to-time, an amount equal to the Exercise Price. |
|
|
The Company will pay to you cash with respect to each unexercised 2003 RSU
corresponding in amount and timing to the cash dividend that is paid by the
Company on a common share of the Company. |
|
|
In this summary the following definitions apply: |
|
(a) |
|
Company means Imperial Oil Limited. |
|
(b) |
|
Exercise Price means the closing price of common shares of the Company
on the Toronto Stock Exchange on the Exercise Date. |
|
(c) |
|
Exercise Date means the day on which the RSU is exercised by the
Company as prescribed in the Plan text. |
|
(d) |
|
Continued Employment means continued employment after the RSU Grant
Date with any or more of the Company, its wholly owned subsidiaries or a
Designated Employer, and for nonemployee directors means the period of time
while serving as a director of Imperial Oil Limited. |
|
|
Subject to the expiry, forfeiture and deferral of exercise provisions summarized under clauses 7
and 8 of the Plan document, the 2003 RSUs granted to you will be exercised by the Company on the
following basis: |
|
|
|
No 2003 RSUs will be exercised before December 31, 2006. |
|
|
|
50% of the 2003 RSUs will be exercised on December 31, 2006. |
|
|
|
The remaining 50% of the 2003 RSUs will be exercised on December 31, 2010. |
|
|
This RSU grant shall expire or be forfeited at the earliest of the following times: |
|
(a) |
|
On termination of Continued Employment other than by reason of retirement on or after December 31, 2006, or other than by reason of death or disability
on or after December 31, 2003. |
|
(b) |
|
The Company believes that you intend to terminate Continued Employment or if during Continued Employment or during the 24 months after the termination of your Continued Employment you, without the written consent of the Company, were engaged in any business that was in competition with the Company or otherwise engaged in any activity that was detrimental to the Company. |
|
|
No right created by the grant of a 2003 RSU can be pledged in any
circumstance, nor can it be assigned and any attempt to do so may result in
forfeiture of the grant. |
|
|
In the event that this award is exercised, in whole or in part, and during
Continued Employment with the Company or during the period of 24 months
after the termination of your Continued Employment you, without the written
consent of the Company, were engaged in any business that was in competition
with the Company or otherwise engaged in any activity that was detrimental
to the Company, the Company may require payment to the Company, for that
part of the award exercised during the 180 day period prior to the date of
termination of Continued Employment. |
|
|
|
|
|
IMPERIAL OIL LIMITED |
|
|
![-s- T.J. Hearn](t12211t1221104.gif) |
|
|
Chairman, President and
Chief Executive Officer |
EX-23.II.A.
5
t12211exv23xiiyxay.htm
EX-23(II)(A)
exv23xiiyxay
Exhibit (23) (ii) (A)
CONSENT OF AUDITORS
We hereby consent to the incorporation by reference in the Offering Circular
constituting part of the Registration Statement on Form S-3 (File No. 33-41418)
filed with the Securities and Exchange Commission on June 27, 1991 of our
report dated February 18, 2004 which appears on page F-2 in Imperial Oils
Annual Report on Form 10-K for the fiscal year ended December 31, 2003. We
also consent to the incorporation by reference of our report dated February 18,
2004 on the information under the caption Reconciliation of Canadian and
United States generally accepted accounting principles in item 6 of such
Annual Report on Form 10-K, which appears on page F-2 of such Annual Report on
Form 10-K. We also consent to the reference to us under the heading Experts
in such Offering Circular.
/s/ PricewaterhouseCoopers
LLP
Chartered Accountants
March 11, 2004
PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers
LLP and the other member firms of PricewaterhouseCoopers International Limited,
each of which is a separate and independent legal entity.
EX-23.II.B.
6
t12211exv23xiiyxby.htm
EX-23(II)(B)
exv23xiiyxby
Exhibit (23)(ii)(B)
|
|
|
|
|
March 11, 2004 |
|
|
|
|
|
|
|
|
CONSENT OF THE CHIEF ENGINEERING OFFICER |
|
|
|
|
|
|
|
|
|
|
|
I hereby consent to the incorporation by reference in the Offering Circular
constituting part of the Registration Statement of Form S-3 (File No. 33-41418)
filed with the Securities and Exchange Commission on June 27, 1991 of the
statements and opinions as to reserves under Item 8. Financial Statements and
Supplementary Data in Imperial Oil Limiteds Annual Report on Form 10-K for
the fiscal year ended December 31, 2003, in reliance upon my authority as
expert and to the reference to me under the heading Experts in the Offering
Circular as modified by the Supplement dated March 15, 2004 to such Offering
Circular. |
|
|
|
|
|
|
|
|
|
|
|
/s/ Eddie Lui |
|
|
|
|
|
|
|
|
E.L. (Eddie) Lui, P.Eng.
Vice-President
Oil Sands Development & Research
Imperial Oil Resources
A wholly-owned subsidiary of
Imperial Oil Limited |
EX-31.1
7
t12211exv31w1.htm
EX-31.1
exv31w1
Exhibit (31.1)
Certifications
I, Timothy J. Hearn, certify that:
1. |
|
I have reviewed this annual report on Form 10-K of Imperial Oil Limited; |
|
2. |
|
Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report; |
|
3. |
|
Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this report; |
|
4. |
|
The registrants other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant
and have: |
a) |
|
Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the period in which
this report is being prepared; |
|
b) |
|
[Paragraph omitted pursuant to SEC
Release Nos. 33-8238 and 34-47986] |
|
c) |
|
Evaluated the effectiveness of the
registrants disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this report based
on such evaluation; and |
|
d) |
|
Disclosed in this report any change in the
registrants internal control over financial reporting that occurred
during the registrants most recent fiscal quarter (the registrants
fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and |
5. |
|
The registrants other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrants auditors and the audit
committee of the registrants board of directors (or persons performing the
equivalent functions): |
a) |
|
All significant deficiencies and material
weaknesses in the design or operation of internal control over financial
reporting which are reasonably likely to adversely affect the registrants
ability to record, process, summarize and report financial information; and |
|
b) |
|
Any fraud, whether or not material, that involves management or other
employees who have a significant role in the registrants internal controls
over financial reporting. |
Date: March 11, 2004
|
/s/ T.J. Hearn |
|
|
|
Timothy J. Hearn |
Chairman of the Board, |
President and Chief Executive
Officer |
(Principal Executive Officer) |
EX-31.2
8
t12211exv31w2.htm
EX-31.2
exv31w2
Exhibit (31.2)
Certifications
I, Paul A. Smith, certify that:
1. |
|
I have reviewed this annual report on Form 10-K of Imperial Oil Limited; |
|
2. |
|
Based on my knowledge, this report does not contain any untrue statement
of a material fact or omit to state a material fact necessary to make the
statements made, in light of the circumstances under which such statements
were made, not misleading with respect to the period covered by this
report; |
|
3. |
|
Based on my knowledge, the financial statements, and other financial
information included in this report, fairly present in all material
respects the financial condition, results of operations and cash flows of
the registrant as of, and for, the periods presented in this report; |
|
4. |
|
The registrants other certifying officer(s) and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant
and have: |
a) |
|
Designed such disclosure controls and procedures, or caused
such disclosure controls and procedures to be designed under our
supervision, to ensure that material information relating to the
registrant, including its consolidated subsidiaries, is made known to us
by others within those entities, particularly during the period in which
this report is being prepared; |
|
b) |
|
[Paragraph omitted pursuant to SEC
Release Nos. 33-8238 and 34-47986] |
|
c) |
|
Evaluated the effectiveness of the
registrants disclosure controls and procedures and presented in this
report our conclusions about the effectiveness of the disclosure controls
and procedures, as of the end of the period covered by this report based
on such evaluation; and |
|
d) |
|
Disclosed in this report any change in the
registrants internal control over financial reporting that occurred
during the registrants most recent fiscal quarter (the registrants
fourth fiscal quarter in the case of an annual report) that has materially
affected, or is reasonably likely to materially affect, the registrants
internal control over financial reporting; and |
5. |
|
The registrants other certifying officer(s) and I have disclosed, based
on our most recent evaluation of internal control over financial
reporting, to the registrants auditors and the audit committee of the
registrants board of directors (or persons performing the equivalent
functions): |
a) |
|
All significant deficiencies and material weaknesses in the
design or operation of internal control over financial reporting which are
reasonably likely to adversely affect the registrants ability to record,
process, summarize and report financial information; and |
|
b) |
|
Any fraud,
whether or not material, that involves management or other employees who
have a significant role in the registrants internal controls over
financial reporting. |
Date: March 11, 2004
|
/s/ Paul A. Smith |
|
|
|
Paul A. Smith |
Controller and Senior Vice-President, |
Finance and Administration |
(Principal Financial Officer) |
EX-32.1
9
t12211exv32w1.htm
EX-32.1
exv32w1
Exhibit (32.1)
Certification of Periodic Financial Report Pursuant to 18 U.S.C. Section 1350
For the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002, the undersigned, Timothy J. Hearn, the chief
executive officer of Imperial Oil Limited (the Company), hereby certifies that
to his knowledge:
(i) |
|
the Annual Report on Form 10-K of the Company for the year ended December
31, 2003, as filed with the Securities and Exchange Commission (the Report),
fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and |
(ii) |
|
the information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the Company. |
Date: March 11, 2004
|
/s/ T.J. Hearn |
|
|
Timothy J. Hearn |
Chairman of the Board, President and |
Chief Executive Officer |
EX-32.2
10
t12211exv32w2.htm
EX-32.2
exv32w2
Exhibit (32.2)
Certification of Periodic Financial Report Pursuant to 18 U.S.C. Section 1350
For the purposes of 18 U.S.C. Section 1350, as adopted pursuant to Section 906
of the Sarbanes-Oxley Act of 2002, the undersigned, Paul A. Smith, the chief
financial officer of Imperial Oil Limited (the Company), hereby certifies that
to his knowledge:
(i) |
|
the Annual Report on Form 10-K of the Company for the year ended December
31, 2003, as filed with the Securities and Exchange Commission (the Report),
fully complies with the requirements of section 13(a) or 15(d) of the
Securities Exchange Act of 1934; and |
(ii) |
|
the information contained in the Report fairly presents, in all material
respects, the financial condition and results of operations of the Company. |
Date: March 11, 2004
|
/s/ Paul A. Smith |
|
|
Paul A. Smith |
Controller and Senior Vice-President, |
Finance and Administration |
(Chief Financial Officer) |
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