e10vk
UNITED STATES 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
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For the fiscal year ended December 31, 2007
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Commission file number: 0-12014 |
IMPERIAL OIL LIMITED
(Exact name of registrant as specified in its charter)
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CANADA
(State or other jurisdiction of
incorporation or organization)
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98-0017682
(I.R.S. Employer
Identification No.) |
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237 FOURTH AVENUE S.W., CALGARY, AB, CANADA
(Address of principal executive offices)
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T2P 3M9
(Postal Code) |
Registrants telephone number, including area code:
1-800-567-3776
Securities registered pursuant to Section 12(b) of the Act:
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Name of each exchange on |
Title of each class
None
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which registered
None |
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Securities registered pursuant to Section 12(g) of the Act:
Common Shares (without par value)
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule
405 of the Securities Exchange Act of 1934).
Yes ü No......
Indicate by check mark if the registrant is not required to file reports pursuant to Section
13 or Section 15(d) of the Securities Exchange Act of 1934.
Yes ...... No ü
Indicate by check mark whether the registrant (1) has filed all reports required to be filed
by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or
for such shorter period that the registrant was required to file such reports), and (2) has been
subject to such filing requirements for the past 90 days.
Yes ü No......
Indicate by check mark if 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 ü No......
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, a non-accelerated filer, or a smaller reporting company (see definition of large
accelerated filer, accelerated filer and smaller reporting company in Rule 12b-2 of the
Securities Exchange Act of 1934).
Large accelerated filer ü Accelerated filer......
Non-accelerated filer...... Smaller reporting company......
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12 b-2 of
the Securities Exchange Act of 1934).
Yes ...... No ü
As of the last business day of the 2007 second fiscal quarter, the aggregate market value of
the voting stock held by non-affiliates of the registrant was Canadian $13,974,075,595 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 14, 2008, was 900,825,903.
All dollar amounts set forth in this report are in Canadian dollars, except where otherwise
indicated.
Note that numbers may not add due to rounding.
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 wire
transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New
York.
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2007 |
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2006 |
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2005 |
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2004 |
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2003 |
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(dollars) |
Rate at end of period |
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1.0120 |
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0.8582 |
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0.8579 |
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0.8310 |
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0.7738 |
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Average rate during period |
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0.9376 |
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0.8844 |
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0.8276 |
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0.7702 |
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0.7186 |
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High |
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1.0908 |
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0.9100 |
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0.8690 |
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0.8493 |
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0.7738 |
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Low |
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0.8437 |
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0.8528 |
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0.7872 |
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0.7158 |
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0.6349 |
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On February 14, 2008, the noon buying rate in New York City for wire transfers in Canadian
dollars as certified for customs purposes by the Federal Reserve Bank of New York was $1.0033
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 237 Fourth Avenue S.W. Calgary,
Alberta, Canada T2P 3M9; 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 or Imperial includes Imperial Oil Limited and its
subsidiaries.
The company is one of Canadas largest integrated oil companies. 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.
Financial Information by Operating Segments (under U.S. GAAP)
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2007 |
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2006 |
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2005 |
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2004 |
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2003 |
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External sales (1): |
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(millions of dollars) |
Natural resources |
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4,539 |
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4,619 |
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4,702 |
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3,689 |
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3,390 |
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Petroleum products |
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19,230 |
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18,527 |
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21,793 |
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17,503 |
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14,710 |
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Chemicals |
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1,300 |
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1,359 |
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1,302 |
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1,216 |
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994 |
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Corporate and other |
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25,069 |
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24,505 |
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27,797 |
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22,408 |
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19,094 |
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Intersegment sales: |
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Natural resources |
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4,146 |
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3,837 |
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3,487 |
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2,891 |
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2,224 |
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Petroleum products |
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2,305 |
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2,256 |
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2,224 |
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1,666 |
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1,294 |
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Chemicals |
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335 |
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345 |
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363 |
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293 |
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238 |
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Net income (2): |
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Natural resources |
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2,369 |
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2,376 |
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2,008 |
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1,517 |
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1,174 |
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Petroleum products |
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921 |
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624 |
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694 |
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556 |
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462 |
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Chemicals |
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97 |
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143 |
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121 |
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109 |
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44 |
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Corporate and other (3)/eliminations |
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(199) |
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(99) |
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(223) |
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(130) |
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25 |
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3,188 |
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3,044 |
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2,600 |
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2,052 |
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1,705 |
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Identifiable assets at December 31 (4): |
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Natural resources |
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8,171 |
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7,513 |
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7,289 |
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6,822 |
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6,397 |
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Petroleum products |
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6,727 |
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6,450 |
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6,257 |
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5,509 |
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5,225 |
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Chemicals |
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476 |
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504 |
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500 |
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490 |
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433 |
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Corporate and other/eliminations |
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1,251 |
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1,674 |
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1,536 |
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1,206 |
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282 |
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16,287 |
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16,141 |
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15,582 |
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14,027 |
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12,337 |
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Capital and exploration expenditures: |
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Natural resources |
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744 |
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787 |
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937 |
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1,113 |
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1,007 |
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Petroleum products |
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187 |
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361 |
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478 |
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283 |
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478 |
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Chemicals |
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11 |
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13 |
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19 |
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15 |
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41 |
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Corporate and other |
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36 |
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48 |
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41 |
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34 |
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33 |
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978 |
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1,209 |
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1,475 |
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1,445 |
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1,559 |
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(1) |
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Export sales are reported in note 3 to the consolidated financial statements on page
F-10. Total external sales include $4,894 million for 2005, $3,584 million for 2004, and
$2,851 million for 2003 for purchases/sales contracts with the same counterparty.
Associated costs were included in purchases of crude oil and products. Effective January
1, 2006, these purchases/sales were recorded on a net basis. See note 1, Summary of
significant Accounting Policies. |
(2) |
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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. |
(3) |
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Includes primarily interest charges on the debt obligations of the company, interest
income on investments, incentive compensation expenses, and intersegment consolidating
adjustments. |
(4) |
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The identifiable assets in each operating segment represent the net book value of the
tangible and intangible assets attributed to such segment. Net intangible assets
representing unrecognized prior service costs associated with the recognition of the
additional minimum pension liability in 2005 and prior years have been reclassified from
the operating segments to the corporate and other segment.
Amounts reclassified into the corporate and other segment were $92 million for 2005, $97
million in 2004, and $89 million for 2003. This change has no impact on total identifiable
assets at December 31 of 2005 and prior years. |
3
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, conventional crude oil, natural gas, upgraded crude oil and
heavy oil. 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.
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, 2007, was as follows:
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2007 |
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2006 |
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2005 |
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2004 |
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2003 |
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Conventional (including natural gas liquids): |
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(thousands a day) |
|
Barrels |
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Gross (1) |
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45 |
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55 |
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69 |
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76 |
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74 |
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Net (2) |
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33 |
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42 |
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54 |
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59 |
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57 |
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Heavy Oil (3): |
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Barrels |
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Gross (1) |
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154 |
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152 |
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139 |
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126 |
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129 |
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Net (2) |
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130 |
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127 |
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124 |
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112 |
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116 |
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Oil Sands (4): |
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Barrels |
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Gross (1) |
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76 |
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65 |
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53 |
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60 |
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53 |
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Net (2) |
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65 |
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58 |
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53 |
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59 |
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52 |
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Total: |
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Barrels |
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Gross (1) |
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275 |
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272 |
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261 |
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262 |
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256 |
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Net (2) |
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228 |
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227 |
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231 |
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230 |
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|
225 |
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(1) |
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Gross production of crude oil is the companys share of production from conventional
wells, Syncrude oil sands and Cold Lake heavy oil, 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) |
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Net production is gross production less the mineral owners or governments share or
both. |
(3) |
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Heavy oil typically is represented by crude oils with a viscosity of greater than
10,000 cP and recovered through enhanced thermal operations. The companys heavy oil
production volumes are from the Cold Lake production operations. |
(4) |
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Oil sands are a semi-solid material composed of bitumen, sand, water and clays and are
recovered through surface mining methods. Imperials oil sands production volumes are the
companys share of production volumes in the Syncrude joint venture. |
In 2004, conventional liquids production increased primarily due to increased natural gas
liquids production from the Wizard Lake gas cap. In 2005 and 2006 conventional production fell
mainly due to the natural decline of the companys conventional fields. In 2007, the lower
production volume was primarily due to decline in the Wizard Lake field. In 2004, Cold Lake
production declined due to the timing of steaming cycles and higher royalty, and Syncrude
production increased due to improved reliability in upgrading operations than in 2003. In 2005,
Cold Lake production increased due to the timing of steaming cycles and increased volumes from the
ongoing development drilling program, and Syncrude production declined primarily due to increased
maintenance for upgrading facilities. In 2006, Cold Lake production increased due to timing of
steam cycles and production from the ongoing development drilling program and Syncrude production
increased due to lower maintenance activities and the start-up of expanded upgrading facilities. In
2007, Cold Lake production increased due to timing of steam cycles and production from the ongoing
development drilling program and Syncrude production increased with full year operation of the
expanded upgrading facilities.
The companys average daily production and sales of natural gas during the five years ended
December 31, 2007 are set forth below. All gas volumes in this report are calculated at a pressure
base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit.
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2007 |
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2006 |
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2005 |
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2004 |
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2003 |
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(millions a day) |
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Sales (1): |
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Cubic feet |
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|
407 |
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|
513 |
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|
536 |
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|
520 |
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|
460 |
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Gross Production (2): |
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Cubic feet |
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|
458 |
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|
556 |
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|
580 |
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|
569 |
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|
513 |
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Net Production (2): |
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Cubic feet |
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|
404 |
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|
496 |
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|
514 |
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|
518 |
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|
457 |
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(1) |
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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) |
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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. |
4
In 2004 natural gas production increased primarily due to increased production from the Wizard
Lake gas cap. In 2005, gross natural gas production increased due to increased production from the
Nisku and Wizard Lake gas caps and the Medicine Hat gas field. In 2006, gas production decreased
primarily due to natural decline. In 2007, the lower production volume was primarily due to decline
in production from the gas cap at Wizard Lake.
Most of the companys natural gas sales are made under short term contracts.
The companys average sales price and production costs for conventional crude oil, Cold Lake
heavy oil and natural gas liquids and natural gas for the five years ended December 31, 2007, were
as follows:
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2007 |
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2006 |
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2005 |
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|
2004 |
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|
2003 |
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Average Sales Price: |
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Crude oil and natural gas liquids: |
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Dollars per barrel |
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45.16 |
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45.13 |
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37.21 |
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32.95 |
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28.92 |
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Natural gas: |
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Dollars per thousand cubic feet |
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6.95 |
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7.24 |
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9.00 |
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6.78 |
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|
6.60 |
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Average Production Costs Per |
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Unit of Net Production (1)(2): |
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Dollars per barrel |
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12.75 |
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|
11.08 |
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10.78 |
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|
9.25 |
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|
9.66 |
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(1) |
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Average production costs per unit of production 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. |
(2) |
|
Unit production costs are sometimes referred to as lifting costs. |
Canadian crude oil prices are mainly determined by international crude oil markets which are
volatile and the impact of foreign exchange rates.
Canadian natural gas prices are determined by North American gas markets which are also
volatile and the impact of foreign exchange rates. Natural gas prices throughout North America
increased in the second half of 2005 due to supply disruptions from hurricane damage to facilities
in the U.S. Gulf Coast.
In 2004, average unit production costs decreased mainly due to higher production from the
Wizard Lake gas cap. In 2005, average unit production costs increased mainly due to higher costs of
purchased natural gas at Cold Lake. In 2006, average production costs increased due to lower gas
production and higher liquids royalties resulting in lower net liquids production. Liquids
royalties were higher in the year due to increased realizations for Cold Lake production. In 2007,
unit production costs were higher primarily as a result of lower gas and liquids volumes due to
decline in production from Wizard 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 21 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 10 of the plants.
The companys production of conventional crude oil, Cold Lake heavy 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, 2007, 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 |
|
|
1,139 |
|
|
|
756 |
|
|
|
5,090 |
|
|
|
2,773 |
|
|
|
6,229 |
|
|
|
3,529 |
|
Heavy Oil wells |
|
|
4,143 |
|
|
|
4,143 |
|
|
|
|
|
|
|
|
|
|
|
4,143 |
|
|
|
4,143 |
|
|
|
|
(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 companys largest conventional oil producing asset is the Norman Wells oil field in the
Northwest Territories which currently accounts for approximately 57 percent of the companys net
production of conventional crude oil (approximately 63 percent of gross production). In 2007, net
production of crude oil and natural gas liquids was about 12,400 barrels per day and gross
production was about 18,200 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 540 mile
pipeline which transports the crude oil and natural gas liquids from the project. In 2007, those
costs were about $33 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
5
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 also has a nine percent interest in a project to
develop and produce natural gas reserves in the Sable Island area off the coast of the Province of
Nova Scotia.
Cold Lake
The company holds about 192,000 acres of heavy oil leases near Cold Lake, Alberta. To develop
the technology necessary to produce this oil commercially, the company has conducted experimental
pilot operations since 1964 to recover the heavy oil from wells by means of new drilling and
production techniques including steam injection. Research at, and operation of, the Cold Lake
pilots is continuing.
In late 1983, the company commenced the development, in phases, of its heavy oil resources at
Cold Lake. During 2007, average net production at Cold Lake was about 130,000 barrels per day and
gross production was about 153,500 barrels per day.
To maintain production at Cold Lake, capital expenditures for additional production wells and
associated facilities will be required periodically. In 2007, the company spent $307 million and
executed a development drilling program of 188 wells on existing phases. In 2008, a development
drilling program of more than 100 wells is planned within the approved development area to add
productive capacity from undeveloped areas of existing Cold Lake phases. In addition, opportunities
are being evaluated to improve utilization of the existing infrastructure.
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
third-party heavy oil upgrader in Lloydminster, Saskatchewan.
The Province of Alberta, in its capacity as lessor of the Cold Lake heavy oil leases, is
entitled to a royalty on production from the Cold Lake production project. The original royalty
agreement, which applied through the end of 1999, provided for a royalty calculated at the greater
of five percent of gross revenue or 30 percent of an amount based on revenue net of operating and
capital costs. It also provided for a royalty waiver on equity natural gas produced in Alberta and
deemed to be consumed in generating steam at the companys Cold Lake operations. Effective January
1, 2000, the company entered into an agreement with the Province of Alberta on a transitional
royalty arrangement that applied to all of the companys operations at Cold Lake until the end of
2007 at which time the generic Alberta regulations for heavy oil royalties applied. The transition
agreement made provision for the differences between the two royalty regimes (higher bitumen
royalties with gas royalty waiver vs. lower bitumen royalties and no gas royalty waiver). The
generic regulations which apply effective January 1, 2008, provide for a royalty calculated at the
greater of one percent of gross revenue or 25 percent of an amount based on revenue net of
operating and capital costs, and with no gas royalty waiver. The transition did not materially
change the amount of royalties that the company would have otherwise paid under the pre-existing
royalty arrangements. In 2007, the Alberta government proposed increases to the royalty rates
beginning in 2009. The company believes that this proposal could have an adverse effect on future
company investments in Alberta and the companys future financial results. The magnitude of the
potential impact will depend on the final form of enacted legislation and the future prices of oil
and gas and cannot be reasonably estimated at this time. The effective royalty on gross production
was 15 percent in 2007, 17 percent in 2006, 11 percent in 2005 and 2004 and 10 percent in 2003.
Other Heavy Oil Activity
The company has interests in other heavy oil leases in the Athabasca and Peace River areas of
northern Alberta. Evaluation wells completed on these leased areas established the presence of
heavy oil. The company continues to evaluate these leases to determine their potential for future
development.
The company holds varying interests in heavy oil lands totaling about 168,000 leased net acres
in the Athabasca area. 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 heavy oil deposit.
Syncrude Mining Operations
The company holds a 25 percent participating interest in Syncrude, a joint venture established
to recover shallow deposits of oil 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 (see map), mines 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. Since
startup in 1978, Syncrude has produced about 1.8 billion barrels of synthetic crude oil.
6
Syncrude has an operating license issued by the Province of Alberta which is effective until
2035. This license permits Syncrude to mine oil sands and produce synthetic crude oil from approved
development areas on oil sands leases. Syncrude holds eight oil sands leases covering about 248,300
acres in the Athabasca oil sands deposit. Issued by the Province of Alberta, the leases are
automatically renewable as long as oil 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.
As of January 1, 2002, the 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.
In 2007, the Alberta government proposed changes to the generic oil sands royalty regime
beginning in 2009. The Syncrude Joint Venture owners have a Crown Agreement with the Province of
Alberta that codifies the royalty rates through December 31, 2015. The Syncrude Joint Venture
owners are in discussions with the Alberta government to determine if an amended agreement can be
negotiated that would transition Syncrude to the new generic royalty regime before 2016.
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. The Base mine (located on lease
17) was depleted and ceased operation in 2007. In the North mine (leases 17 and 22) and in the
Aurora mine (leases 10, 12 and 34), truck, shovel and hydrotransport systems are used. The
extraction facilities, which separate crude bitumen from sand, are capable of processing
approximately 830,000 tons of oil sands a day, producing about 150 million barrels of crude bitumen
a year. This represents recovery capability of about 93 percent of the crude bitumen contained in
the mined oil sands.
Crude bitumen extracted from oil sands is refined to a marketable hydrocarbon product through
a combination of carbon removal in three 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 2007, the upgrading process yielded 0.843 barrels of synthetic
crude oil per barrel of crude bitumen. In 2007, about 38 percent of the synthetic crude oil was
processed by Edmonton area refineries and the remaining 62 percent was pipelined to refineries in
7
eastern Canada or exported to the United States. Electricity is provided to Syncrude by a 270
megawatt electricity generating plant and a 160 megawatt electricity generating plant, both located
at Syncrude. The generating plants are owned by the Syncrude participants. Recycled water is the
primary water source, and incremental raw water is drawn, under license, from the Athabasca River.
The companys 25 percent share of net investment in plant, property and equipment, including
surface mining facilities, transportation equipment and upgrading facilities is about $3.4 billion.
In 2007 Syncrudes net production of synthetic crude oil was about 259,300 barrels per day and
gross production was about 305,000 barrels per day. The companys share of net production in 2007
was about 64,800 barrels per day.
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 22 miles 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. The second Aurora
mining and extraction development became fully operational in 2004. The increased upgrading
capacity came on stream in 2006. These projects increased total production capacity to about
355,000 barrels of synthetic crude oil a day. The companys share of total project costs was $2.1
billion. Additional mining trains in the North mine and Aurora mine were also completed in 2005.
There are no approved plans for major future expansion projects.
On May 1, 2007, the company implemented a management services agreement under which Syncrude
will be provided with operational, technical and business management services from Imperial and
Exxon Mobil Corporation. The agreement has an initial term of 10 years and may be terminated by the
company or Syncrude with at least two years prior written notice.
The following table sets forth certain operating statistics for the Syncrude operations:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
Total mined overburden (1)
millions of cubic yards |
|
|
132.2 |
|
|
|
128.2 |
|
|
|
97.1 |
|
|
|
100.3 |
|
|
|
109.2 |
|
Mined overburden to oil sands ratio (1) |
|
|
1.06 |
|
|
|
1.18 |
|
|
|
1.02 |
|
|
|
0.94 |
|
|
|
1.15 |
|
Oil sands mined
millions of tons |
|
|
221.0 |
|
|
|
195.5 |
|
|
|
168.0 |
|
|
|
188.0 |
|
|
|
168.0 |
|
Average
bitumen grade (weight percent) |
|
|
11.6 |
|
|
|
11.4 |
|
|
|
11.1 |
|
|
|
11.1 |
|
|
|
11.0 |
|
Crude bitumen in mined oil sands
millions of tons |
|
|
25.6 |
|
|
|
22.2 |
|
|
|
18.6 |
|
|
|
20.9 |
|
|
|
18.5 |
|
Average
extraction recovery (percent) |
|
|
91.8 |
|
|
|
90.3 |
|
|
|
89.1 |
|
|
|
87.3 |
|
|
|
88.6 |
|
Crude bitumen production (2)
millions of barrels |
|
|
132.5 |
|
|
|
111.6 |
|
|
|
94.2 |
|
|
|
103.3 |
|
|
|
92.3 |
|
Average
upgrading yield (percent) |
|
|
84.3 |
|
|
|
84.9 |
|
|
|
85.3 |
|
|
|
85.5 |
|
|
|
86.0 |
|
Gross synthetic crude oil produced
millions of barrels |
|
|
113.0 |
|
|
|
95.5 |
|
|
|
79.3 |
|
|
|
88.4 |
|
|
|
78.4 |
|
Companys net share (3)
millions of barrels |
|
|
23.7 |
|
|
|
21.3 |
|
|
|
19.3 |
|
|
|
21.6 |
|
|
|
19.1 |
|
|
|
|
(1) |
|
Includes pre-stripping of mine areas and reclamation volumes. |
(2) |
|
Crude bitumen production is equal to crude bitumen in mined oil 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 Oil Sands Activity
The company holds a 100 percent interest in approximately 33,400 acres of surface mineable oil
sands which forms part of the Kearl project in the Athabasca region of northern Alberta. The
company, as operator, filed a regulatory application in July 2005 with the Alberta Energy and
Utilities Board for the development of the Kearl oil sands as a joint project with ExxonMobil
Canada. The Alberta Energy and Utilities Board and the Government of Canada gave conditional
regulatory approval in February 2007 to the companys proposed project, following a joint federal
and provincial review. The company, with an approximate 70 percent interest, continues to progress
a phased development of the project.
The company is continuing to evaluate other undeveloped oil sands acreage.
8
Land Holdings
At December 31, 2007 and 2006, the company held the following oil and gas rights, and heavy
oil and oil sands leases:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Acres |
|
|
|
Developed |
|
|
Undeveloped |
|
|
Total |
|
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
|
2007 |
|
|
2006 |
|
Western Provinces |
|
|
|
|
|
|
|
|
|
(thousands) |
|
|
|
|
|
|
|
|
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
2,529 |
|
|
|
2,550 |
|
|
|
371 |
|
|
|
382 |
|
|
|
2,900 |
|
|
|
2,932 |
|
Net (2) |
|
|
995 |
|
|
|
1,006 |
|
|
|
223 |
|
|
|
235 |
|
|
|
1,218 |
|
|
|
1,241 |
|
Heavy Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
102 |
|
|
|
102 |
|
|
|
429 |
|
|
|
429 |
|
|
|
531 |
|
|
|
531 |
|
Net (2) |
|
|
102 |
|
|
|
102 |
|
|
|
258 |
|
|
|
258 |
|
|
|
360 |
|
|
|
360 |
|
Oil Sands |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
116 |
|
|
|
116 |
|
|
|
293 |
|
|
|
294 |
|
|
|
409 |
|
|
|
410 |
|
Net (2) |
|
|
29 |
|
|
|
29 |
|
|
|
134 |
|
|
|
134 |
|
|
|
163 |
|
|
|
163 |
|
Canada Lands (3): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
78 |
|
|
|
78 |
|
|
|
1,302 |
|
|
|
794 |
|
|
|
1,380 |
|
|
|
872 |
|
Net (2) |
|
|
8 |
|
|
|
8 |
|
|
|
496 |
|
|
|
242 |
|
|
|
504 |
|
|
|
250 |
|
Atlantic Offshore |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
65 |
|
|
|
42 |
|
|
|
6,343 |
|
|
|
6,425 |
|
|
|
6,408 |
|
|
|
6,467 |
|
Net (2) |
|
|
6 |
|
|
|
4 |
|
|
|
1,513 |
|
|
|
1,524 |
|
|
|
1,519 |
|
|
|
1,528 |
|
Total (4): |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gross (1) |
|
|
2,890 |
|
|
|
2,888 |
|
|
|
8,738 |
|
|
|
8,324 |
|
|
|
11,628 |
|
|
|
11,212 |
|
Net (2) |
|
|
1,140 |
|
|
|
1,149 |
|
|
|
2,624 |
|
|
|
2,393 |
|
|
|
3,764 |
|
|
|
3,542 |
|
|
|
|
(1) |
|
Gross acres include the interests of others. |
(2) |
|
Net acres exclude the interests of others. |
(3) |
|
Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and other
Northwest Territories, Nunavut and Yukon regions. |
(4) |
|
Certain land holdings are subject to modification under agreements whereby others may
earn interests in the companys holdings by performing certain exploratory work (farm-out)
and whereby the company may earn interests in others holdings by performing certain
exploratory work (farm-in). |
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 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 heavy oil net exploratory and development
wells that were drilled or participated in by the company during the five years ended December 31,
2007.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
Western and Atlantic Provinces: |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploratory |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Gas |
|
|
|
|
|
|
1 |
|
|
|
|
|
|
|
2 |
|
|
|
3 |
|
Dry Holes |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1 |
|
|
|
1 |
|
Development |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
|
|
|
|
|
|
|
|
2 |
|
|
|
3 |
|
|
|
4 |
|
Gas |
|
|
183 |
|
|
|
192 |
|
|
|
155 |
|
|
|
207 |
|
|
|
89 |
|
Dry Holes |
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
1 |
|
|
|
3 |
|
Heavy Oil (Cold Lake and other) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Development |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Oil |
|
|
188 |
|
|
|
174 |
|
|
|
87 |
|
|
|
218 |
|
|
|
118 |
|
|
|
|
Total |
|
|
371 |
|
|
|
368 |
|
|
|
245 |
|
|
|
432 |
|
|
|
218 |
|
|
|
|
In 2007, 188 heavy oil development wells were drilled to add new productive capacity from
undeveloped areas of existing phases at Cold Lake. In addition, 183 gas development wells were
drilled in 2007 adding productivity primarily in the shallow gas area. Increased shallow gas
development drilling accounted for the increase in gas
9
well count in 2004. Weather related delays in 2005 resulted in a reduction in the number of
wells drilled in the ongoing shallow gas development program.
At December 31, 2007, the company was participating in the drilling of 183 gross (123 net)
exploratory and development wells.
Western Provinces
In 2007, the company had a working interest in 489 gross (371 net) development wells.
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, anchored by three large onshore natural gas fields.
The company retains a 100 percent interest in the largest of these fields.
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 framework, and the cost of constructing, operating
and abandoning the field production and pipeline facilities.
In October 2004, the company and its co-venturers filed regulatory applications and
environmental impact statements for the project with the National Energy Board (NEB) and other
boards, panels and agencies responsible for assessing and regulating energy developments in the
Northwest Territories. All the scheduled public hearings by the Joint Review Panel (JRP) and the
NEB were concluded in late 2007. The regulatory process continues with a JRP report expected in
2008 followed by an NEB decision in early 2009.
In 2007, the company acquired a 50 percent interest in an exploration licence for about
507,000 gross acres in the Beaufort Sea. As part of the evaluation, a 3-D seismic program is being
planned.
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 six production licences, managed by others.
The company retains a 20 percent interest in one exploration licence for about 52,000 gross
acres acquired in 1999 in the Sable Island area. One exploratory well was completed on this licence
without commercial success. In 2007, one exploration licence in which the company had a 20 percent
interest for about 58,000 gross acres in the Sable Island area was allowed to expire.
Also, the company retains a 70 percent interest in one exploration licence for about 279,000
gross acres farther offshore in deeper water. In 2003, one exploratory well was drilled on this
licence, without commercial success. The company is not planning further exploration in these
areas.
In early 2004, the company acquired a 25 percent interest in eight deep water exploration
licences offshore Newfoundland in the Orphan Basin for about 5,251,000 gross acres. In February
2005, the company reduced its interest to 15 percent through an agreement with another company. The
companys share of proposed exploration spending is about $100 million with a minimum commitment of
about $25 million. In 2004 and 2005, the company participated in 3-D seismic surveys in this area.
Drilling of an exploration well was concluded in early 2007. Additional drilling is planned.
The company retains 100 percent interest in a single exploration licence for about 474,000
gross acres in the Laurentian basin area offshore Newfoundland and Labrador.
10
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 renewable contracts with 30 to 60 day
cancellation terms.
Crude oil from foreign sources is purchased by the company at market 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 2007, capital expenditures of about $110 million were made at the companys refineries.
About 50 percent of those expenditures were on environmental and safety initiatives with the
remaining expenditures being primarily on capacity and efficiency improvements.
The approximate average daily volumes of refinery throughput during the five years ended
December 31, 2007, and the daily rated capacities of the refineries at December 31, 2002 and 2007,
were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Average Daily Volumes of |
|
|
Daily Rated |
|
|
|
Refinery Throughput (1) |
|
|
Capacities at |
|
|
|
Year Ended December 31 |
|
|
December 31 (2) |
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
2007 |
|
|
2002 |
|
|
|
(thousands of barrels) |
|
|
|
|
|
|
|
|
|
Strathcona, Alberta |
|
|
170 |
|
|
|
160 |
|
|
|
174 |
|
|
|
170 |
|
|
|
174 |
|
|
|
187 |
|
|
|
184 |
|
Sarnia, Ontario |
|
|
103 |
|
|
|
111 |
|
|
|
106 |
|
|
|
108 |
|
|
|
92 |
|
|
|
121 |
|
|
|
121 |
|
Dartmouth, Nova Scotia |
|
|
69 |
|
|
|
77 |
|
|
|
79 |
|
|
|
80 |
|
|
|
82 |
|
|
|
82 |
|
|
|
82 |
|
Nanticoke, Ontario |
|
|
100 |
|
|
|
94 |
|
|
|
108 |
|
|
|
109 |
|
|
|
102 |
|
|
|
112 |
|
|
|
112 |
|
|
|
|
|
|
Total |
|
|
442 |
|
|
|
442 |
|
|
|
466 |
|
|
|
467 |
|
|
|
450 |
|
|
|
502 |
|
|
|
499 |
|
|
|
|
|
|
|
|
|
(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 88 percent of capacity in 2007, the same as the previous year but
lower than 2005 due to planned and unplanned downtime of crude processing facilities.
Distribution
The company maintains a nation-wide distribution system, including 27 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.
Marketing
The company markets more than 700 petroleum products throughout Canada under well known brand
names, most notably Esso and Mobil, to all types of customers.
The company sells to the motoring public through Esso service stations. On average during the
year, there were about 1,930 sites of which about 600 were company owned or leased, but none of
which were company operated. The company continues to improve its Esso service station 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. Heating oil is provided through authorized dealers as well as through two
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.
11
The approximate daily volumes of net petroleum products (excluding purchases/sales contracts
with the same counterparty) sold during the five years ended December 31, 2007, are set out in the
following table:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(thousands of cubic metres a day) |
|
|
Gasolines |
|
|
33.1 |
|
|
|
32.7 |
|
|
|
33.4 |
|
|
|
33.2 |
|
|
|
33.0 |
|
Heating, Diesel and Jet Fuels |
|
|
26.0 |
|
|
|
26.4 |
|
|
|
26.9 |
|
|
|
27.3 |
|
|
|
26.2 |
|
Heavy Fuel Oils |
|
|
5.2 |
|
|
|
5.1 |
|
|
|
6.0 |
|
|
|
5.9 |
|
|
|
5.4 |
|
Lube Oils and Other Products |
|
|
6.9 |
|
|
|
7.7 |
|
|
|
7.6 |
|
|
|
7.0 |
|
|
|
5.8 |
|
|
|
|
Net petroleum product sales |
|
|
71.2 |
|
|
|
71.9 |
|
|
|
73.9 |
|
|
|
73.4 |
|
|
|
70.4 |
|
|
|
|
The total domestic sales of petroleum products as a percentage of total sales of petroleum
products during the five years ended December 31, 2007, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
|
94.8 |
% |
|
|
95.1 |
% |
|
|
95.3 |
% |
|
|
93.0 |
% |
|
|
93.3 |
% |
The company continues to evaluate and adjust its Esso service station and distribution system
to increase productivity and efficiency. During 2007, the company closed or debranded about 80 Esso
service stations, about 30 of which were company owned, and added about 50 sites. The companys
average annual throughput in 2007 per Esso service station was 3.8 million litres, an increase of
about 0.2 million litres from 2006. Average throughput per company owned or leased Esso service
station was 6.5 million litres in 2007, an increase of about 0.4 million litres from 2006.
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,
2007, were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2004 |
|
|
2003 |
|
|
|
(thousands of tonnes a day) |
|
|
Petrochemicals |
|
|
3.1 |
|
|
|
3.0 |
|
|
|
3.0 |
|
|
|
3.3 |
|
|
|
3.3 |
|
Research
In 2007, the companys research expenditures in Canada, before deduction of investment tax
credits, were $83 million, as compared with $56 million in 2006, and $50 million in 2005. Those
funds were used mainly for developing improved heavy oil and oil sands 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 2007. The company also participated in heavy oil recovery and processing research for oil 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 and fuels. About 115 people were employed in this type of research
and advanced technical support at the end of 2007. Also in Sarnia, there are about 10 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 made capital expenditures of about $1.0 billion on
environmental protection and facilities. The environmental expenditures over the past five years
primarily reflect spending on two major projects. One project completed in
12
2004, costing about $650 million, reduced sulphur in motor gasolines, meeting a requirement of
the Government of Canada. The second project completed in 2006 was to meet a new Government of
Canada regulation requiring ultra-low sulphur on-road diesel fuel which cost about $500 million in
total. In 2007, the companys capital expenditures relating to environmental protection totaled
approximately $135 million which was spent primarily on emissions reductions at Syncrude and
company owned facilities as well as on ultra-low sulphur off-road diesel fuel. Capital
expenditures relating to environmental protection are expected to be about $200 million in 2008.
Human Resources
At December 31, 2007, the company employed full-time approximately 4,800 persons compared with
about 4,900 at the end of 2006 and 5,100 at the end of 2005. About 10 percent of the companys
employees are members of unions. The company continues to maintain a broad range of benefits,
including health, dental, disability and survivor benefits, vacation, savings plan and pension
plan.
Competition
The Canadian petroleum, natural gas and chemical industries are highly competitive.
Competition exists in the search for and development of new sources of supply, the construction and
operation of crude oil, natural gas and refined products pipelines and facilities 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.
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 and/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 NEB and the
Government of Canada.
Natural Gas
Production
The maximum allowable gross production of natural gas from wells in Canada is subject to
limitations by various regulatory authorities. These limitations are to ensure oil recovery is not
adversely impacted by accelerated gas production practices. These limitations do not impact gas
reserves, only the timing of production of the reserves, and did not have a significant impact on
2007 gas production rates. As well, these limitations do not apply to gas fields where there are no
associated oil reserves.
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
13
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. The
acquisition of natural resource properties may, in certain circumstances, be considered to be a
transaction that constitutes an acquisition of control of a Canadian business requiring Government
of Canada approval.
The Act also 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 is 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.
Item 1A. Risk Factors.
Volatility of Oil and Natural Gas Prices
The companys results of operations and financial condition are dependent on the prices it
receives for its oil and natural gas production. Crude oil and natural gas prices are determined by
global and North American markets and are subject to changing supply and demand conditions. These
can be influenced by a wide range of factors including economic conditions, international political
developments and weather. In the past, crude oil and natural gas prices have been volatile, and the
company expects that volatility to continue. Any material decline in oil or natural gas prices
could have a material adverse effect on the companys operations, financial condition, proven
reserves and the amount spent to develop oil and natural gas reserves.
A significant portion of the companys production is heavy oil. The market prices for heavy
oil differ from the established market indices for light and medium grades of oil principally due
to the higher transportation and refining costs associated with heavy oil and limited refining
capacity capable of processing heavy oil. As a result, the price received for heavy oil is
generally lower than the price for medium and light oil. Future differentials are uncertain and
increases in the heavy oil differentials could have a material adverse effect on the companys
business.
The company does not use derivative markets to hedge or sell forward any part of production
from any business segment.
Competitive Factors
The oil and gas industry is highly competitive, particularly in the following areas: searching
for and developing new sources of supply; constructing and operating crude oil, natural gas and
refined products pipelines and facilities; and the refining, distribution and marketing of
petroleum products and chemicals. The companys competitors include major integrated oil and gas
companies and numerous other independent oil and gas companies. The petroleum industry also
competes with other industries in supplying energy, fuel and related products to customers.
Competitive forces may result in shortages of prospects to drill, services to carry out
exploration, development or operating activities and infrastructure to produce and transport
production. It may also result in an oversupply of crude oil, natural gas, petroleum products and
chemicals. Each of these factors could have a negative impact on costs and prices and, therefore,
the companys financial results.
Environmental Risks
All phases of the upstream, downstream and chemicals businesses are subject to environmental
regulation pursuant to a variety of Canadian federal, provincial and municipal laws and
regulations, as well as international conventions (collectively, environmental legislation).
Environmental legislation imposes, among other things, restrictions, liabilities and
obligations in connection with the generation, handling, storage, transportation, treatment and
disposal of hazardous substances and waste and in connection with spills, releases and emissions of
various substances to the environment. As well, environmental regulations are imposed on the
qualities and compositions of the products sold and imported. Environmental legislation also
requires that wells, facility sites and other properties associated with the companys operations
be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory
authorities. In addition, certain types of operations, including exploration and development
projects and significant
14
changes to certain existing projects, may require the submission and approval of environmental
impact assessments. Compliance with environmental legislation can require significant expenditures
and failure to comply with environmental legislation may result in the imposition of fines and
penalties and liability for clean up costs and damages. The company cannot assure that the costs of
complying with environmental legislation in the future will not have a material adverse effect on
its financial condition or results of operations. The company anticipates that changes in
environmental legislation may require, among other things, reductions in emissions to the air from
its operations and result in increased capital expenditures. Future changes in environmental
legislation could occur and result in stricter standards and enforcement, larger fines and
liability, and increased capital expenditures and operating costs, which could have a material
adverse effect on the companys financial condition or results of operations.
Climate Change
In April 2007, the Government of Canada announced its intent to introduce a set of regulations
to limit emissions of greenhouse gas and air pollutants from major industrial facilities in Canada
beginning in 2010, although the details of the regulations have not been finalized. Consequently,
attempts to assess the impact on the company are premature. The company will continue to monitor
the development of legal requirements in this area.
In the Province of Alberta, regulations governing greenhouse gas emissions from large
industrial facilities came into effect July 1, 2007. The company does not expect ongoing compliance
costs to have a material adverse effect on the companys operations or financial condition.
The recently enacted U.S. Energy Independence and Security Act of 2007 precludes agencies of
the U.S. federal government from procuring motive fuels from non-conventional petroleum sources
that have lifecycle greenhouse gas emissions greater than equivalent conventional fuel. This may
have implications for the companys marketing in the United States of some heavy oil and oil sands
production, but the impact cannot be determined at this time.
Other Regulatory Risk
The company is subject to a wide range of legislation and regulation governing its operations
over which it has no control. Changes may affect every aspect of the companys operations and
financial performance.
Need to Replace Reserves
The companys future conventional oil, heavy oil and natural gas reserves and production, and
therefore cash flows, are highly dependent upon the companys success in exploiting its current
reserve base and acquiring or discovering additional reserves. Without additions to the companys
reserves through exploration, acquisition or development activities, reserves and production will
decline over time as reserves are depleted. The business of exploring for, developing or acquiring
reserves is capital intensive. To the extent cash flows from operations are insufficient to fund
capital expenditures and external sources of capital become limited or unavailable, the companys
ability to make the necessary capital investments to maintain and expand oil and natural gas
reserves will be impaired. In addition, the company may be unable to find and develop or acquire
additional reserves to replace oil and natural gas production at acceptable costs.
Other Business Risks
Exploring for, producing and transporting petroleum substances involve many risks, which even
a combination of experience, knowledge and careful evaluation may not be able to mitigate. These
activities are subject to a number of hazards which may result in fires, explosions, spills,
blow-outs or other unexpected or dangerous conditions causing personal injury, property damage,
environmental damage and interruption of operations. The companys insurance may not provide
adequate coverage in certain unforeseen circumstances.
Uncertainty of Reserve Estimates
There are numerous uncertainties inherent in estimating quantities of reserves, including many
factors beyond the companys control. In general, estimates of economically recoverable oil and
natural gas reserves and the future net cash flow therefrom are based upon a number of factors and
assumptions made as of the date on which the reserve estimates were determined, such as geological
and engineering estimates which have inherent uncertainties, the assumed effects of regulation by
governmental agencies and future commodity prices and operating costs, all of which may vary
considerably from actual results. All such estimates are, to some degree, uncertain and
classifications of reserves are only attempts to define the degree of uncertainty involved. For
these reasons, estimates of the economically recoverable oil and natural gas reserves, the
classification of such reserves based on risk of recovery and estimates of future net revenues
expected therefrom, prepared by different engineers or by the same engineers at different times,
may vary substantially. Actual production, revenues, taxes and development, abandonment and
operating expenditures with respect to its reserves will likely vary from such estimates, and such
variances could be material.
15
Estimates with respect to reserves that may be developed and produced in the future are often
based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon
actual production history. Estimates based on these methods generally are less reliable than those
based on actual production history. Subsequent evaluation of the same reserves based upon
production history will result in variations, which may be material, in the estimated reserves.
Project Factors
The companys results depend on its ability to develop and operate major projects and
facilities as planned. The companys results will, therefore, be affected by events or conditions
that affect the advancement, operation, cost or results of such projects or facilities. These risks
include the companys ability to obtain the necessary environmental and other regulatory approvals;
changes in resources and operating costs including the availability and cost of materials,
equipment and qualified personnel; the impact of general economic, business and market conditions;
and the occurrence of unforeseen technical difficulties.
Market Risk Factors
See Item 7A for a discussion of the impact of market risks and other uncertainties.
Item 1B Unresolved Staff Comments.
Not applicable.
Item 2. Properties.
Reference is made to Item 1 above, and for the reserves of the Syncrude mining operations and
oil and gas producing activities, 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.
16
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.
Imperial Oil Limited is a qualified foreign corporation for purposes of the reduced U.S.
capital gains tax rates (15 percent and 5 percent 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
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
2006 |
|
|
three months ended |
|
|
|
three months ended |
|
|
Mar. 31 |
|
|
Jun. 30 |
|
|
Sep. 30 |
|
|
Dec. 31 |
|
|
Mar. 31 |
|
Jun. 30 |
Sep. 30 |
Dec. 31 |
|
|
|
Financial data |
|
(millions of dollars)
|
|
(millions of dollars)
|
Total revenues and other income |
|
|
5,934 |
|
|
|
6,339 |
|
|
|
6,430 |
|
|
|
6,740 |
|
|
|
5,818 |
|
|
|
6,688 |
|
|
|
6,651 |
|
|
|
5,631 |
|
Total expenses |
|
|
4,819 |
|
|
|
5,319 |
|
|
|
5,240 |
|
|
|
5,686 |
|
|
|
4,928 |
|
|
|
5,604 |
|
|
|
5,421 |
|
|
|
4,735 |
|
|
|
|
Income before income taxes |
|
|
1,115 |
|
|
|
1,020 |
|
|
|
1,190 |
|
|
|
1,054 |
|
|
|
890 |
|
|
|
1,084 |
|
|
|
1,230 |
|
|
|
896 |
|
Income taxes |
|
|
(341 |
) |
|
|
(308 |
) |
|
|
(374 |
) |
|
|
(168 |
) |
|
|
(299) |
|
|
|
(247) |
|
|
|
(408) |
|
|
|
(102) |
|
|
|
|
Net income |
|
|
774 |
|
|
|
712 |
|
|
|
816 |
|
|
|
886 |
|
|
|
591 |
|
|
|
837 |
|
|
|
822 |
|
|
|
794 |
|
|
|
|
Per-share information (a) |
|
(dollars)
|
|
(dollars)
|
Net earnings basic |
|
|
0.82 |
|
|
|
0.76 |
|
|
|
0.88 |
|
|
|
0.97 |
|
|
|
0.60 |
|
|
|
0.85 |
|
|
|
0.84 |
|
|
|
0.83 |
|
Net earnings diluted |
|
|
0.81 |
|
|
|
0.76 |
|
|
|
0.88 |
|
|
|
0.96 |
|
|
|
0.59 |
|
|
|
0.85 |
|
|
|
0.84 |
|
|
|
0.83 |
|
Dividends (declared quarterly) |
|
|
0.08 |
|
|
|
0.09 |
|
|
|
0.09 |
|
|
|
0.09 |
|
|
|
0.08 |
|
|
|
0.08 |
|
|
|
0.08 |
|
|
|
0.08 |
|
Share prices (a) |
|
(dollars)
|
|
(dollars)
|
Toronto Stock Exchange |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
High |
|
|
43.75 |
|
|
|
54.70 |
|
|
|
51.90 |
|
|
|
56.26 |
|
|
|
42.28 |
|
|
|
43.33 |
|
|
|
45.20 |
|
|
|
44.80 |
|
Low |
|
|
37.40 |
|
|
|
41.77 |
|
|
|
40.86 |
|
|
|
45.57 |
|
|
|
35.36 |
|
|
|
36.18 |
|
|
|
35.33 |
|
|
|
34.31 |
|
Close |
|
|
42.80 |
|
|
|
49.59 |
|
|
|
49.29 |
|
|
|
54.26 |
|
|
|
41.91 |
|
|
|
40.78 |
|
|
|
37.47 |
|
|
|
42.93 |
|
American
Stock Exchange |
|
($U.S.)
|
|
($U.S.)
|
High |
|
|
38.29 |
|
|
|
50.35 |
|
|
|
50.95 |
|
|
|
61.48 |
|
|
|
36.67 |
|
|
|
39.64 |
|
|
|
40.38 |
|
|
|
38.93 |
|
Low |
|
|
31.87 |
|
|
|
36.90 |
|
|
|
37.99 |
|
|
|
46.43 |
|
|
|
30.54 |
|
|
|
32.50 |
|
|
|
31.64 |
|
|
|
29.99 |
|
Close |
|
|
37.12 |
|
|
|
46.34 |
|
|
|
49.56 |
|
|
|
54.78 |
|
|
|
35.85 |
|
|
|
36.50 |
|
|
|
33.55 |
|
|
|
36.83 |
|
|
|
|
(a) |
|
Adjusted to reflect the May 2006 three-for-one share split. |
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 adjusted for the
three-for-one share split.
As of February 14, 2008 there were 13,175 holders of record of common shares of the company.
During the period October 1, 2007 to December 31, 2007, the company issued 164,805 common
shares for $15.50 per share (following the three-for-one share split) as a result of the exercise
of stock options by the holders of the stock options, who are all employees or former employees of
the company, in transactions outside the U.S.A. which were not registered under the Securities Act
in reliance on Regulation S thereunder.
17
Issuer purchases of equity securities (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Period |
|
|
(a) Total number |
|
|
(b) Average price |
|
|
(c) Total number of |
|
|
(d) Maximum number |
|
|
|
|
|
of shares |
|
|
paid per share |
|
|
shares purchased as |
|
|
(or approximate dollar value) |
|
|
|
|
|
(or units) |
|
|
(or unit) |
|
|
part of publicly |
|
|
of shares that may yet be |
|
|
|
|
|
purchased |
|
|
|
|
|
|
|
announced plans or |
|
|
purchased under the plans or |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
programs |
|
|
programs |
|
|
October 2007
(October 1 - October 31) |
|
|
|
1,498,890 |
|
|
|
$ |
48.00 |
|
|
|
|
1,498,890 |
|
|
|
|
30,445,586 |
|
|
|
November 2007
(November 1 - November 30) |
|
|
|
6,656,699 |
|
|
|
$ |
51.45 |
|
|
|
|
6,656,699 |
|
|
|
|
23,737,240 |
|
|
|
December 2007
(December 1 - December 31) |
|
|
|
2,971,920 |
|
|
|
$ |
51.70 |
|
|
|
|
2,971,920 |
|
|
|
|
20,714,852 |
|
|
|
|
|
|
(1) |
|
The purchases were pursuant to a 12 month normal course share purchase program that was
renewed on June 25, 2007 under which the company may purchase up to 46,459,967 of its
outstanding common shares less any shares purchased by the employee savings plan and the
company pension fund. If not previously terminated, the program will terminate on June 24,
2008. |
Item 6. Selected Financial Data.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(millions of dollars) |
Total operating revenues (a) |
|
|
25,069 |
|
|
|
24,505 |
|
|
|
27,797 |
|
|
|
22,408 |
|
|
|
19,094 |
|
Net income |
|
|
3,188 |
|
|
|
3,044 |
|
|
|
2,600 |
|
|
|
2,052 |
|
|
|
1,705 |
|
Total assets |
|
|
16,287 |
|
|
|
16,141 |
|
|
|
15,582 |
|
|
|
14,027 |
|
|
|
12,337 |
|
Long term debt |
|
|
38 |
|
|
|
359 |
|
|
|
863 |
|
|
|
367 |
|
|
|
859 |
|
Other long term obligations |
|
|
1,914 |
|
|
|
1,683 |
|
|
|
1,728 |
|
|
|
1,525 |
|
|
|
1,314 |
|
|
|
(dollars)
|
Net income/share basic (b) |
|
|
3.43 |
|
|
|
3.12 |
|
|
|
2.54 |
|
|
|
1.92 |
|
|
|
1.53 |
|
Net income/share diluted (b) |
|
|
3.41 |
|
|
|
3.11 |
|
|
|
2.53 |
|
|
|
1.91 |
|
|
|
1.53 |
|
Cash dividends/share (b) |
|
|
0.35 |
|
|
|
0.32 |
|
|
|
0.31 |
|
|
|
0.29 |
|
|
|
0.29 |
|
|
|
|
(a) |
|
Total operating revenues include $4,894 million for 2005, $3,584 million for 2004, and
$2,851 million for 2003 for purchases/sales contracts with the same counterparty.
Associated costs were included in purchases of crude oil and products. Effective January
1, 2006, these purchases/sales were recorded on a net basis. See note 1 (page F-7),
Summary of Significant Accounting Policies. |
|
(b) |
|
Adjusted to reflect the three-for-one share split. |
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.
Item 7. Managements Discussion and Analysis of Financial Condition and Results of Operations.
Overview
The following discussion and analysis of Imperials financial results, as well as the
accompanying financial statements and related notes to consolidated financial statements to which
they refer, are the responsibility of the management of Imperial Oil Limited.
The companys accounting and financial reporting fairly reflect its straightforward business
model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based
products. The companys business involves the production (or purchase), manufacture and sale of
physical products, and all commercial activities are directly in support of the underlying physical
movement of goods.
Imperial, with its resource base, financial strength, disciplined investment approach and
technology portfolio, is well-positioned to participate in substantial investments to develop new
Canadian energy supplies. While commodity prices remain volatile on a short-term basis depending
upon supply and demand, Imperials investment decisions are based on its long-term business
outlook, using a disciplined approach in selecting and pursuing the most attractive investment
opportunities. The corporate plan is a fundamental annual management process that is the basis for
setting near-term operating and capital objectives, in addition to providing the longer-term
economic assumptions used for investment evaluation purposes. Potential investment opportunities
are tested over a wide range of economic scenarios to establish the resiliency of each opportunity.
Once investments are made, a reappraisal process is completed to ensure relevant lessons are
learned and improvements are incorporated into future projects.
18
Business environment and risk assessment
Long-term business outlook
Economic and population growth are expected to remain the primary drivers of energy demand,
globally and in North America. The company expects the global economy to grow at an average rate of
about three percent per year through 2030. The combination of population and economic growth should
lead to an increase in demand for primary energy at an average rate of 1.3 percent annually. The
vast majority of this increase is expected to occur in developing countries.
Oil, gas and coal are expected to remain the predominant energy sources with approximately an
80 percent share of total energy. Oil and gas alone are expected to maintain close to a 60 percent
share.
Over the same period, the Canadian economy is expected to grow at an average rate of about two
percent per year, and Canadian demand for energy at less than one percent per year. Oil and gas are
expected to continue to supply about two-thirds of Canadian energy demand. It is expected that
Canada will also be a growing supplier of energy to U.S. markets through this period.
Oil products are the transportation fuel of choice for the worlds fleet of cars, trucks,
trains, ships and airplanes. Primarily because of increased demand in developing countries, oil
consumption will increase by about 35 percent or about 30 million barrels a day by 2030. Canadas
resources of heavy oil and oil sands represent an important additional source of supply.
Natural gas is expected to be a major primary energy source globally, capturing about 30
percent of all incremental energy growth and approaching one-quarter of global energy supplies.
Natural gas production from mature established regions in the United States and Canada is not
expected to meet increasing demand, strengthening the market opportunities for new gas supply from
Canadas frontier areas.
Natural resources
Imperial produces crude oil and natural gas for sale into large North American markets. Crude
oil and natural gas prices are determined by global and North American markets and are subject to
changing supply and demand conditions. These can be influenced by a wide range of factors,
including economic conditions, international political developments and weather. In the past, crude
oil and natural gas prices have been volatile, and the company expects that volatility to continue.
Imperial has a large and diverse portfolio of oil and gas resources in Canada, both developed
and undeveloped, which helps reduce the risks of dependence on potentially limited supply sources
in the upstream. With the relative maturity of conventional production in the established producing
areas of Western Canada, Imperials production is expected to come increasingly from frontier and
unconventional sources, particularly heavy oil, oil sands and natural gas from Canadas North,
where Imperial has large undeveloped resource opportunities.
Petroleum products
The downstream industry environment remains very competitive. Refining margins are the
difference between what a refinery pays for its raw materials (primarily crude oil) and the
wholesale market prices for the range of products produced (primarily gasoline, diesel fuel,
heating oil, jet fuel and heavy fuel oil). While refining margins have been strong over the last
few years, real inflation adjusted refining margins have declined at a rate of about one percent
per year over the past 20 years. Intense competition in the retail fuels market similarly has
driven down real margins. Crude oil and many products are widely traded with published
international prices. Prices for those commodities are determined by the marketplace, often an
international marketplace, and are affected by many factors, including global and regional
supply/demand balances, inventory levels, refinery operations, import/export balances,
transportation logistics, seasonality and weather.
Canadian wholesale prices in particular are largely determined by wholesale prices in adjacent
U.S. regions. These prices and factors are continually monitored and provide input to operating
decisions about which raw materials to buy, facilities to operate and products to make. However,
there are no reliable indicators of future market factors that accurately predict changes in
margins from period to period.
Imperials downstream strategies are to provide customers with quality service at the lowest
total cost offer, have the lowest unit costs among our competitors, ensure efficient and effective
use of capital and capitalize on integration with the companys other businesses. Imperial owns and
operates four refineries in Canada, with distillation capacity of 502,000 barrels a day and
lubricant manufacturing capacity of 9,000 barrels a day.
Imperials fuels marketing business includes retail operations across Canada serving customers
through more than 1,900 Esso-branded service stations, of which about 600 are company-owned or
leased, and wholesale and industrial operations through a network of 27 primary distribution
terminals, as well as a secondary distribution network.
Chemicals
The North American petrochemical industry is cyclical. The companys strategy for its
chemicals business is to reduce costs and maximize value by continuing to increase the integration
of its chemicals plants at Sarnia and
19
Dartmouth with the refineries. The company also benefits from its integration within
ExxonMobils North American chemicals businesses, enabling Imperial to maintain a leadership
position in its key market segments.
Results of operations
Net income in 2007 of $3,188 million or $3.41 a share on a diluted basis was the best on
record, exceeding the previous record achieved in 2006 of $3,044 million or $3.11 a share. Earnings
increased primarily due to higher crude oil commodity prices, stronger industry refining and
marketing margins, favourable refinery operations and higher Syncrude volumes. Gains from asset
divestments were also higher in 2007. These factors were partially offset by lower expected
conventional resources volumes, the negative impact of a stronger Canadian dollar, higher
exploration and share-based compensation expenses and higher tax expense.
Natural resources
Net income from natural resources was $2,369 million versus $2,376 million in 2006. Earnings
benefited from higher crude oil commodity prices totaling about $325 million and higher Syncrude
volumes of about $125 million. Higher gains from asset divestments of about $65 million also
contributed to higher earnings. Offsetting these positive factors were lower natural gas,
conventional crude oil, and natural gas liquids (NGLs) volumes totaling about $285 million, the
negative impact of a stronger Canadian dollar of about $175 million and higher exploration and
other operating expenses of about $75 million.
Financial statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(millions of dollars) |
Net income |
|
|
2,369 |
|
|
|
2,376 |
|
|
|
2,008 |
|
|
|
1,517 |
|
|
|
1,174 |
|
Operating revenues |
|
|
8,685 |
|
|
|
8,456 |
|
|
|
8,189 |
|
|
|
6,580 |
|
|
|
5,584 |
|
World crude oil prices, denominated in U.S. dollars, were higher in 2007 than in the previous
year. The annual average price of Brent crude oil, the most actively traded North Sea crude and a
common benchmark of world oil markets, was about $72 (U.S.) a barrel in 2007, about 11 percent
higher than the average price of $65 in 2006 (2005 $55). However, the companys Canadian-dollar
realizations for conventional crude oil increased to a lesser extent because of a stronger Canadian
dollar. Average realizations for conventional crude oil during the year were $71.70 (Cdn) a barrel,
an increase of less than five percent from $68.58 in 2006 (2005 $64.48).
Average realizations for Cold Lake heavy oil in U.S. dollars were about five percent higher
for the year. Also mainly because of a stronger Canadian dollar, the companys average realizations
for Cold Lake heavy oil were lower by about two percent in 2007.
Prices for Canadian natural gas in 2007 were lower than in the previous year. The average of
30-day spot prices for natural gas in Alberta was about $7.01 a thousand cubic feet in 2007,
compared with $7.41 in 2006 (2005 $9.01). The companys average realizations on natural gas sales
were $6.95 a thousand cubic feet, compared with $7.24 in 2006 (2005 $9.00).
Average realizations and prices
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(Canadian dollars) |
Conventional crude oil realizations (a barrel) |
|
|
71.70 |
|
|
|
68.58 |
|
|
|
64.48 |
|
|
|
48.96 |
|
|
|
40.10 |
|
Natural gas liquids realizations (a barrel) |
|
|
47.92 |
|
|
|
40.75 |
|
|
|
40.00 |
|
|
|
33.78 |
|
|
|
32.09 |
|
Natural gas realizations (a thousand cubic feet) |
|
|
6.95 |
|
|
|
7.24 |
|
|
|
9.00 |
|
|
|
6.78 |
|
|
|
6.60 |
|
Par crude oil price at Edmonton (a barrel) |
|
|
77.67 |
|
|
|
73.75 |
|
|
|
69.86 |
|
|
|
53.26 |
|
|
|
43.93 |
|
Heavy oil price at Hardisty (Bow River, a barrel) |
|
|
53.87 |
|
|
|
51.90 |
|
|
|
45.62 |
|
|
|
37.98 |
|
|
|
33.00 |
|
Total gross production of crude oil and NGLs averaged 275,000 barrels a day, compared with
272,000 barrels in 2006 (2005 261,000).
Gross production of heavy oil at the companys wholly owned facilities at Cold Lake was a
record 154,000 barrels a day, surpassing the previous record of 152,000 barrels in 2006 (2005
139,000). Increased production was due to the cyclic nature of production at Cold Lake and
increased volumes from the ongoing development drilling program.
Production from the Syncrude oil sands operation, in which the company has a 25 percent
interest, was higher during 2007 with increased volumes from the Stage 3 upgrader expansion. Gross
production of synthetic crude oil increased to 305,000 barrels a day from 258,000 barrels in 2006
(2005 214,000). Imperials share of average gross production increased to 76,000 barrels a day
from 65,000 barrels in 2006 (2005 53,000).
Gross production of conventional oil decreased to 29,000 barrels a day from 31,000 barrels in
2006 (2005 38,000) as a result of natural decline in Western Canadian reservoirs and the impact
of divested properties.
Gross production of NGLs available for sale averaged 16,000 barrels a day in 2007, down from
24,000 barrels in 2006 (2005 31,000), mainly due to the declining NGL content of Wizard Lake gas
production.
20
Gross production of natural gas decreased to 458 million cubic feet a day from 556 million in
2006 (2005 580 million). Lower production volumes were primarily due to decline, as expected, in
production from the gas cap at Wizard Lake.
In 2007, the company realized a gain of $142 million primarily from the sale of the companys interests
in several producing properties. Production of the companys share of these properties averaged
about 2,000 oil-equivalent barrels a day in 2006. In 2006, the gain on divestment of assets was
approximately $76 million (2005 $208 million).
Crude oil and NGLs production and sales (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
gross |
|
net |
|
gross |
|
net |
|
gross |
|
net |
|
gross |
|
net |
|
gross |
|
net |
|
|
(thousands of barrels a day) |
Cold Lake |
|
|
154 |
|
|
|
130 |
|
|
|
152 |
|
|
|
127 |
|
|
|
139 |
|
|
|
124 |
|
|
|
126 |
|
|
|
112 |
|
|
|
129 |
|
|
|
116 |
|
Syncrude |
|
|
76 |
|
|
|
65 |
|
|
|
65 |
|
|
|
58 |
|
|
|
53 |
|
|
|
53 |
|
|
|
60 |
|
|
|
59 |
|
|
|
53 |
|
|
|
52 |
|
Conventional crude oil |
|
|
29 |
|
|
|
21 |
|
|
|
31 |
|
|
|
23 |
|
|
|
38 |
|
|
|
29 |
|
|
|
43 |
|
|
|
33 |
|
|
|
46 |
|
|
|
35 |
|
|
|
|
Total crude oil production |
|
|
259 |
|
|
|
216 |
|
|
|
248 |
|
|
|
208 |
|
|
|
230 |
|
|
|
206 |
|
|
|
229 |
|
|
|
204 |
|
|
|
228 |
|
|
|
203 |
|
NGLs available for sale |
|
|
16 |
|
|
|
12 |
|
|
|
24 |
|
|
|
19 |
|
|
|
31 |
|
|
|
25 |
|
|
|
33 |
|
|
|
26 |
|
|
|
28 |
|
|
|
22 |
|
|
|
|
Total crude oil and NGL production |
|
|
275 |
|
|
|
228 |
|
|
|
272 |
|
|
|
227 |
|
|
|
261 |
|
|
|
231 |
|
|
|
262 |
|
|
|
230 |
|
|
|
256 |
|
|
|
225 |
|
Cold Lake sales, including diluent (b) |
|
|
200 |
|
|
|
|
|
|
|
198 |
|
|
|
|
|
|
|
183 |
|
|
|
|
|
|
|
167 |
|
|
|
|
|
|
|
170 |
|
|
|
|
|
NGL sales |
|
|
20 |
|
|
|
|
|
|
|
29 |
|
|
|
|
|
|
|
39 |
|
|
|
|
|
|
|
42 |
|
|
|
|
|
|
|
39 |
|
|
|
|
|
Natural
gas production and sales (a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
gross |
|
net |
|
gross |
|
net |
|
gross |
|
net |
|
gross |
|
net |
|
gross |
|
net |
|
|
(millions of cubic feet a day) |
Production (c) |
|
|
458 |
|
|
|
404 |
|
|
|
556 |
|
|
|
496 |
|
|
|
580 |
|
|
|
514 |
|
|
|
569 |
|
|
|
518 |
|
|
|
513 |
|
|
|
457 |
|
Sales |
|
|
407 |
|
|
|
|
|
|
|
513 |
|
|
|
|
|
|
|
536 |
|
|
|
|
|
|
|
520 |
|
|
|
|
|
|
|
460 |
|
|
|
|
|
|
(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 share of mineral owners or governments or both. Net
production excludes those shares. |
|
|
(b) |
|
Diluent is natural gas condensate or other light hydrocarbons added to the Cold Lake
heavy oil to facilitate transportation to market by pipeline. |
|
|
(c) |
|
Production of natural gas includes amounts used for internal consumption with the
exception of the amounts reinjected. |
Operating costs increased by less than three percent in 2007. Higher exploration and other
operating costs were partially offset by lower depreciation expenses.
On May 1, 2007, the company confirmed and implemented a management services agreement with
Syncrude Canada Ltd., under which Syncrude will be provided operational, technical and business
management services from Imperial and Exxon Mobil Corporation.
Petroleum products
Net income from petroleum products was a record $921 million, $297 million higher than 2006.
Increased earnings were primarily due to improved refinery operations including lower refinery
maintenance and project activities which contributed about $205 million, and stronger industry
refining and marketing margins totaling about $190 million. These positive factors were partially
offset by the negative impact of a stronger Canadian dollar of about $60 million and the absence of
favourable tax effects of about $40 million.
Financial statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(millions of dollars) |
Net income |
|
|
921 |
|
|
|
624 |
|
|
|
694 |
|
|
|
556 |
|
|
|
462 |
|
Operating revenues (a) |
|
|
21,535 |
|
|
|
20,783 |
|
|
|
24,017 |
|
|
|
19,169 |
|
|
|
16,004 |
|
Sale of petroleum products
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(millions of litres a day (b)) |
Gasolines |
|
|
33.1 |
|
|
|
32.7 |
|
|
|
33.4 |
|
|
|
33.2 |
|
|
|
33.0 |
|
Heating, diesel and jet fuels |
|
|
26.0 |
|
|
|
26.4 |
|
|
|
26.9 |
|
|
|
27.3 |
|
|
|
26.2 |
|
Heavy fuel oils |
|
|
5.2 |
|
|
|
5.1 |
|
|
|
6.0 |
|
|
|
5.9 |
|
|
|
5.4 |
|
Lube oils and other products |
|
|
6.9 |
|
|
|
7.7 |
|
|
|
7.6 |
|
|
|
7.0 |
|
|
|
5.8 |
|
|
|
|
Net petroleum product sales |
|
|
71.2 |
|
|
|
71.9 |
|
|
|
73.9 |
|
|
|
73.4 |
|
|
|
70.4 |
|
|
|
|
Total domestic sales of petroleum products (percent) |
|
|
94.8 |
|
|
|
95.1 |
|
|
|
95.3 |
|
|
|
93.0 |
|
|
|
93.3 |
|
|
|
|
21
Refinery utilization
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(thousands of barrels a day (b)) |
Total refinery throughput (c) |
|
|
442 |
|
|
|
442 |
|
|
|
466 |
|
|
|
467 |
|
|
|
450 |
|
Refinery capacity at December 31 |
|
|
502 |
|
|
|
502 |
|
|
|
502 |
|
|
|
502 |
|
|
|
502 |
|
Utilization of total refinery capacity (percent) |
|
|
88 |
|
|
|
88 |
|
|
|
93 |
|
|
|
93 |
|
|
|
90 |
|
|
(a) |
|
Operating revenues in 2005 and prior years included amounts for purchases/sales with
the same counterparty. Associated costs were included in purchases of crude oil and
products. Effective January 1, 2006, these purchases/sales were recorded on a net basis.
See note 1, Summary of Significant Accounting Policies, on page F-7. |
|
|
(b) |
|
Volumes a day are calculated by dividing total volumes for the year by the number of
days in the year. |
|
|
(c) |
|
Crude oil and feedstocks sent directly to atmospheric distillation units.
|
One thousand litres are approximately 6.3 barrels.
Margins were stronger in the refining segment of the industry in 2007 compared with those in
2006, pushed up by increased demand for refined petroleum products that stemmed from generally
stronger global economic conditions. However, the effects of stronger industry margins were reduced
partially by a higher Canadian dollar. Marketing margins in 2007 were slightly higher than those in
2006.
Refinery throughput was 88 percent of capacity in 2007, unchanged from the previous year (2005
- 93 percent). Refinery throughput in 2007 and 2006 was lower than in 2005 due to planned and
unplanned downtime of crude processing facilities.
The companys total sales volumes, excluding those resulting from reciprocal supply agreements
with other companies, were 71.2 million litres a day, compared with 71.9 million litres in 2006
(2005 73.9 million). Lower refinery production was the main reason for the decline.
Operating costs in 2007 were lower than the previous year by about two percent, reflecting
lower maintenance and project related expenses.
Chemicals
Net income from chemicals operations was $97 million, compared with $143 million in 2006.
Lower earnings were primarily due to lower industry margins for polyethylene products partially
offset by the positive impact of lower tax rates. A stronger Canadian dollar also negatively
impacted earnings in 2007.
Financial statistics
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(millions of dollars) |
Net income |
|
|
97 |
|
|
|
143 |
|
|
|
121 |
|
|
|
109 |
|
|
|
44 |
|
Operating revenues |
|
|
1,635 |
|
|
|
1,704 |
|
|
|
1,665 |
|
|
|
1,509 |
|
|
|
1,232 |
|
Sales
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(thousands of tonnes a day (a)) |
Polymers and basic chemicals |
|
|
2.2 |
|
|
|
2.2 |
|
|
|
2.1 |
|
|
|
2.4 |
|
|
|
2.4 |
|
Intermediate and others |
|
|
0.9 |
|
|
|
0.8 |
|
|
|
0.9 |
|
|
|
0.9 |
|
|
|
0.9 |
|
|
|
|
Total chemicals |
|
|
3.1 |
|
|
|
3.0 |
|
|
|
3.0 |
|
|
|
3.3 |
|
|
|
3.3 |
|
|
|
|
|
(a) |
|
Calculated by dividing total volumes for the year by the number of days in the year. |
The average industry price of polyethylene was $1,666 a tonne in 2007, slightly lower than
$1,703 a tonne in 2006 (2005 $1,708).
Sales of chemicals were 3,100 tonnes a day, compared with 3,000 tonnes a day in 2006 (2005 -
3,000 tonnes) primarily due to higher volumes in intermediate chemical products.
Operating costs in the chemicals segment for 2007 were about three percent lower than in 2006,
reflecting lower direct operating expenses.
Corporate and other
Net income from corporate and other was negative $199 million, versus negative $99 million
last year. Unfavourable earnings effects were primarily due to higher share-based compensation
charges and the impact of tax rate changes.
22
Liquidity and capital resources
Sources and uses of cash
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
|
(millions of dollars) |
Cash provided by/(used in) |
|
|
|
|
|
|
|
|
Operating activities |
|
|
3,626 |
|
|
|
3,587 |
|
Investing activities |
|
|
(620) |
|
|
|
(965) |
|
Financing activities |
|
|
(3,956) |
|
|
|
(2,125) |
|
|
|
|
Increase/(decrease) in cash and cash equivalents |
|
|
(950) |
|
|
|
497 |
|
|
|
|
Cash and cash equivalents at end of year |
|
|
1,208 |
|
|
|
2,158 |
|
|
|
|
Although the company issues long-term debt from time to time and maintains a revolving
commercial paper program, internally generated funds cover the majority of its financial
requirements. The management of cash that may be temporarily available as surplus to the companys
immediate needs is carefully controlled, both to optimize returns on cash balances and to ensure
that it is secure and readily available to meet the companys cash requirements.
Cash flows from operating activities are highly dependent on crude oil and natural gas prices
and product margins. In addition, to support cash flows in future periods the company will need to
continually find and develop new fields, and continue to develop and apply new technologies and
recovery processes to existing fields, in order to maintain or increase production. Projects are in
place or underway to increase production capacity. However, these volume increases are subject to a
variety of risks, including project execution, operational outages, reservoir performance and
regulatory changes.
The companys financial strength enables it to make large, long-term capital expenditures.
Imperials large and diverse portfolio of development opportunities and the complementary nature of
its business segments help mitigate the overall risks of the company and associated cash flow.
Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the
risk associated with failure or delay of any single project would not have a significant impact on
the companys liquidity or ability to generate sufficient cash flows for its operations and fixed
commitments.
Cash flow from operating activities
Cash provided by operating activities was $3,626 million, versus $3,587 million in 2006 (2005
- $3,451 million). Higher cash flow in 2007 was primarily due to higher net income. Unfavourable
impact of the timing of income tax payments was largely offset by net effects of higher commodity
prices on working capital balances.
Cash flow from investing activities
Cash used in investing activities totaled $620 million in 2007, compared with $965 million in
2006 (2005 $992 million). Lower planned spending on property, plant and equipment and higher
proceeds from asset sales contributed to the change.
Capital and exploration expenditures
Total capital and exploration expenditures were $978 million in 2007, compared with $1,209
million in 2006 (2005 $1,475 million).
The funds were used mainly to invest in Cold Lake to maintain and expand production capacity,
advance upstream projects, invest in environmental initiatives, and upgrade the network of Esso
retail outlets. About $160 million was spent on projects related to reducing the environmental
impact of the companys operations and improving safety.
The following table shows the companys capital and exploration expenditures for natural
resources during the five years ending December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(millions of dollars) |
Heavy oil and oil sands |
|
|
489 |
|
|
|
518 |
|
|
|
662 |
|
|
|
819 |
|
|
|
769 |
|
Production |
|
|
150 |
|
|
|
237 |
|
|
|
232 |
|
|
|
234 |
|
|
|
181 |
|
Exploration |
|
|
105 |
|
|
|
32 |
|
|
|
43 |
|
|
|
60 |
|
|
|
57 |
|
|
|
|
Total capital and exploration expenditures |
|
|
744 |
|
|
|
787 |
|
|
|
937 |
|
|
|
1,113 |
|
|
|
1,007 |
|
|
|
|
For the natural resources segment, over 80 percent of the capital and exploration expenditures
in 2007 were focused on growth opportunities. Significant expenditures during the year were made to
ongoing development drilling at Cold Lake. Other 2007 investments included advancing the Kearl oil
sands and Mackenzie gas projects, drilling at conventional fields in Western Canada, and
exploration off the East Coast of Canada. Expenditures at Syncrude were lower in 2007 primarily due
to the completion of the Stage 3 upgrader project, partially offset by increased investment in
other facility improvement projects and programs.
23
The Alberta Energy and Utilities Board and the Government of Canada gave conditional
regulatory approval in February 2007 to the companys proposed Kearl oil sands project, following a
joint federal and provincial review. The company is advancing the project including further
progress in engineering work to define the project design, execution strategies and project cost
estimate.
In March, the company, on behalf of the Mackenzie gas project co-venturers, filed updated cost
and schedule information on the proposed project with the National Energy Board and Joint Review
Panel. The updated project costs are $3.5 billion for the gas-gathering system, $7.8 billion for
the Mackenzie Valley Pipeline and $4.9 billion for the development of the anchor fields. Current
project activities are focused on regulatory work, finalizing remaining benefits and access
agreements and establishing an appropriate fiscal framework with the federal government. All the
scheduled public hearings by the Joint Review Panel and the National Energy Board were concluded in
late 2007. The regulatory process continues with a Joint Review Panel report expected in 2008
followed by a National Energy Board decision in early 2009.
Drilling of an exploration well with co-venturers in the Orphan Basin off the East Coast of
Newfoundland was concluded in April. Exploration costs related to the well were reflected in 2007
earnings. Results from the well will be used to plan future drilling in the area.
During the year, the company, along with co-venturer ExxonMobil Canada, successfully acquired
exploration rights for a parcel in the Beaufort Sea. The companys 50 percent share of the proposed
exploration spending would be about $293 million with a minimum commitment of about $73 million.
Planned capital and exploration expenditures in natural resources are expected to be about
$1,200 million in 2008, with over 80 percent of the total focused on growth opportunities.
Investments are mainly planned for development drilling at Cold Lake and conventional oil and gas
operations in Western Canada, facilities improvement at Syncrude, the Kearl oil sands project, the
Mackenzie gas project, and exploration off the East Coast.
The following table shows the companys capital expenditures in the petroleum products segment
during the five years ending December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(millions of dollars) |
Refining and supply |
|
|
120 |
|
|
|
248 |
|
|
|
368 |
|
|
|
178 |
|
|
|
369 |
|
Marketing |
|
|
63 |
|
|
|
97 |
|
|
|
91 |
|
|
|
85 |
|
|
|
91 |
|
Other (a) |
|
|
4 |
|
|
|
16 |
|
|
|
19 |
|
|
|
20 |
|
|
|
18 |
|
|
|
|
Total capital expenditures |
|
|
187 |
|
|
|
361 |
|
|
|
478 |
|
|
|
283 |
|
|
|
478 |
|
|
|
|
|
(a) |
|
Consists primarily of real estate purchases. |
For the petroleum products segment, capital expenditures were $187 million in 2007, compared
with $361 million in 2006 (2005 $478 million). In 2006, the company completed the project to
produce ultra-low sulphur diesel. In 2007, the majority of the capital expenditures were directed
to investments to continue enhancements to the companys retail network, environmental and safety
initiatives, as well as capacity and efficiency improvements.
Capital expenditures for the petroleum products segment in 2008 are expected to be about $300
million. Major items include investments focused on reducing air emissions and improving refinery
utilizations, as well as ongoing upgrades to the retail network.
The following table shows the companys capital expenditures for its chemicals operations
during the five years ending December 31, 2007:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
|
|
(millions of dollars) |
Capital expenditures |
|
|
11 |
|
|
|
13 |
|
|
|
19 |
|
|
|
15 |
|
|
|
41 |
|
Of the capital expenditures for chemicals in 2007, the major investment focused on operational
reliability and energy conservation initiatives.
Planned capital expenditures for chemicals in 2008 will be about $25 million and will include
investments to improve safety and increase future feedstock flexibility.
Total capital and exploration expenditures for the company in 2008, which will focus mainly on
growth and productivity improvements, are expected to total about $1.5 billion and will be financed
from internally generated funds.
Cash flow from financing activities
Cash used in financing activities was $3,956 million in 2007, compared with $2,125 million in
2006 (2005 $2,077 million).
In June, the company renewed the normal course issuer bid (share-repurchase program) for
another 12 months. During 2007, the company purchased 50.5 million shares for $2,358 million (2006
45.5 million shares for $1,818 million). Since Imperial initiated its first share-repurchase
program in 1995, the company has purchased 846
24
million shares representing about 48 percent of the total outstanding at the start of the
program with resulting distributions to shareholders of $12.8 billion.
The company declared dividends totaling 35 cents a share in 2007, up from 32 cents in 2006
(2005 31 cents). Regular annual per-share dividends paid have increased in each of the past 13
years and, since 1986, payments per share have grown by 97 percent.
During the year, the company retired the entire $818 million of long-term loans and the
remaining $404 million of its medium-term notes. Total debt outstanding at the end of 2007,
excluding the companys share of equity company debt, was $146 million, compared with $1,437
million at the end of 2006 (2005 $1,439 million). Debt represented two percent of the companys
capital structure at the end of 2007, compared with 17 percent at the end of 2006 (2005 18
percent).
Debt-related interest incurred in 2007, before capitalization of interest, was $62 million,
compared with $63 million in 2006 (2005 $45 million). The average effective interest rate on the
companys debt was 4.9 percent in 2007, compared with 4.4 percent in 2006 (2005 3.1 percent).
Financial percentages and ratios
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
Total debt as a percentage of capital (a) |
|
|
2 |
|
|
|
17 |
|
|
|
18 |
|
|
|
19 |
|
|
|
21 |
|
Interest coverage ratios |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings basis (b) |
|
|
72 |
|
|
|
66 |
|
|
|
88 |
|
|
|
83 |
|
|
|
64 |
|
Cash-flow basis (c) |
|
|
82 |
|
|
|
77 |
|
|
|
101 |
|
|
|
108 |
|
|
|
80 |
|
|
(a) |
|
Current and long-term portions of debt (page F-5) and the companys share of equity
company debt, divided by debt and shareholders equity (page F-5). |
|
|
(b) |
|
Net income (page F-3), debt-related interest before capitalization (page F-19, note 14)
and income taxes (page F-3) divided by debt-related interest before capitalization. |
|
|
(c) |
|
Cash flow from net income adjusted for other non-cash items (page F-4), current income
tax expense (page F-11, note 5) and debt-related interest before capitalization (page F-19,
note 14) divided by debt-related interest before capitalization. |
The companys financial strength, as evidenced by the above financial ratios, represents a
competitive advantage of strategic importance. The companys sound financial position gives it the
opportunity to access capital markets in the full range of market conditions and enables the
company to take on large, long-term capital commitments in the pursuit of maximizing shareholder
value.
Commitments
The following table shows the companys commitments outstanding at December 31, 2007. It
combines data from the consolidated balance sheet and from individual notes to the consolidated
financial statements.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financial |
|
|
|
|
|
Payment due by period |
|
|
|
|
Statement |
|
|
|
|
|
|
|
|
|
|
Note Reference |
|
|
|
|
|
2009 to |
|
|
2013 and |
|
|
Total |
|
|
|
|
|
|
|
2008 |
|
|
2012 |
|
|
beyond |
|
|
Amount |
|
|
|
|
|
|
|
(millions of dollars) |
Long-term debt (a) |
|
Note 4 |
|
|
3 |
|
|
|
15 |
|
|
|
23 |
|
|
|
41 |
|
Operating leases (b) |
|
Note 15 |
|
|
55 |
|
|
|
138 |
|
|
|
39 |
|
|
|
232 |
|
Unconditional purchase obligations (c) |
|
Note 11 |
|
|
99 |
|
|
|
345 |
|
|
|
38 |
|
|
|
482 |
|
Firm capital commitments (d) |
|
|
|
|
|
|
250 |
|
|
|
43 |
|
|
|
63 |
|
|
|
356 |
|
Pension and other post-retirement obligations (e) |
|
Note 6 |
|
|
218 |
|
|
|
194 |
|
|
|
601 |
|
|
|
1,013 |
|
Asset retirement obligations (f) |
|
Note 7 |
|
|
33 |
|
|
|
199 |
|
|
|
256 |
|
|
|
488 |
|
Other long-term purchase agreements (g) |
|
|
|
|
|
|
215 |
|
|
|
590 |
|
|
|
200 |
|
|
|
1,005 |
|
|
(a) |
|
Includes capitalized lease obligations. Long-term debt amounts exclude the companys
share of equity company debt. |
|
|
(b) |
|
Minimum commitments for operating leases, shown on an undiscounted basis, primarily
cover office buildings, rail cars and service stations. |
|
|
(c) |
|
Unconditional purchase obligations are those long-term commitments that are
non-cancelable and that third parties have used to secure financing for the facilities that
will provide the contracted goods and services. They mainly pertain to pipeline throughput
agreements. |
|
|
(d) |
|
Firm capital commitments related to capital projects, shown on an undiscounted basis.
The largest commitment outstanding at year-end 2007 was $126 million associated with the
companys off-shore exploration projects. |
|
|
(e) |
|
The amount by which the benefit obligations exceeded the fair value of fund assets for
pension and other post-retirement plans at year-end. The payments by period include
expected contributions to funded pension plans in 2008 and estimated benefit payments for
unfunded plans in all years. |
|
|
(f) |
|
Asset retirement obligations represent the discounted present value of legal
obligations associated with site restoration on the retirement of assets with determinable
useful lives. |
|
|
(g) |
|
Other long-term purchase agreements are non-cancelable, long-term commitments other
than unconditional purchase obligations. They include primarily raw material supply and
transportation services agreements. |
25
Unrecognized tax benefits totaling $170 million have not been included in the companys commitments
table because the company does not expect there will be any cash impact from the final settlements
as sufficient funds have been deposited with the Canada Revenue Agency. Further details on the
unrecognized tax benefits can be found in note 5 to the financial statements on page F-11.
The company was contingently liable at December 31, 2007, for a maximum of $83 million
relating to guarantees for purchasing operating equipment and other assets from its rural marketing
associates upon expiry of the associate agreement or the resignation of the associate. The company
expects that the fair value of the operating equipment and other assets so purchased would cover
the maximum potential amount of future payments under the guarantees.
Litigation and other contingencies
As discussed in note 11 to the consolidated financial statements on page F-18, a variety of
claims have been made against Imperial Oil Limited and its subsidiaries. Based on a consideration
of all relevant facts and circumstances, the company does not believe the ultimate outcome of any
currently pending lawsuits against the company will have a material adverse effect on the companys
operations or financial condition.
In 2007, the Alberta government proposed changes to the oil and gas and generic oil sands
royalty regime beginning in 2009. The company believes that this proposal could have an adverse
effect on future company investments in Alberta and the companys future financial results. The
magnitude of the potential impact will depend on the final form of enacted legislation and the
future prices of oil and gas and cannot be reasonably estimated at this time. The Syncrude Joint
Venture owners have a Crown Agreement with the Province of Alberta that codifies the royalty rates
through December 31, 2015. The Syncrude Joint Venture owners are in discussions with the Alberta
government to determine if an amended agreement can be negotiated that would transition Syncrude to
the new generic oil sands royalty regime before 2016.
Recently issued Statements of Financial Accounting Standards
Fair Value Measurements
In September 2006, the Financial Accounting Standards Board (FASB) issued FASB Statement No.
157 (SFAS 157), Fair Value Measurements. SFAS 157 defines fair value, establishes a framework for
measuring fair value when an entity is required to use a fair value measure for recognition or
disclosure purposes and expands the disclosures about fair value measurements. SFAS 157 must be
adopted by the company no later than January 1, 2008 for all financial assets and liabilities that
are measured at fair value and non financial assets and liabilities that are remeasured at fair
value at least annually. SFAS 157 must be adopted no later than January 1, 2009 for non financial
assets and liabilities that are not remeasured at fair value at least annually. The company does
not expect the adoption of SFAS 157 to have a material impact on the companys financial
statements.
Critical accounting policies
The companys financial statements have been prepared in accordance with United States
generally accepted accounting principles (GAAP) and include estimates that reflect managements
best judgment. The companys accounting and financial reporting fairly reflect its straightforward
business model. Imperial 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 note 1 to the consolidated financial
statements on page F-7.
Hydrocarbon reserves
Proved oil, gas and synthetic crude oil reserve quantities are used as the basis of
calculating unit-of-production rates for depreciation and evaluating for impairment. Proved oil and
gas 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.
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 estimation of proved reserves is controlled by the company through long-standing approval
guidelines. Reserve changes are made within a well-established, disciplined process driven by
senior-level geoscience and engineering professionals (assisted by a central reserves group with
significant technical experience), culminating in reviews with and approval by senior management
and the companys board of directors. Notably, the company does not use specific quantitative
reserve targets to determine compensation. Key features of the estimation include rigorous
peer-reviewed technical evaluations and analysis of well and field performance information and a
requirement that management make significant funding commitments toward the development of the
reserves prior to reporting as proved.
26
Although the company is reasonably certain that proved reserves will be produced, the timing
and amount recovered can be affected by a number of factors, including completion of development
projects, reservoir performance, regulatory approvals and significant changes in long-term oil and
gas price levels.
The year-end reserves volumes as well as the reserves change categories shown in the proved
reserves tables are calculated using December 31 prices and costs. These reserves quantities are
also used in calculating unit-of-production depreciation rates and in calculating the standardized
measure of discounted net cash flow. The U.S. Securities and Exchange Commission regulations
preclude the company from showing in the Financial section of this document the reserves that are
calculated in a manner which is consistent with the basis that the company uses to make its
investment decisions. The use of year-end prices for reserves estimation introduces short-term
price volatility into the process, since annual adjustments are required based on prices occurring
on a single day. The company believes that this approach is inconsistent with the long-term nature
of the natural resources business where production from individual projects often spans multiple
decades. The use of prices from a single date is not relevant to the investment decisions made by
the company and annual variations in reserves based on such year-end prices are not of consequence
in how the business is actually managed.
Revisions can include upward or downward changes in previously estimated volumes of proved
reserves for existing fields due to the evaluation or revaluation of already available geologic,
reservoir or production data; new geologic, reservoir or production data; or changes in year-end
prices and costs that are used in the determination of reserves. This category can also include
changes associated with the performance of improved recovery projects and significant changes in
either development strategy or production equipment/facility capacity. The quantities shown in the
revisions category under heavy oil proved reserves in 2005 and 2006 on page 31 were due mainly to
the changes in year-end prices and costs that were used in the determination of reserves.
The company uses the successful-efforts method to account for its exploration and production
activities. Under this method, costs are accumulated on a field-by-field basis with certain
exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive
wells and development dry holes are capitalized and amortized on the unit-of-production method for
each field. The company uses this accounting policy instead of the full-cost method because it
provides a more timely accounting of the success or failure of the companys exploration and
production activities.
Impact of reserves on depreciation
The calculation of unit-of-production depreciation is a critical accounting estimate that
measures the depreciation of natural resources assets. It is the ratio of actual volumes produced
to total proved developed reserves (those reserves recoverable through existing wells with existing
equipment and operating methods) applied to the asset cost. The volumes produced and asset cost are
known and, while proved developed reserves have a high probability of recoverability, they are
based on estimates that are subject to some variability. While the revisions the company has made
in the past are an indicator of variability, they have had little impact on the unit-of-production
rates of depreciation.
Impact of reserves and prices on testing for impairment
Proved oil and gas properties held and used by the company are reviewed for impairment
whenever events or 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. In general, impairment analyses are based on proved
reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves
may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash
flows were less than its carrying value. Impairments are measured by the amount by which the
assets carrying value exceeds its fair value.
The impairment evaluation triggers include a significant decrease in current and projected
prices or reserve volumes, an accumulation of project costs significantly in excess of the amount
originally expected and historical and current operating losses.
In general, the company does not view temporarily low oil prices as a triggering event for
conducting impairment tests. The markets for crude oil and natural gas have a history of
significant price volatility. Although prices will occasionally drop precipitously, the relative
growth/decline in supply versus demand will determine industry prices over the long term and these
cannot be accurately predicted. Accordingly, any impairment tests that the company performs make
use of the companys price assumptions developed in the annual planning and budgeting process for
crude oil and natural gas markets, petroleum products and chemicals. These are the same price
assumptions that are used for capital investment decisions. Volumes are based on individual field
production profiles, which are also updated annually.
The standardized measure of discounted future cash flows on page 33 is based on the year-end
price applied for all future years, as required under Statement of Financial Accounting Standards
No. 69 (SFAS 69). Future
27
prices used for any impairment tests will vary from the one used in the SFAS 69
disclosure and could be lower or higher for any given year.
Pension 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 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 8.00 percent used in 2007 compares
to actual returns of 8.29 percent and 9.84 percent achieved over the last 10- and 20-year periods
ending December 31, 2007. If different assumptions are used, the expense and obligations could
increase or decrease as a result. The companys potential exposure to changes in assumptions is
summarized in note 6 to the consolidated financial statements on page F-12. At Imperial,
differences between actual returns on plan assets and the long-term expected returns are not
recorded in pension expense in the year the differences occur. Such differences are deferred, along
with other actuarial gains and losses, and are amortized into pension expense over the expected
remaining service life of employees. Pension expense represented less than one percent of total
expenses in 2007.
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. For 2007, the obligations were discounted at
six percent and the accretion expense was $25 million, before tax, 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.
Asset retirement obligations for these facilities generally become firm at the time the facilities
are permanently shut down and dismantled. These obligations may include the costs of asset disposal
and additional soil remediation. However, these sites have indeterminate lives based on plans for
continued operations, and as such, the fair value of the conditional legal obligations cannot be
measured, since it is impossible to estimate the future settlement dates of such obligations. 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.
Tax Contingencies
The operations of the company are complex, and related tax interpretations, regulations and
legislation are continually changing. Significant management judgment is required in the accounting
for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
GAAP requires recognition and measurement of uncertain tax positions that the company has
taken or expects to take in its income tax returns. The benefit of an uncertain tax position can
only be recognized in the financial statements if management concludes that it is more likely than
not that the position will be sustained with the tax authorities. For a position that is likely to
be sustained, the benefit recognized in the financial statements is measured at the largest amount
that is greater than 50 percent likely of being realized. A reserve is established for the
difference between a position taken in an income tax return and the amount recognized in the
financial statements. The companys unrecognized tax benefits and a description of open tax years
are summarized in note 5 to the consolidated financial statements on page F-11.
28
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.
In April 2007, the Government of Canada announced its intent to introduce a set of regulations
to limit emissions of greenhouse gas and air pollutants from major industrial facilities in Canada
beginning in 2010, although the details of the regulations have not been finalized. Consequently,
attempts to assess the impact on the company are premature. The company will continue to monitor
the development of legal requirements in this area.
In the Province of Alberta, regulations governing greenhouse gas emissions from large
industrial facilities came into effect July 1, 2007. The company does not expect ongoing compliance
costs to have a material adverse effect on the companys operations or financial condition.
The recently enacted U.S. Energy Independence and Security Act of 2007 precludes agencies of
the U.S. federal government from procuring motive fuels from non-conventional petroleum sources
that have lifecycle greenhouse gas emissions greater than equivalent conventional fuel. This may
have implications for the companys marketing in the United States of some heavy oil and oil sands
production, but the impact cannot be determined at this time.
Other risks, such as changes in international commodity prices and currency-exchange rates,
are beyond the companys control. 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 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 earnings sensitivity table below, which shows the estimated annual
effect, under current conditions, of certain sensitivities of the companys after-tax net income.
Earnings sensitivities (a)
|
|
|
|
|
|
|
|
|
millions of dollars after tax |
Nine dollars (U.S.) a barrel change in crude oil prices |
|
+(-) |
|
|
330 |
|
Sixty cents a thousand cubic feet change in natural gas prices |
|
+(-) |
|
|
6 |
|
One cent (U.S) a litre change in sales margins for total petroleum products |
|
+(-) |
|
|
182 |
|
One cent (U.S.) a pound change in sales margins for polyethylene |
|
+(-) |
|
|
6 |
|
Ten cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar |
|
+(-) |
|
|
400 |
|
|
|
|
(a) |
|
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 2007.
Each sensitivity calculation shows the impact on net income 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 of net income to changes in crude oil prices decreased from 2006 year-end by
about $8 million (after-tax) for each one U.S.-dollar difference. An increase in the value of the
Canadian dollar has lessened the impact of the U.S. dollar denominated crude oil prices on the
companys revenues and earnings.
The sensitivity of net income to changes in natural gas prices decreased from 2006 year-end by
about $2 million (after-tax) for each 10-cent change, primarily due to the companys lower natural
gas production.
The sensitivity of net income to changes in the Canadian dollar versus the U.S. dollar
decreased from 2006 year-end by about $4 million (after-tax) for each one-cent difference. This was
primarily due to the impact of the widening price spread between light crude oil and Cold Lake
heavy oil.
Item 8. Financial Statements and Supplementary Data.
Reference is made to the Index to Financial Statements on page F-1 of this report.
Syncrude Mining Operations
Syncrudes crude bitumen is contained within the unconsolidated sands of the McMurray
Formation. Ore bodies are buried beneath 50 to 150 feet of overburden, have bitumen grades ranging
from 4 to 14 weight percent and ore thickness of 115 to 160 feet. Estimates of synthetic crude oil
reserves are based on detailed geological and engineering assessments of in-place crude bitumen
volumes, 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. In active mining areas, the
approximate well spacing is 400 feet (150 wells per section) and in future mining areas, the well
spacing is approximately 1,150 feet (20 wells per section). Proven reserves are within operating
North and Aurora mines. In accordance with the long range mine plan approved by the Syncrude
owners, there are extractable oil sands in the North and Aurora mines, with average bitumen grades
of 10.6 and 11.2 weight percent respectively. After deducting royalties payable to the Province of
Alberta, the company estimates its 25 percent net share of proven reserves at year end 2007 was equivalent to 694 million barrels of
synthetic crude oil. Imperials reserve
29
assessment uses a 6 percent and 7 percent bitumen grade
cut-off for the North mine and Aurora mine respectively, a 90 percent overall extraction recovery,
a 97 percent mining dilution factor and an 88 percent upgrading yield.
In 2007, the Alberta government proposed changes to the generic oil sands royalty regime
beginning in 2009. The Syncrude Joint Venture owners have a Crown Agreement with the Province of
Alberta that codifies the royalty rates through December 31, 2015. The Syncrude Joint Venture
owners are in discussions with the Alberta government to determine if an amended agreement can be
negotiated that would transition Syncrude to the new generic royalty regime before 2016.
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 |
|
Aurora mine |
|
Total |
|
|
|
|
|
|
North mine |
|
|
|
|
|
|
|
|
|
|
(millions of barrels) |
|
|
|
|
Beginning of year 2005 |
|
|
217 |
|
|
|
540 |
|
|
|
757 |
|
|
|
|
|
Revision of previous estimate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(9) |
|
|
|
(10) |
|
|
|
(19) |
|
|
|
|
|
|
|
|
End of year 2005 |
|
|
208 |
|
|
|
530 |
|
|
|
738 |
|
|
|
|
|
Revision of previous estimate |
|
|
|
|
|
|
1 |
|
|
|
1 |
|
|
|
|
|
Production |
|
|
(9) |
|
|
|
(12) |
|
|
|
(21) |
|
|
|
|
|
|
|
|
End of year 2006 |
|
|
199 |
|
|
|
519 |
|
|
|
718 |
|
|
|
|
|
Revision of previous estimate |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Production |
|
|
(11) |
|
|
|
(13) |
|
|
|
(24) |
|
|
|
|
|
|
|
|
End of year 2007 |
|
|
188 |
|
|
|
506 |
|
|
|
694 |
|
|
|
|
|
|
|
|
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.
Results of operations
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
(millions of dollars) |
|
|
|
|
Sales to customers (1) |
|
|
2,383 |
|
|
|
2,601 |
|
|
|
2,739 |
|
|
|
|
|
Intersegment sales (1)(2) |
|
|
1,131 |
|
|
|
1,251 |
|
|
|
1,013 |
|
|
|
|
|
|
|
|
|
|
|
3,514 |
|
|
|
3,852 |
|
|
|
3,752 |
|
|
|
|
|
Production expenses |
|
|
1,074 |
|
|
|
1,016 |
|
|
|
1,035 |
|
|
|
|
|
Exploration expenses |
|
|
100 |
|
|
|
32 |
|
|
|
31 |
|
|
|
|
|
Depreciation and depletion |
|
|
371 |
|
|
|
467 |
|
|
|
583 |
|
|
|
|
|
Income taxes |
|
|
526 |
|
|
|
564 |
|
|
|
716 |
|
|
|
|
|
|
|
|
Results of operations |
|
|
1,443 |
|
|
|
1,773 |
|
|
|
1,387 |
|
|
|
|
|
|
|
|
Capital and exploration expenditures
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
|
|
|
|
|
(millions of dollars) |
|
|
|
|
Property costs (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Proved |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Unproved |
|
|
1 |
|
|
|
|
|
|
|
7 |
|
|
|
|
|
Exploration costs |
|
|
100 |
|
|
|
32 |
|
|
|
37 |
|
|
|
|
|
Development costs |
|
|
437 |
|
|
|
496 |
|
|
|
330 |
|
|
|
|
|
|
|
|
Total capital and exploration expenditures |
|
|
538 |
|
|
|
528 |
|
|
|
374 |
|
|
|
|
|
|
|
|
30
Property, plant and equipment
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
|
2006 |
|
|
(millions of dollars) |
Property costs (3) |
|
|
|
|
|
|
|
|
Proved |
|
|
3,167 |
|
|
|
3,226 |
Unproved |
|
|
148 |
|
|
|
139 |
Producing assets |
|
|
6,706 |
|
|
|
6,392 |
Support facilities |
|
|
180 |
|
|
|
184 |
Incomplete construction |
|
|
579 |
|
|
|
595 |
|
|
|
Total cost |
|
|
10,780 |
|
|
|
10,536 |
Accumulated depreciation and depletion |
|
|
7,505 |
|
|
|
7,326 |
|
|
|
Net property, plant and equipment |
|
|
3,275 |
|
|
|
3,210 |
|
|
|
|
|
|
(1) |
|
Sales to customers or intersegment sales do not include the sale of natural gas and
natural gas liquids purchased for resale, as well as royalty payments. These items are
reported gross in note 3 (page F-10) in external sales, intersegment sales and in
purchases of crude oil and products. |
(2) |
|
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. |
(3) |
|
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. |
Oil and Gas Reserves
Proved developed and undeveloped reserves (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Crude oil and natural gas liquids |
|
Natural Gas |
|
|
|
Conventional |
|
|
Heavy Oil (2) |
|
|
Total |
|
|
|
Total |
|
|
|
(millions of barrels) |
|
(billions of |
|
|
|
|
|
|
|
|
|
|
|
|
|
cubic feet) |
|
Beginning of year 2005 |
|
|
115 |
|
|
|
232 |
|
|
|
347 |
|
|
|
791 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions |
|
|
|
|
|
|
350 |
|
|
|
350 |
|
|
|
137 |
|
Improved recovery |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Sale)/purchase of reserves in place |
|
|
(12) |
|
|
|
|
|
|
|
(12) |
|
|
|
(6) |
|
Discoveries and extensions |
|
|
|
|
|
|
14 |
|
|
|
14 |
|
|
|
13 |
|
Production |
|
|
(20) |
|
|
|
(45) |
|
|
|
(65) |
|
|
|
(188) |
|
|
|
|
End of year 2005 |
|
|
83 |
|
|
|
551 |
|
|
|
634 |
|
|
|
747 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions |
|
|
4 |
|
|
|
236 |
|
|
|
240 |
|
|
|
140 |
|
Improved recovery |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Sale)/purchase of reserves in place |
|
|
(1) |
|
|
|
|
|
|
|
(1) |
|
|
|
(6) |
|
Discoveries and extensions |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10 |
|
Production |
|
|
(15) |
|
|
|
(46) |
|
|
|
(61) |
|
|
|
(181) |
|
|
|
|
End of year 2006 |
|
|
71 |
|
|
|
741 |
|
|
|
812 |
|
|
|
710 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Revisions |
|
|
24 |
|
|
|
(27) |
|
|
|
(3) |
|
|
|
75 |
|
Improved recovery |
|
|
|
|
|
|
6 |
|
|
|
6 |
|
|
|
1 |
|
(Sale)/purchase of reserves in place |
|
|
(1) |
|
|
|
|
|
|
|
(1) |
|
|
|
(12) |
|
Discoveries and extensions |
|
|
|
|
|
|
44 |
|
|
|
44 |
|
|
|
8 |
|
Production |
|
|
(12) |
|
|
|
(47) |
|
|
|
(59) |
|
|
|
(147) |
|
|
|
|
End of year 2007 |
|
|
82 |
|
|
|
717 |
|
|
|
799 |
|
|
|
635 |
|
|
|
|
|
|
|
(1) |
|
Proved developed and undeveloped reserves reported on this table represent net
reserves. 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. |
(2) |
|
Heavy oil reserves typically are represented by crude oils with a viscosity of greater
than 10,000 cP and recovered through enhanced thermal operations. Currently, the companys
heavy oil reserves are from the Cold Lake production operations. |
The information above describes changes during the years and balances of proved oil and gas
reserves at year-end 2005, 2006 and 2007. The definitions used for oil and gas reserves are in
accordance with the U.S. Securities and Exchange Commissions (SEC) Rule 4-10 (a) of Regulation
S-X, paragraphs (2), (3) and (4).
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.
31
The year-end reserves volumes as well as the reserves change categories shown in the proved
reserves tables are calculated using December 31 prices and costs. These reserves quantities are
also used in calculating unit-of-production depreciation rates and in calculating the standardized
measure of discounted net cash flow. We understand that the use of December 31 prices and costs is
intended to provide a point in time measure to calculate reserves and to enhance comparability
between companies.
The U.S. Securities and Exchange Commission regulations preclude the company from showing in
the Financial section of this document, however, the reserves that are calculated in a manner which
is consistent with the basis that the company uses to make its investment decisions. The use of
year-end prices for reserves estimation introduces short-term price volatility into the process
since annual adjustments are required based on prices occurring on a single day. The company
believes that this approach is inconsistent with the long-term nature of the natural resources
business where production from individual projects often spans multiple decades. The use of prices
from a single date is not relevant to the investment decisions made by the company and annual
variations in reserves based on such year-end prices are not of consequence in how the business is
actually managed.
Revisions can include upward or downward changes in previously estimated volumes of proved
reserves for existing fields due to the evaluation or revaluation of already available geologic,
reservoir or production data; new geologic, reservoir or production data; or changes in year-end
prices and costs that are used in the determination of reserves. This category can also include
changes associated with the performance of improved recovery projects and significant changes in
either development strategy or production equipment/facility capacity. The quantities shown in the
revisions category under heavy oil proved reserves in 2005 and 2006 were due mainly to changes in
year-end prices and costs that were used in the determination of reserves.
In 2007, the Alberta government proposed increases to the royalty rates on oil and gas
production beginning in 2009. The magnitude of the potential impact on future royalty rates will
depend on the final form of enacted legislation and the future prices of oil and gas and cannot be
reasonably estimated at this time. As a result, this proposed increase in royalty rates cannot be
and has not been reflected in the net proved crude oil and natural gas reserves at December 31,
2007.
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 heavy oil, 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.
Oil-equivalent barrels (OEB) may be misleading, particularly if used in isolation. An OEB
conversion ratio of 6,000 cubic feet to one barrel on an energy-equivalent conversion method is
primarily applicable at the burner tip and does not represent a value equivalency at the well head.
No independent qualified reserves evaluator or auditor was involved in the preparation of the
reserves data.
Net proved developed and undeveloped reserves of crude oil and natural gas as of December 31 (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
Crude Oil (millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels |
|
|
82 |
|
|
|
71 |
|
|
|
83 |
|
|
|
115 |
|
|
|
126 |
|
Heavy Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels |
|
|
717 |
|
|
|
741 |
|
|
|
551 |
|
|
|
232 |
|
|
|
763 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels |
|
|
799 |
|
|
|
812 |
|
|
|
634 |
|
|
|
347 |
|
|
|
889 |
|
Natural Gas (billions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic feet |
|
|
635 |
|
|
|
710 |
|
|
|
747 |
|
|
|
791 |
|
|
|
1,023 |
|
|
|
|
(1) |
|
Net reserves are the companys share of reserves after deducting the shares of mineral
owners or governments or both. |
32
Net proved developed reserves of crude oil and natural gas as of December 31 (1)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
2006 |
|
2005 |
|
2004 |
|
2003 |
Crude Oil (millions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Conventional |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels |
|
|
82 |
|
|
|
71 |
|
|
|
81 |
|
|
|
111 |
|
|
|
121 |
|
Heavy Oil |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels |
|
|
483 |
|
|
|
501 |
|
|
|
368 |
|
|
|
232 |
|
|
|
398 |
|
Total |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Barrels |
|
|
565 |
|
|
|
572 |
|
|
|
449 |
|
|
|
343 |
|
|
|
519 |
|
Natural Gas (billions) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cubic feet |
|
|
539 |
|
|
|
608 |
|
|
|
643 |
|
|
|
704 |
|
|
|
859 |
|
|
|
|
(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 cash flows
As required by SFAS 69, the standardized measure of discounted future net cash flows is
computed by applying year-end prices, costs and legislated tax rates and a discount factor of 10
percent to net proved reserves. The standardized measure includes costs for future dismantlement,
abandonment and remediation 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. The table below excludes
the companys interest in Syncrude.
Standardized measure of discounted future net cash flows related to proved oil and gas reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(millions of dollars) |
Future cash flows |
|
|
32,415 |
|
|
|
36,751 |
|
|
|
21,911 |
|
Future production costs |
|
|
(14,475) |
|
|
|
(16,290) |
|
|
|
(11,376) |
|
Future development costs |
|
|
(3,548) |
|
|
|
(2,633) |
|
|
|
(2,039) |
|
Future income taxes |
|
|
(3,655) |
|
|
|
(5,039) |
|
|
|
(2,777) |
|
|
|
|
Future net cash flows |
|
|
10,737 |
|
|
|
12,789 |
|
|
|
5,719 |
|
Annual discount of 10 percent for estimated timing of cash flows |
|
|
(4,487) |
|
|
|
(6,374) |
|
|
|
(1,405) |
|
|
|
|
Discounted future cash flows |
|
|
6,250 |
|
|
|
6,415 |
|
|
|
4,314 |
|
|
|
|
Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
|
(millions of dollars) |
Balance at beginning of year |
|
|
6,415 |
|
|
|
4,314 |
|
|
|
3,317 |
|
Changes resulting from: |
|
|
|
|
|
|
|
|
|
|
|
|
Sales and transfers of oil and gas produced, net of production costs |
|
|
(2,430) |
|
|
|
(2,839) |
|
|
|
(2,650) |
|
Net changes in prices, development costs and production costs |
|
|
(625) |
|
|
|
4,221 |
|
|
|
3,343 |
|
Extensions, discoveries, additions and improved recovery, less related costs |
|
|
164 |
|
|
|
(4) |
|
|
|
(513) |
|
Development costs incurred during the year |
|
|
412 |
|
|
|
411 |
|
|
|
272 |
|
Revisions of previous quantity estimates |
|
|
1,285 |
|
|
|
87 |
|
|
|
660 |
|
Accretion of discount |
|
|
710 |
|
|
|
568 |
|
|
|
417 |
|
Net change in income taxes |
|
|
319 |
|
|
|
(343) |
|
|
|
(532) |
|
|
|
|
Net change |
|
|
(165) |
|
|
|
2,101 |
|
|
|
997 |
|
|
|
|
Balance at end of year |
|
|
6,250 |
|
|
|
6,415 |
|
|
|
4,314 |
|
|
|
|
Within the past 12 months, the company has not filed oil and gas reserve estimates with any
authority or agency of the United States.
33
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.
Item 9A. Controls and Procedures.
As indicated in the certifications in Exhibit 31 of this report, the companys principal
executive officer and principal financial officer have evaluated the companys disclosure controls
and procedures as of December 31, 2007. Based on that evaluation, these officers have concluded
that the companys disclosure controls and procedures are effective in ensuring that information
required to be disclosed by the company in the reports that it files or submits under the
Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner
that allows for timely decisions regarding required disclosures and are effective in ensuring that
such information is recorded, processed, summarized and reported within the time periods specified
in the Securities and Exchange Commissions rules and forms.
Reference is made to page F-2 of this report for managements report on internal control over
financial reporting.
Reference is made to page F-2 of this report for the report of the independent registered
public accounting firm on the companys internal control over financial reporting as of December
31, 2007.
There has not been any change in the companys internal control over financial reporting
during the last fiscal quarter 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.
Each of the eight individuals listed below has been nominated for election at the annual
meeting of shareholders to be held May 1, 2008. All of the nominees except for Krystyna T. Hoeg,
are now directors and have been since the dates indicated. Timothy J. Hearn and James F. Shepard
are currently directors and have both requested not to be nominated for re-election. Timothy J.
Hearn has announced his intention to retire as director, chairman and chief executive officer
effective March 31, 2008. Bruce H. March has been elected as chairman, president and chief
executive officer effective April 1, 2008.
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 (3)(4)(5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
R.L. (Randy) Broiles
Senior vice-president,
resources division,
Imperial Oil Limited
|
|
|
Global planning manager,
ExxonMobil Production
Company
|
|
|
July 21, 2005
|
|
|
Common shares of
Imperial Oil Limited
Deferred share units of
Imperial Oil Limited
Restricted stock units of
Imperial Oil Limited
Shares of
Exxon Mobil Corporation (6)
|
|
|
7,500
0
0
66,229 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Krystyna T. Hoeg
Retired president and
chief executive officer
of Corby Distilleries
Limited
|
|
|
|
|
|
Not currently a
member of the board
|
|
|
Common shares of
Imperial Oil Limited
Deferred share units of
Imperial Oil Limited
Restricted stock units of
Imperial Oil Limited
Shares of
Exxon Mobil Corporation
|
|
|
0
0
0
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Bruce H. March
President,
Imperial Oil Limited
|
|
|
Director, refining
Europe/Africa/Middle East,
ExxonMobil Petroleum &
Chemicals, Brussels,
Belgium
|
|
|
January 1, 2008
|
|
|
Common shares of
Imperial Oil Limited
Deferred share units of
Imperial Oil Limited
Restricted stock units of
Imperial Oil Limited
Shares of
Exxon Mobil Corporation (6)
|
|
|
5,000
0
0
70,929 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J.M. (Jack) Mintz
Palmer Chair in Public
Policy for the
University of Calgary
(1)(2)
|
|
|
|
|
|
April 21, 2005
|
|
|
Common shares of
Imperial Oil Limited
Deferred share units
of Imperial Oil Limited
Restricted stock units
of Imperial Oil Limited
Shares of
Exxon Mobil Corporation
|
|
|
1,000
1,684
8,000
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(Table continued on following page)
35
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Last major |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
position or office with the |
|
|
|
|
|
|
|
|
|
|
|
Name and current principal |
|
|
company or Exxon Mobil |
|
|
|
|
|
|
|
|
|
|
|
occupation or employment |
|
|
Corporation |
|
|
Director since |
|
|
Holdings (3)(4)(5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
R. (Roger) Phillips
Retired president and
chief executive officer,
IPSCO Inc.
(steel manufacturing) (1)(2)
|
|
|
|
|
|
April 23, 2002
|
|
|
Common shares of
Imperial Oil Limited
Deferred share units of
Imperial Oil Limited
Restricted stock units
of Imperial Oil Limited
Shares of
Exxon Mobil Corporation
|
|
|
9,000
14,887
12,125
2,000 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
P.A. (Paul) Smith
Senior vice-president,
finance and administration,
and treasurer
Imperial Oil Limited (2)
|
|
|
Controller and senior
vice-president, finance
and administration
|
|
|
February 1, 2002
|
|
|
Common shares of
Imperial Oil Limited
Deferred share units of
Imperial Oil Limited
Restricted stock units of
Imperial Oil Limited
Shares of
Exxon Mobil Corporation
|
|
|
13,337
0
190,250
1,662 |
|
|
|
|
|
|
|
|
|
|
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|
|
|
|
|
|
S.D. (Sheelagh) Whittaker
Retired managing director,
Electronic Data Systems
Limited (business and
information technology
services)
(1)(2)
|
|
|
|
|
|
April 19, 1996
|
|
|
Common shares of
Imperial Oil Limited
Deferred share units of
Imperial Oil Limited
Restricted stock units of
Imperial Oil Limited
Shares of
Exxon Mobil Corporation
|
|
|
9,000
30,452
12,125
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
V.L. (Victor) Young
Corporate director of
several corporations (1)(2)
|
|
|
|
|
|
April 23, 2002
|
|
|
Common shares of
Imperial Oil Limited
Deferred share units of
Imperial Oil Limited
Restricted stock units
of Imperial Oil Limited
Shares of
Exxon Mobil Corporation
|
|
|
10,250
5,320
12,125
0 |
|
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|
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|
(1) |
|
Member of audit committee; member of environment, health and safety committee; member
of executive resources committee; and member of nominations and corporate governance
committee. |
(2) |
|
Member of Imperial Oil Foundation board of directors |
(3) |
|
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. |
(4) |
|
The companys plans for deferred share units and restricted stock units for selected
employees and nonemployee directors are described on page 43 and page 44 respectively. |
(5) |
|
The numbers for the companys restricted stock units and deferred share units represent
the total of the restricted stock units and deferred share units received in 2006 and 2007
after the three-for-one share split in May 2006, plus three times the number of restricted
stock units and deferred share units granted before the share split and still held by the
director. |
(6) |
|
R.L. Broiles holds 17,729 common shares and 48,500 restricted shares of Exxon Mobil
Corporation. B.H. March holds 20,679 common shares and 50,250 restricted shares and
restricted stock units of Exxon Mobil Corporation. |
The ages of the directors, nominees for election as directors, and the five senior executives
of the company are: Randy L. Broiles 50, Timothy J. Hearn 63, Krystyna T. Hoeg 58, Bruce H. March
51, Jack M. Mintz 56, Roger Phillips 68, James F. Shepard 69, Paul A. Smith 54, Sheelagh D.
Whittaker 60, Victor L. Young 62 and Brian W. Livingston 53.
36
Certain of the directors and nominees for election as directors hold positions as directors of
other Canadian and U.S. reporting issuers as follows: Timothy J. Hearn - Royal Bank of Canada;
Krystyna T. Hoeg - Sun Life Financial Inc., Shoppers Drug Mart Corporation, Canadian Pacific
Railway Limited and Cineplex Galaxy Income Fund; Jack M. Mintz - Brookfield Asset Management Inc.
and CHC Helicopter Corporation; Roger Phillips - Canadian Pacific Railway Company, Canadian Pacific
Railway Limited, Cleveland-Cliffs Inc. and The Toronto-Dominion Bank; James F. Shepard - Canfor
Corporation; and Victor L. Young - Bell Aliant Regional Communications Income Fund, BCE Inc. and
Royal Bank of Canada.
All of the directors and nominees for election as directors, except for Krystyna T. Hoeg, Jack
M. Mintz, James F. Shepard and Sheelagh D. Whittaker 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, Krystyna T. Hoeg was president and chief
executive officer of Corby Distilleries Limited until she retired in February 2007, Jack M. Mintz
was president and chief executive officer of The C.D. Howe Institute until he retired in July 2006,
James F. Shepard became president and chief executive officer of Canfor Corporation in July 2007,
and Sheelagh D. Whittaker was managing director of Electronic Data Systems until she retired in
November 2005.
The following table provides information on the senior executives of the company as of February 14, 2008.
|
|
|
Name and Office |
|
Office held since |
Timothy J. Hearn
chairman of the board
and chief executive officer
|
|
January 1, 2008 |
|
|
|
Bruce H. March
president
|
|
January 1, 2008 |
|
|
|
Paul A. Smith
senior vice-president,
finance and administration,
and treasurer
|
|
February 1, 2008 |
|
|
|
Randy L. Broiles
senior vice-president, resources division
|
|
July 1, 2005 |
|
|
|
Brian W. Livingston
vice-president, general counsel and corporate secretary
|
|
August 1, 2004 |
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 the
members of the audit committee: R. Phillips, J.F. Shepard, S.D. Whittaker, V.L. Young, and J.M.
Mintz.
Audit committee financial expert
The companys board of directors has determined that R. Phillips, S.D. Whittaker and V.L.
Young meet the definition of audit committee financial expert and that they, J.F. Shepard and
J.M. Mintz are independent, as that term is defined in Multilateral Instrument 52-110, 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 that applies to all employees, including its principal
executive officer, principal financial officer and principal accounting officer. The code of ethics
consists of the companys ethics policy, conflicts of interest policy, corporate assets policy,
directorships policy, and procedures and open door communication. Those documents are available at
the companys web site www.imperialoil.ca.
37
Item 11. Executive Compensation.
Composition of the companys compensation committee
The executive resources committee of the board of directors, composed of the independent
directors, is responsible for corporate policy on compensation and for specific decisions on the
compensation of the chief executive officer and key senior executives and officers reporting
directly to that position. In addition to compensation matters, the committee is also responsible
for succession plans and appointments to senior executive and officer positions, including the chief executive officer. During 2007, the membership
of the executive resources committee was as follows:
R.
Phillips - Chair
V.L. Young - Vice-chair
J.F. Shepard
S.D. Whittaker
J.M. Mintz
T.J. Hearn periodically attends meetings at the request of the committee.
Executive Resources Committee Report on Executive Compensation
Compensation Discussion and Analysis
The companys executive compensation program is designed to reinforce the companys
orientation toward career employment and individual performance. It acknowledges the long-term
nature of the companys business and its philosophy that the experience, skill and motivation of
the companys 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.
The assessment of individual performance is conducted through the companys employee appraisal
program. Conducted annually, the appraisal process assesses performance against business
performance measures and objectives relevant to each employee including the means by which
performance is achieved. It involves comparative ranking of employee performance using a standard
process throughout the organization and at all levels. The appraisal program is integrated with the
compensation program and also with the executive development process. Both have been in place for
more than 50 years and are the basis for planning individual development and succession planning
for management positions.
In establishing compensation for the companys senior executives, the executive resources
committee relies on market comparisons to a group of 25 major Canadian 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
management.
The companys executive compensation program is composed of base salaries, cash bonuses and
medium/long-term incentive compensation. The company does not have written employment contracts or
any other agreement with its named executive officers providing for payments on change of control
or termination of employment.
Base Salary
The companys salary ranges for executives were increased by 2.5 percent in 2006 and 8.0
percent in 2007 and 2008. The salary program in 2008 maintained the companys competitive position
on salaries in the marketplace. Individual salary increases vary depending on each executives
performance assessment and other factors such as time in position and potential for advancement.
Cash Bonus
Cash bonuses are typically granted to approximately 80 executives to reward their
contributions to the business during the past year. Bonuses are drawn from an aggregate bonus pool
established annually by the executive resources committee based on the companys financial and
operating performance.
In 2007, the overall bonus pool generally remained the same as the previous year and continues
to reflect improved financial results and operating performance. In relation to this, the companys
net income for 2007 was a record $3.188 billion (up 5 percent), return on shareholders equity was
42 percent, return on capital employed was 38 percent and total annual shareholders return was 28
percent. Changes in individual cash bonus awards vary depending on each executives performance
assessment.
Medium/Long-Term Incentive Compensation
A medium-term incentive compensation plan, called the earnings bonus unit plan, was introduced
in 2001 and continues today. This plan is made available to selected executives to promote
individual contribution to sustained
38
improvement in the companys business performance and shareholder value. Earnings bonus units
are generally equal to and granted in tandem with cash bonuses to approximately 80 executives
annually. In 2007, 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 after the fifth anniversary of the grant, or when the maximum settlement
value per unit is reached, if earlier. If after five years the maximum payout has not been reached,
payout will be prorated. In 2007, similar to the cash bonus pool, the earnings bonus units pool
generally remained the same as the previous year.
In December 2002, the company introduced a restricted stock unit plan, which is the companys
long-term incentive compensation plan. The purpose of the plan is to align the interests of
selected employees and nonemployee directors directly with the interests of shareholders. The
restricted stock unit plan is a straightforward, primarily cash-based approach to long-term
incentive compensation.
Grant level guidelines for the restricted stock unit program are generally held constant for
long periods of time. In 2006, the guidelines were reviewed in light of the companys three-for-one
share split. Given the significant appreciation in the companys share price over the previous
several years, restricted stock unit guidelines were adjusted on a two-for-one basis rather than
the three-for-one share split. This had the effect of reducing grant values in 2006 and 2007
compared to earlier years.
Each unit granted in 2007 entitles the recipient to receive from the company, upon exercise,
an amount equal to the five day average of the closing price of the companys shares preceding the
exercise dates. Fifty percent of the units will be exercised by the company on the third
anniversary of the grant date, and the remainder will be exercised on the seventh anniversary of
the grant date. Recipients may receive the proceeds of the seventh year exercise as either one
common share per unit or elect a cash payment. The company also pays 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.
In 2007, 800 employees were granted restricted stock units, including 95 executives.
CEO compensation
T.J. Hearns salary is currently assessed to be within the range of the competitive target for
the companys chairman, president and chief executive officer, namely, between the median and upper
quartile of the competitive market. The target is consistent with the executive resources
committees view that the chairman, president and 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 organization.
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 focusing 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
chairman, president and chief executive officer. T.J. Hearns 2007 cash bonus remained the same as
his 2006 cash bonus, again to reflect his effectiveness in the position, the companys record
financial performance and comparisons to other leading Canadian employers.
With respect to the companys medium term incentive program, the committee similarly awarded
Mr. Hearn the same earnings bonus unit award that he received in 2006 for the same reasons noted
above for Mr. Hearns cash bonus award.
Directors compensation
Directors fees are paid only to nonemployee directors. For 2007, nonemployee directors were
paid an annual retainer of $35,000 and 2,000 restricted stock units 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. The restricted stock units issued to nonemployee directors have the same features as the
restricted stock units for selected key employees described on page 44.
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 page 43.
While serving as directors in 2007, the aggregate cash remuneration paid to nonemployee
directors, as a group, was $384,875, and they received an additional 5,456 deferred share units,
based on an aggregate of $265,625 of cash remuneration elected to be received as deferred share
units. The nonemployee directors, as a group, received an additional 514 deferred share units
granted as the equivalent to the cash dividend paid on company shares during 2007 for previously
granted deferred share units. In addition, the nonemployee directors received 10,000 restricted
stock units.
39
Senior executive compensation
Summary Compensation Table
The following table shows the compensation for the chairman, president and chief executive
officer; the controller and senior vice-president, finance and administration and the three other
most highly compensated senior executives of the company who were serving as senior executives at
the end of 2007. This information includes the dollar value of base salaries, cash bonus awards and
units of other long-term incentive compensation and certain other compensation.
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Annual Compensation |
|
|
Long-Term Compensation |
|
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Awards |
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Payouts |
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Shares or |
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Shares or |
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Securities |
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Units |
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Units |
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Under |
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Subject to |
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Subject to |
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Name and |
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Other Annual |
|
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Options/ |
|
|
Resale |
|
|
Resale |
|
|
LTIP |
|
|
All Other |
|
|
Total |
|
|
Principal |
|
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|
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|
|
|
|
Bonus |
|
|
Compensation |
|
|
SARs |
|
|
Restrictions |
|
|
Restrictions |
|
|
Payouts |
|
|
Compensation |
|
|
Compensation |
|
|
Position at the |
|
|
|
|
|
|
|
Salary |
|
|
(2) |
|
|
(3) |
|
|
Granted (4) |
|
|
(5) (6) |
|
|
(5) (6) |
|
|
(7) |
|
|
(8) |
|
|
(9) |
|
|
end of 2007 |
|
|
Year |
|
|
($) |
|
|
($) |
|
|
($) |
|
|
(#) |
|
|
(#) |
|
|
($) |
|
|
($) |
|
|
($) |
|
|
($) |
|
|
|
|
|
|
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|
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|
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|
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|
|
|
|
|
|
|
|
T.J. Hearn |
|
|
|
2007 |
|
|
|
|
1,200,000 |
|
|
|
|
1,000,050 |
|
|
|
|
671,855 |
|
|
|
|
|
|
|
|
|
130,000 |
|
|
|
|
6,464,900 |
|
|
|
|
999,950 |
|
|
|
|
36,000 |
|
|
|
|
10,372,755 |
|
|
|
Chairman, |
|
|
|
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|
|
|
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restricted |
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president and |
|
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stock units |
|
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|
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|
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|
chief executive |
|
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|
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|
2 |
|
|
|
|
109 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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officer |
|
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deferred |
|
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|
|
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|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
1,140,000 |
|
|
|
|
1,000,050 |
|
|
|
|
562,665 |
|
|
|
|
|
|
|
|
share units 130,000 |
|
|
|
5,623,800 |
|
|
|
|
900,000 |
|
|
|
|
34,200 |
|
|
|
|
9,260,801 |
|
|
|
|
|
|
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restricted |
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stock units |
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2 |
|
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86 |
|
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deferred share units |
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|
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|
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|
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|
|
2005 |
|
|
|
|
1,100,000 |
|
|
|
|
900,000 |
|
|
|
|
385,028 |
|
|
|
|
|
|
|
|
|
193,200 |
|
|
|
|
7,432,404 |
|
|
|
|
870,000 |
|
|
|
|
33,000 |
|
|
|
|
10,720,526 |
|
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restricted stock |
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units |
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3 |
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115 |
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|
|
|
|
|
|
|
|
|
|
|
deferred share units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
P.A. Smith |
|
|
|
2007 |
|
|
|
|
412,500 |
|
|
|
|
181,233 |
|
|
|
|
125,486 |
|
|
|
|
|
|
|
|
|
27,200 |
|
|
|
|
1,352,656 |
|
|
|
|
197,225 |
|
|
|
|
24,750 |
|
|
|
|
2,293,850 |
|
|
|
Controller and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
senior |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
vice-president, |
|
|
|
2006 |
|
|
|
|
404,167 |
|
|
|
|
197,267 |
|
|
|
|
111,279 |
|
|
|
|
|
|
|
|
|
35,100 |
|
|
|
|
1,518,426 |
|
|
|
|
193,050 |
|
|
|
|
24,250 |
|
|
|
|
2,448,439 |
|
|
|
finance and |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
administration |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
398,333 |
|
|
|
|
193,675 |
|
|
|
|
87,198 |
|
|
|
|
|
|
|
|
55,200 restricted |
|
|
|
2,123,544 |
|
|
|
|
193,125 |
|
|
|
|
23,900 |
|
|
|
|
3,019,775 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
R.L. Broiles (1) |
|
|
|
2007 |
|
|
|
U.S. 345,000 |
|
|
U.S. 159,000 |
|
|
U.S. 206,336 |
|
|
|
|
|
|
|
|
11,000 |
|
|
|
U.S. 967,120 |
|
|
U.S. 159,265 |
|
|
U.S. 22,950 |
|
|
U.S. 1,859,671 |
|
|
Senior |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
vice-president, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
resources division |
|
|
|
2006 |
|
|
|
U.S. 325,083 |
|
|
U.S. 159,200 |
|
|
U.S. 421,481 |
|
|
|
|
|
|
|
|
11,000 |
|
|
|
U.S. 815,760 |
|
|
U.S. 140,513 |
|
|
U.S. 21,705 |
|
|
U.S. 1,883,742 |
|
|
(from July 1, 2005) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
U.S. 159,000 |
|
|
U.S. 140,500 |
|
|
U.S. 112,214 |
|
|
|
|
|
|
|
|
11,000 |
|
|
|
U.S. 641,740 |
|
|
U.S. 116,253 |
|
|
U.S. 10,175 |
|
|
U.S. 1,179,882 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
shares |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
B.W. Livingston |
|
|
|
2007 |
|
|
|
|
342,916 |
|
|
|
|
157,574 |
|
|
|
|
75,274 |
|
|
|
|
|
|
|
|
|
22,000 |
|
|
|
|
1,094,060 |
|
|
|
|
158,900 |
|
|
|
|
10,287 |
|
|
|
|
1,839,011 |
|
|
|
Vice-president, |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
general counsel |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and
corporate |
|
|
|
2006 |
|
|
|
|
318,750 |
|
|
|
|
159,088 |
|
|
|
|
83,236 |
|
|
|
|
|
|
|
|
22,000 |
|
|
|
951,720 |
|
|
|
|
153,450 |
|
|
|
|
9,562 |
|
|
|
|
1,675,806 |
|
|
|
secretary |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
303,750 |
|
|
|
|
154,330 |
|
|
|
|
66,401 |
|
|
|
|
|
|
|
|
|
33,000 |
|
|
|
|
1,269,510 |
|
|
|
|
128,625 |
|
|
|
|
9,112 |
|
|
|
|
1,931,648 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
J.F. Kyle |
|
|
|
2007 |
|
|
|
|
366,166 |
|
|
|
|
122,083 |
|
|
|
|
103,405 |
|
|
|
|
|
|
|
|
|
19,000 |
|
|
|
|
944,870 |
|
|
|
|
119,000 |
|
|
|
|
21,970 |
|
|
|
|
1,677,494 |
|
|
|
Vice-president |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
and treasurer |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2006 |
|
|
|
|
365,000 |
|
|
|
|
119,145 |
|
|
|
|
124,081 |
|
|
|
|
|
|
|
|
|
20,800 |
|
|
|
|
899,808 |
|
|
|
|
112,500 |
|
|
|
|
21,900 |
|
|
|
|
1,642,434 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2005 |
|
|
|
|
364,166 |
|
|
|
|
112,500 |
|
|
|
|
90,821 |
|
|
|
|
|
|
|
|
|
33,900 |
|
|
|
|
1,304,133 |
|
|
|
|
171,375 |
|
|
|
|
21,850 |
|
|
|
|
2,064,845 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
restricted |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
stock units |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
40
|
|
|
(1) |
|
R.L. Broiles has been on a loan assignment from Exxon Mobil Corporation since July 1, 2005.
His compensation was paid to him directly by ExxonMobil 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 R.L. Broiles, consist of dividend
equivalent payments on restricted stock units, interest paid in respect of deferred
payments of bonuses and earnings bonus units and any costs associated with the personal use
of the company aircraft. There is no tax assistance from the company for taxes related to
personal use of the company aircraft. In 2007, the dividend equivalent payments were
$228,476 for T.J. Hearn, $64,476 for P.A. Smith, $38,285 for B.W. Livingston and $42,986
for J.F. Kyle. In 2007, the interest paid in respect of deferred payments of bonuses and
earnings bonus units was $335,446 for T.J. Hearn, $6,010 for P.A. Smith, $21,989 for B.W.
Livingston and $30,420 for J.F. Kyle. Also included is an earned benefits allowance. The
earned benefits allowance in 2007 was $70,000 for T.J. Hearn, $45,000 for P.A. Smith,
$15,000 for B.W. Livingston and $30,000 for J.F. Kyle. For R.L. Broiles, the U.S. dollar
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, R.L. Broiles paid to Exxon Mobil Corporation amounts that were approximate to
the income taxes that would have been imposed if he was resident in his originating country
of employment. For R.L. Broiles, the amount includes dividend equivalent payments on
restricted stock from Exxon Mobil Corporation. |
|
(4) |
|
The company has not granted stock options since 2002. The stock option plan is
described on page 44. |
|
(5) |
|
These values include the number of units granted under the companys restricted stock
unit plan and deferred share unit plan for selected executives described on pages 44 and 43
respectively. The number of restricted stock units and deferred share units for 2006 and
2007 are the number of units actually received. The numbers shown for restricted stock
units and deferred share units for 2005 represent three times the number of restricted
stock units and deferred share units received in those years before the three-for-one share
split in May 2006. The values of the restricted stock units shown are the number of units
multiplied by the closing price of the companys shares on the date of grant. The closing
price on the date of grant of the restricted stock units was $38.47 in 2005, $43.26 for
2006 and $49.73 for 2007 (all on a post-split basis). T.J. Hearn is the only senior
executive who holds deferred share units and he received additional deferred shares from
dividends on his existing deferred shares. The values of the deferred share units shown are
the number of such additional deferred share units multiplied by the year-end closing
price. R.L. Broiles participates in Exxon Mobil Corporations restricted stock plan under
which the grantee may receive restricted stock or restricted stock units (both of which are
referred to herein as restricted stock or restricted shares), which plan is similar to the
companys restricted stock unit plan. Under that plan, R.L. Broiles was granted 11,000
restricted shares in 2007, whose value on the date of grant (November 28, 2007) was
$967,120 U.S., based on a closing price of Exxon Mobil Corporation shares on the date of
grant of $87.92 U.S. |
|
(6) |
|
The table below shows the number and value of restricted stock units and deferred share
units held as of December 31, 2007. The numbers for restricted stock units and deferred
share units represent the total of the restricted stock units and deferred share units
received in 2006 and 2007 after the three-for-one share split in May 2006, plus three times
the number of restricted stock units and deferred share units received before the share
split and still held by the employee. The closing price on December 31, 2007 was $54.62.
R.L. Broiles participates in Exxon Mobil Corporations restricted stock plan, which is
similar to the companys restricted stock unit plan. Under that plan, R.L. Broiles holds
48,500 restricted shares whose value on December 31, 2007 was $4,543,965 U.S. based on a
closing price for Exxon Mobil Corporation shares on December 31, 2007 of $93.69 U.S. |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Restricted Stock Units |
|
|
Deferred Share Units |
|
|
Name |
|
|
Total (#) |
|
|
Total ($) |
|
|
Total (#) |
|
|
Total ($) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
T.J. Hearn |
|
|
714,800 |
|
|
39,042,376 |
|
|
306 |
|
|
16,714 |
|
|
P.A. Smith |
|
|
190,250 |
|
|
10,391,455 |
|
|
0 |
|
|
0 |
|
|
R.L. Broiles |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
B.W. Livingston |
|
|
119,750 |
|
|
6,540,745 |
|
|
0 |
|
|
0 |
|
|
J.F. Kyle |
|
|
126,500 |
|
|
6,909,430 |
|
|
0 |
|
|
0 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(7) |
|
Payouts were from 2006 earnings bonus units that reached maximum value of $1.75 per
unit in 2007. That plan is described on page 44. R.L. Broiles participates in Exxon Mobil
Corporations earnings bonus unit plan, which is similar to the companys earnings bonus
unit plan. |
|
(8) |
|
Amounts under All Other Compensation, except for R.L. Broiles, are the companys
contributions to the savings plan, which is a plan available to all employees. Under one of
the options of that plan to which the senior executives subscribe, except for R.L. Broiles,
the company matched employee contributions up to six percent of base salary per year;
however, an employee may elect to receive an enhanced pension under the companys pension
plan by foregoing three percent of the companys matching contributions. The plan is
intended to be primarily for retirement savings, although employees may withdraw their
contributions prior to retirement. For R.L. Broiles, the amount is Exxon Mobil
Corporations contributions to its employee savings plan. |
|
(9) |
|
Total Compensation for each of 2005, 2006 and 2007 consists of the total dollar value
of Salary, Bonus, Other Annual Compensation, Shares or Units Subject to Resale
Restrictions, LTIP Payouts and All Other Compensation for each such year. |
41
Earnings
Bonus Unit Plan awards in most recently completed financial year
The following table provides information on earnings bonus units granted in 2007 to the
named senior executives. The earnings bonus unit plan is described in more detail on page 44.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Performance |
|
|
|
|
|
|
|
|
Securities |
|
|
or Other |
|
|
Estimated Future Payouts Under |
|
|
Name |
|
|
Units or |
|
|
Period Until |
|
|
Non-Securities-Price Based Plans |
|
|
|
|
|
Other Rights |
|
|
Maturation or |
|
|
|
|
|
|
|
|
(#) |
|
|
Payout (1) |
|
|
Threshold |
|
|
Target |
|
|
Maximum |
|
|
|
|
|
|
|
|
|
|
|
($) |
|
|
($) (2) |
|
|
($) (2) |
|
|
T.J. Hearn |
|
|
444,400 |
|
|
Nov 20, 2012 |
|
|
0 |
|
|
2.25 |
|
|
2.25 |
|
|
P.A. Smith |
|
|
80,500 |
|
|
Nov 20, 2012 |
|
|
0 |
|
|
2.25 |
|
|
2.25 |
|
|
R.L. Broiles (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
B.W. Livingston |
|
|
70,000 |
|
|
Nov 20, 2012 |
|
|
0 |
|
|
2.25 |
|
|
2.25 |
|
|
J.F. Kyle |
|
|
54,200 |
|
|
Nov 20, 2012 |
|
|
0 |
|
|
2.25 |
|
|
2.25 |
|
|
|
|
|
(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 2007. |
|
(3) |
|
R.L. Broiles participates in Exxon Mobil Corporations earnings bonus unit plan which
is similar to the companys earnings bonus unit plan. In 2007, R.L Broiles was granted
31,800 units under that plan for which the maximum settlement value payable per earnings
bonus unit is $5.00 U.S. |
Aggregated option/SAR exercises during the most recently completed financial year and financial
year end option/SAR values
The following table provides information on the exercise in 2007 and the aggregate holdings
at the end of 2007 of incentive share units (referred to in the table as SARs) by the named
senior executives. The incentive share unit plan is described in more detail on page 43. The
number of incentive share units in the table below is equal to three times the number of
incentive share units held before the three-for-one share split in May 2006.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Securities |
|
|
Aggregate |
|
|
Unexercised |
|
|
Value of |
|
|
|
|
|
Acquired |
|
|
Value |
|
|
Options/SARs |
|
|
Unexercised |
|
|
Name |
|
|
on Exercise |
|
|
Realized |
|
|
at Financial |
|
|
in-the-Money |
|
|
|
|
|
(#) |
|
|
($) |
|
|
Year End |
|
|
Options/SARs |
|
|
|
|
|
|
|
|
|
|
|
(#) |
|
|
at Financial |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year End |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($) |
|
|
|
|
|
|
|
|
|
|
|
Exercisable |
|
|
Unexercisable |
|
|
Exercisable |
|
|
Unexercisable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(1) |
|
|
|
|
|
(1) |
|
|
T.J. Hearn |
|
|
|
|
|
2,711,250 |
|
|
0 |
|
|
0 |
|
|
0 |
|
|
0 |
|
|
P.A. Smith |
|
|
|
|
|
596,100 |
|
|
120,000 |
|
|
0 |
|
|
5,115,900 |
|
|
0 |
|
|
R.L. Broiles |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
B.W. Livingston |
|
|
|
|
|
0 |
|
|
0 |
|
|
0 |
|
|
0 |
|
|
0 |
|
|
J.F. Kyle |
|
|
|
|
|
0 |
|
|
0 |
|
|
0 |
|
|
0 |
|
|
0 |
|
|
|
|
|
(1) |
|
Unexercisable units are units for which the conditions for exercise have not been met. |
42
The following table provides information on the exercise in 2007 and the aggregate holdings
at the end of 2007 of stock options by the named senior executives. The stock option plan is
described in more detail on page 44.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Securities |
|
|
Aggregate |
|
|
Unexercised |
|
|
Value of |
|
|
|
|
|
Acquired |
|
|
Value |
|
|
Options/SARs |
|
|
Unexercised |
|
|
Name |
|
|
on Exercise |
|
|
Realized |
|
|
at Financial |
|
|
in-the-Money |
|
|
|
|
|
(#) (1) |
|
|
($) |
|
|
Year End |
|
|
Options/SARs |
|
|
|
|
|
|
|
|
|
|
|
(#) (1) |
|
|
at Financial |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year
End ($) |
|
|
|
|
|
|
|
|
|
|
|
Exercisable |
|
|
Unexercisable |
|
|
Exercisable |
|
|
Unexercisable |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(2) |
|
|
|
|
|
(2) |
|
|
T.J. Hearn |
|
|
10,002 |
|
|
296,272 |
|
|
154,998 |
|
|
0 |
|
|
6,063,522 |
|
|
0 |
|
|
P.A. Smith |
|
|
|
|
|
|
|
|
75,000 |
|
|
0 |
|
|
2,934,000 |
|
|
0 |
|
|
R.L. Broiles (3) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
B.W. Livingston |
|
|
15,000 |
|
|
512,255 |
|
|
30,000 |
|
|
0 |
|
|
1,173,600 |
|
|
0 |
|
|
J.F. Kyle |
|
|
57,000 |
|
|
1,790,530 |
|
|
0 |
|
|
0 |
|
|
0 |
|
|
0 |
|
|
|
|
|
(1) |
|
The number for the stock options represents three times the number of stock options
granted in 2002 before the three-for-one share split in May 2006 and still held by the
employee. |
|
(2) |
|
Unexercisable units are units for which the conditions for exercise have not been met. |
|
(3) |
|
At the end of 2007, R. L. Broiles held options to acquire 56,398 Exxon Mobil
Corporation shares of which all options were exercisable. The value of R.L. Broiles
exercisable options was $ 2,976,628 U.S. at the end of 2007. In 2007, R.L. Broiles
exercised 55,598 options and realized an aggregate value of $ 2,463,063 U.S.. |
Details of long-term and medium-term incentive compensation
Consistent with the companys compensation philosophy of being performance driven, long-term
incentive compensation is granted to retain selected employees and reward them for high
performance. The assessment of employee performance is conducted through the companys appraisal
program. The appraisal program is a disciplined annual program that assesses business performance
measures relevant to eligible employees and involves ranking of employee performance using a
consistent process throughout the organization at all levels. The number of units received by each
employee is tied to the performance of the employee in achieving these business performance
measures. The scope of the company program is determined by the overall performance of the company
each year.
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. 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. 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 and nonemployee directors whose decisions are considered to
have a direct effect on the long term financial performance of the company. They can elect to
receive all or part of their cash 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 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, in respect of unexercised 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. In 2007, no executive elected to receive deferred share units.
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.
43
Starting in 2001, a medium-term incentive compensation plan was introduced, called the
earnings bonus unit plan. This 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. If after five years the maximum settlement has not been reached, payout
will be prorated.
Under the stock option plan adopted by the company in April 2002, a total of 9,630,600
options, on a post share split basis, were granted to select key employees on April 30, 2002 for
the purchase of the companys common shares at an exercise price of $15.50 per share on a post
share split basis. All of the options are exercisable. Any unexercised options expire after April
29, 2012. As of February 14, 2008, there have been 5,028,645 common shares issued upon exercise of
stock options and 4,601,955 common shares are issuable upon future exercise of stock options. The
common shares that were issued and those that may be issued in the future represent about 1.1
percent of the companys currently outstanding common shares. The companys directors, officers and
vice-presidents as a group hold 6.8 percent of the unexercised stock options.
The maximum number of common shares that any one person may receive from the exercise of stock
options is 154,998 common shares, which is about 0.02 percent of the currently outstanding common
shares. Stock options may be exercised only during employment with the company except in the event
of death, disability or retirement. Also, stock options may be forfeited if the company believes
that the employee intends to terminate employment or if during employment or during the period of
24 months after the termination of employment the employee, without the consent of the company,
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 determine that stock options will not
be forfeited after the cessation of employment. Stock options cannot be assigned except in the case
of death.
The company may amend or terminate the incentive stock option plan as it in its sole
discretion determines appropriate. No such amendment or termination can be made to impair any
rights of stock option holders under the incentive stock option plan unless the stock option holder
consents, except in the event of (a) any adjustments to the share capital of the company or (b) a
take-over bid, amalgamation, combination, merger or other reorganization, sale or lease of assets,
or any liquidation, dissolution, or winding-up, involving the company. Appropriate adjustments may
be made by the company to: (i) the number of common shares that may be acquired on the exercise of
outstanding stock options; (ii) the exercise price of outstanding stock options; or (iii) the class
of shares that may be acquired in place of common shares on the exercise of outstanding stock
options in order to preserve proportionately the rights of the stock option holders and give proper
effect to the event.
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 the selected key employees and nonemployee directors directly with the interests
of shareholders. Each unit entitles the recipient the 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 unit plan was amended for units granted in 2002 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
1,713,488 units were granted on December 4, 2007.
There are 7,074,314 common shares issuable upon future exercise of restricted stock units,
which represent about 0.79 percent of the companys currently outstanding common shares. The
companys directors, officers and vice-presidents have available, as a group, 16 percent of the
common shares issuable under outstanding restricted stock units. The maximum number of common
shares that any one person may receive from the exercise of outstanding restricted stock units is
488,200 common shares, which is about 0.05 percent of the currently outstanding common shares.
Restricted stock units will be exercised only during employment except in the event of death,
disability or retirement. Also, restricted stock units may be forfeited if the company believes
that the employee intends to terminate employment or if during employment or during the period of
24 months after the termination of employment the employee, without the consent of the company,
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 determine that restricted stock units
will not be forfeited after the cessation of employment. Restricted stock units cannot be assigned.
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 restricted stock unit. Effective December 31, 2004, the restricted stock
unit plan was amended by the company to
44
provide that on retirement the company shall determine whether the employees restricted stock
units will not be forfeited. Effective August 2, 2006, the restricted stock unit plan was amended
by the company to change the exercise price under the plan from a single days closing price to a
five-day average and to change exercise dates under the plan from December 31 to December 4 with
respect to restricted stock units granted in prior years. Shareholder approval for these changes
was not required by the Toronto Stock Exchange.
Payments to Employees Who Retire
Pension Plan Table
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Remuneration for |
|
|
|
|
|
determining |
|
|
Estimated undiscounted payments on retirement |
|
|
payments |
|
|
at the age of 65 after years of service indicated below ($) (1) |
|
|
on retirement |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
($) |
|
|
20 Years |
|
|
25 Years |
|
|
30 Years |
|
|
35 Years |
|
|
40 Years |
|
|
45 Years |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
100,000
|
|
|
|
32,000 |
|
|
|
|
40,000 |
|
|
|
|
48,000 |
|
|
|
|
56,000 |
|
|
|
|
64,000 |
|
|
|
|
72,000 |
|
|
|
200,000
|
|
|
|
64,000 |
|
|
|
|
80,000 |
|
|
|
|
96,000 |
|
|
|
|
112,000 |
|
|
|
|
128,000 |
|
|
|
|
144,000 |
|
|
|
300,000
|
|
|
|
96,000 |
|
|
|
|
120,000 |
|
|
|
|
144,000 |
|
|
|
|
168,000 |
|
|
|
|
192,000 |
|
|
|
|
216,000 |
|
|
|
400,000
|
|
|
|
128,000 |
|
|
|
|
160,000 |
|
|
|
|
192,000 |
|
|
|
|
224,000 |
|
|
|
|
256,000 |
|
|
|
|
288,000 |
|
|
|
500,000
|
|
|
|
160,000 |
|
|
|
|
200,000 |
|
|
|
|
240,000 |
|
|
|
|
280,000 |
|
|
|
|
320,000 |
|
|
|
|
360,000 |
|
|
|
600,000
|
|
|
|
192,000 |
|
|
|
|
240,000 |
|
|
|
|
288,000 |
|
|
|
|
336,000 |
|
|
|
|
384,000 |
|
|
|
|
432,000 |
|
|
|
800,000
|
|
|
|
256,000 |
|
|
|
|
320,000 |
|
|
|
|
384,000 |
|
|
|
|
448,000 |
|
|
|
|
512,000 |
|
|
|
|
576,000 |
|
|
|
1,000,000
|
|
|
|
320,000 |
|
|
|
|
400,000 |
|
|
|
|
480,000 |
|
|
|
|
560,000 |
|
|
|
|
640,000 |
|
|
|
|
720,000 |
|
|
|
1,500,000
|
|
|
|
480,000 |
|
|
|
|
600,000 |
|
|
|
|
720,000 |
|
|
|
|
840,000 |
|
|
|
|
960,000 |
|
|
|
|
1,080,000 |
|
|
|
2,000,000
|
|
|
|
640,000 |
|
|
|
|
800,000 |
|
|
|
|
960,000 |
|
|
|
|
1,120,000 |
|
|
|
|
1,280,000 |
|
|
|
|
1,440,000 |
|
|
|
2,500,000
|
|
|
|
800,000 |
|
|
|
|
1,000,000 |
|
|
|
|
1,200,000 |
|
|
|
|
1,400,000 |
|
|
|
|
1,600,000 |
|
|
|
|
1,800,000 |
|
|
|
3,000,000
|
|
|
|
960,000 |
|
|
|
|
1,200,000 |
|
|
|
|
1,440,000 |
|
|
|
|
1,680,000 |
|
|
|
|
1,920,000 |
|
|
|
|
2,160,000 |
|
|
|
3,500,000
|
|
|
|
1,120,000 |
|
|
|
|
1,400,000 |
|
|
|
|
1,680,000 |
|
|
|
|
1,960,000 |
|
|
|
|
2,240,000 |
|
|
|
|
2,520,000 |
|
|
|
4,000,000
|
|
|
|
1,280,000 |
|
|
|
|
1,600,000 |
|
|
|
|
1,920,000 |
|
|
|
|
2,240,000 |
|
|
|
|
2,560,000 |
|
|
|
|
2,880,000 |
|
|
|
|
|
|
(1) |
|
Payment calculations exclude the effect of integration with CPP/QPP and OAS. |
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 (except for R.L. Broiles), 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
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 page 40 corresponds generally to the salary, bonus compensation and
bonus compensation amount elected to be received as deferred share units in that table. The
aggregate maximum settlement value that could be paid for earnings bonus units granted shown in the
table on page 42 is also included in the employees final three year average earnings for the
year of grant of such units. As of February 14, 2008, the number of completed years of service with
Imperial Oil Limited used to determine payments on retirement was 41 for T.J. Hearn, 27 for P.A.
Smith and 23 for B.W. Livingston. J.F. Kyle retired from the company on January 31, 2008 with 31
completed years of service.
R.L. Broiles is not a member of the companys pension plan, but is a member of Exxon Mobil
Corporations pension plan. Under that plan, R.L. Broiles has 28 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 extended on a full year basis and bonus
compensation in the summary compensation table on page 40, which total may be applied to the
pension plan table above but with the dollars in that table representing U.S. rather than Canadian
dollars.
45
Executive Pension Value Disclosure (1)(2)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accrued |
|
|
Annual Pension |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current 2007 |
|
|
Obligations at |
|
|
Benefit Payable at |
|
|
Age |
|
|
|
|
|
Normal |
|
|
|
|
|
Service Cost |
|
|
Dec. 31, 2007 |
|
|
age 65 |
|
|
(at Dec. 31, |
|
|
Credited |
|
|
Retirement |
|
|
Name |
|
|
($)(3) |
|
|
(4) |
|
|
(5) |
|
|
2007) |
|
|
Service |
|
|
Age |
|
|
T.J. Hearn |
|
|
515,200 |
|
|
24,482,600 |
|
|
2,144,400 |
|
|
63 |
|
|
41 |
|
|
65 |
|
|
P.A. Smith |
|
|
133,600 |
|
|
3,624,900 |
|
|
474,000 |
|
|
54 |
|
|
27 |
|
|
65 |
|
|
R.L. Broiles |
|
|
|
|
|
|
|
|
|
|
|
50 |
|
|
28 |
|
|
65 |
|
|
B.W. Livingston |
|
|
122,000 |
|
|
2,522,900 |
|
|
382,800 |
|
|
53 |
|
|
23 |
|
|
65 |
|
|
J.F. Kyle |
|
|
90,100 |
|
|
3,535,400 |
|
|
298,800 |
|
|
64 |
|
|
31 |
|
|
65 |
|
|
|
|
|
(1) |
|
Pension benefits reflected in these tables do not vest until the named executive
officer reaches age 55. In the case of T.J. Hearn and J.F. Kyle, their accrued pension to
date is already vested. |
|
(2) |
|
Amounts shown include pension benefits under Imperial Oil Limiteds registered pension
plan and supplemental retirement plans, other than for R.L. Broiles, who participates in
Exxon Mobil Corporations pension plan and supplemental pension plan. Under Exxon Mobil
Corporations pension plan and supplemental pension plan, R.L. Broiles current 2007
service cost was $237,418 U.S., the accrued obligations at December 31, 2007 with respect
to R.L. Broiles was $1,469,568 U.S. and his annual pension benefit payable at age 65 will
be $450,425 U.S. |
|
(3) |
|
Service cost is the actuarial value of benefits earned under the pension benefit
formula for the calendar year 2007. Amounts shown are consistent with disclosure in Note 6
of the 2007 Consolidated Financial Statements. |
|
(4) |
|
Accrued obligation is the value of the projected benefit obligation for pension earned
for service to December 31, 2007. The accrued obligation increases with age and is
significantly impacted by changes in the discount rate. Amounts shown are consistent with
disclosure in Note 6 of the 2007 Consolidated Financial Statements. |
|
(5) |
|
Amounts in this column are based on current compensation levels and assume accrued
years of service to age 65 for each of the named executive officers. |
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
14, 2008, 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 626,939,795 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 14, 2008, J.F.Kyle was the owner of 12,585 common shares of the company and held
126,500 restricted stock units of the company. As of February 14, 2008, B.W.Livingston was the
owner of 5,908 common shares of the company, held options to acquire 30,000 common shares of the
company and held 119,750 restricted stock units of the company.
The directors and the senior executives of the company, whose compensation for the year ended
December 31, 2007 is described on pages 39 through 41, consist of 11 persons, who, as a group, own
beneficially 176,722 common shares of the company, being approximately 0.02 percent of the total
number of outstanding shares of the company, and 150,926 shares of Exxon Mobil Corporation
(including 98,750 restricted shares). 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 259,998 common shares of the
company and held restricted stock units to acquire 827,100 common shares of the company, as of
February 14, 2008.
46
Equity Compensation Plan Information
The following table provides information on the common shares of the company that may be
issued as of the end of 2007 pursuant to compensation plans of the company.
|
|
|
|
|
|
|
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|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Plan category |
|
|
Number of securities to |
|
|
Weighted-average |
|
|
Number of securities |
|
|
|
|
|
be issued upon exercise |
|
|
exercise price of |
|
|
remaining available for future |
|
|
|
|
|
of outstanding options, |
|
|
outstanding options, |
|
|
issuance under equity |
|
|
|
|
|
warrants and rights |
|
|
warrants and rights |
|
|
compensation plans (excluding |
|
|
|
|
|
(3) |
|
|
($) |
|
|
securities reflected in |
|
|
|
|
|
|
|
|
|
|
|
column (a)) |
|
|
|
|
|
|
|
|
|
|
|
(3) |
|
|
|
|
|
(a) |
|
|
(b) |
|
|
(c) |
|
|
Equity compensation |
|
|
4,728,780 |
|
|
15.50 |
|
|
0 |
|
|
plans approved by
security holders (1) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity compensation |
|
|
7,074,314 |
|
|
|
|
|
3,425,686 |
|
|
plans not approved
by security holders (2) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total |
|
|
11,803,094 |
|
|
15.50 |
|
|
3,425,686 |
|
|
|
|
|
(1) |
|
This is a stock option plan, which is described on page 44.
|
|
(2) |
|
This is a restricted stock unit plan, which is described on page 44. |
|
(3) |
|
The number of securities reserved for the stock option plan represents three times the
number of stock options granted in 2002 before the three-for-one share split in May 2006
and still outstanding. The number of securities reserved for the restricted stock unit plan
represents the securities reserved for restricted stock units issued in 2006 and 2007 after
the three-for-one share split in May 2006, plus three times the number of securities
reserved for restricted stock units issued before the share split and still outstanding.
The weighted average exercise price of the outstanding stock options of $15.50 was
determined on a post share split basis. |
Item 13. Certain Relationships and Related Transactions.
On June 23, 2006, the company implemented another 12-month normal course share-purchase
program under which it purchased 47,868,663 of its outstanding shares between June 23, 2006 and
June 22, 2007. On June 25, 2007, another 12-month normal course program was implemented under
which the company may purchase up to 46,459,967 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 2007, such purchases
cost $2,358 million, of which $1,615 million was received by Exxon Mobil Corporation.
During 2003, the company borrowed $818 million from an affiliated company of Exxon Mobil
Corporation under two long term loan agreements at interest equivalent to Canadian market rates.
Interest on the loans in 2007 was $33 million. The average effective interest rate for the loans
was 4.52 percent for 2007. These loans were repaid in 2007.
The amounts of purchases and sales by the company and its subsidiaries for other transactions
in 2007 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $3,525 million
and $1,772 million, respectively. These transactions 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, natural gas, petroleum and chemical products, as well as transportation, technical and
engineering services. Transactions with Exxon Mobil Corporation also included amounts paid and
received in connection with the companys participation in a number of natural resources activities
conducted jointly in Canada. The company has agreements with affiliates of Exxon Mobil Corporation
to provide computer and customer support services to the company and to share common business and
operational support services to allow the companies to consolidate duplicate work and systems. The
company has a contractual agreement with an affiliate of Exxon Mobil Corporation in Canada to
operate the Western Canada production properties owned by ExxonMobil. There are no asset ownership
changes. During 2007, the company entered into agreements with Exxon Mobil Corporation and one of
its affiliated companies that provide for the delivery of management, business and technical
services to Syncrude Canada Ltd. by ExxonMobil.
47
Item 14. Principal Accountant Fees and Services.
Auditor Fees
The aggregate fees of the companys auditor for professional services rendered for the audit
of the companys financial statements and other services for the fiscal years ended December 31,
2007 and December 31, 2006 were as follows:
|
|
|
|
|
|
|
|
|
Dollars (thousands) |
|
2007 |
|
2006 |
|
|
|
Audit Fees
|
|
|
1,117 |
|
|
|
1,117 |
|
Audit-Related Fees
|
|
|
62 |
|
|
|
62 |
|
Tax Fees
|
|
|
942 |
|
|
|
815 |
|
All Other Fees
|
|
|
Nil |
|
|
|
Nil |
|
|
|
|
Total Fees
|
|
|
2,121 |
|
|
|
1,994 |
|
|
|
|
Audit fees include the audit of the companys annual financial statements and internal control
over financial reporting, and a review of the first three quarterly financial statements in 2007.
Audit-related fees include other assurance services including the audit of the companys
retirement plan and royalty statement audits for oil and gas producing entities.
Tax fees are mainly tax services for employees on foreign loan assignments.
The company did not engage the auditor for any other services.
The audit committee recommends the external auditor to be appointed by the shareholders, fixes
its remuneration and oversees its work. The audit committee also approves the proposed current year
audit program of the external auditor, 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 external
auditor after considering the effect of such services on their independence.
All of the services rendered by the auditor to the company were approved by the audit
committee.
48
PART IV
Item 15. Exhibits and Financial Statement Schedules.
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 (3.1) to the companys Form 8-Q filed on May 3, 2006 (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)). |
49
|
(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). |
50
|
(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) |
|
Form of Earnings Bonus Units (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, 2003 (File No. 0-12014)) and Earnings Bonus 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, 2002 (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
(Incorporated herein by reference to Exhibit (10)(iii)(A)(8) of the companys Annual
Report on Form 10-K for the year ended December 31, 2003 (File No. 0-12014)). |
|
|
(9) |
|
Restricted Stock Unit Plan and general form for Restricted Stock Units,
as amended effective December 31, 2004 (Incorporated herein by reference to Exhibit
99.1 of the companys Form 8-K dated December 31, 2004 (File No. 0-12014)). |
|
|
(10) |
|
Amended Restricted Stock Unit Plan with respect to Restricted Stock Units
granted in 2002, as amended effective August 4, 2006 (Incorporated herein by
reference to Exhibit 99.10(III)(A)(1) of the companys Quarterly Report on Form 10-Q
for the quarter ended September 30, 2006 (File No. 0-12014)). |
|
|
(11) |
|
Amended Restricted Stock Unit Plan with respect to Restricted Stock Units
granted in 2003, as amended effective August 4, 2006 (Incorporated herein by
reference to Exhibit 99.10(III)(A)(2) of the companys Quarterly Report on Form 10-Q
for the quarter ended September 30, 2006 (File No. 0-12014)). |
|
|
(12) |
|
Amended Restricted Stock Unit Plan with respect to Restricted Stock Units
granted in 2004 and 2005, as amended effective August 4, 2006 (Incorporated herein
by reference to Exhibit 99.10(III)(A)(3) of the companys Quarterly Report on Form
10-Q for the quarter ended September 30, 2006 (File No. 0-12014)). |
|
|
(13) |
|
Amended Restricted Stock Unit Plan with respect to Restricted Stock Units
granted in 2006 and subsequent years, as amended effective August 4, 2006
(Incorporated herein by reference to Exhibit 99.10(III)(A)(4) of the companys
Quarterly Report on Form 10-Q for the quarter ended September 30, 2006 (File No.
0-12014)). |
|
|
(14) |
|
Amended Restricted Stock Unit Plan with respect to Restricted Stock Units
granted in 2002, as amended effective February 1, 2007 (Incorporated herein by
reference to Exhibit 99.1 of the companys Form 8-K filed on February 2, 2007 (File
No. 0-121014)). |
|
(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, 2006. |
|
(23)(ii) |
|
(A) Consent of Independent Registered Public Accounting Firm (PricewaterhouseCoopers
LLP). |
|
|
(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, 237 Fourth Avenue S.W., Calgary, Alberta, Canada T2P 3M9,
and payment of processing and mailing costs.
51
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 February 26, 2008 by the
undersigned, thereunto duly authorized.
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Imperial Oil Limited |
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By
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/s/ T.J. Hearn |
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(Timothy J. Hearn, Chairman of the Board |
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and Chief Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below on February 26, 2008 by the following persons on behalf of the registrant and in the
capacities indicated.
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Signature
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Title |
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Chairman of the Board and |
/s/ T.J. Hearn
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Chief Executive Officer and Director |
(Timothy J. Hearn)
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(Principal Executive Officer) |
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Senior Vice-President, |
/s/ Paul A. Smith
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Finance and Administration, and Treasurer |
(Paul A. Smith)
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and Director |
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(Principal Accounting Officer and |
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Principal Financial Officer) |
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/s/ R.L. Broiles
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Director |
(Randy L. Broiles)
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/s/ B.H. March
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Director |
(Bruce H. March)
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/s/ J.M. Mintz
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Director |
(Jack M. Mintz)
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/s/ Roger Phillips
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Director |
(Roger Phillips)
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/s/ J.F. Shepard
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Director |
(James F. Shepard)
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/s/ Sheelagh D. Whittaker
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Director |
(Sheelagh D. Whittaker)
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/s/ V.L. Young
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Director |
(Victor L. Young)
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52
INDEX TO FINANCIAL STATEMENTS
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Pages in this |
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Report |
Managements report on internal control over financial reporting |
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F-2 |
Report of independent registered public accounting firm |
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F-2 |
Financial statements: |
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|
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F-3 |
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F-4 |
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F-5 |
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F-6 |
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F-7 F-20 |
F-1
MANAGEMENTS REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the companys chief executive officer and principal accounting officer
and principal financial officer, is responsible for establishing and maintaining adequate internal
control over the companys financial reporting. Management conducted an evaluation of the
effectiveness of internal control over financial reporting based on the Internal Control -
Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission. Based on this evaluation, management concluded that Imperial Oil Limiteds internal
control over financial reporting was effective as of December 31, 2007.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the
effectiveness of the companys internal control over financial reporting as of December 31, 2007,
as stated in their report which is included herein.
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/s/ T.J. Hearn
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/s/ Paul A. Smith |
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P.A. Smith
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Chairman and chief executive officer
|
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Senior vice-president, finance and administration, and treasurer |
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(Principal accounting officer and principal financial officer) |
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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of Imperial Oil Limited
We have completed integrated audits of Imperial Oil Limiteds 2007, 2006 and 2005 consolidated
financial statements and of its internal control over financial reporting as of December 31, 2007.
Our opinions, based on our audits, are presented below.
Consolidated financial statements
In our opinion, the accompanying consolidated financial statements in the Form 10-K present
fairly, in all material respects, the financial position of Imperial Oil Limited and its
subsidiaries at December 31, 2007 and December 31, 2006, and the results of their operations and
their cash flows for each of the years in the three year period ended December 31, 2007 in
conformity with accounting principles generally accepted in the United States of America. 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 of
these statements in accordance with the standards of the Public Company Accounting Oversight Board
(United States). Those standards require that we plan and perform the audit to obtain reasonable
assurance about whether the financial statements are free of material misstatement. An audit of
financial statements includes examining, on a test basis, evidence supporting the amounts and
disclosures in the financial statements, assessing the accounting principles used and significant
estimates made by management, and evaluating the overall financial statement presentation. We
believe that our audits provide a reasonable basis for our opinion.
Internal control over financial reporting
Also, in our opinion, the Company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2007, based on criteria established in Internal
Control - Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway
Commission (COSO). The Companys management is responsible for maintaining effective internal
control over financial reporting and for its assessment of the effectiveness of internal control
over financial reporting, included in the accompanying Managements report on internal control over
financial reporting. Our responsibility is to express an opinion on the effectiveness of the
Companys internal control over financial reporting based on our audit. We conducted our audit of
internal control over financial reporting in accordance with the standards of the Public Company
Accounting Oversight Board (United States). Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial
reporting was maintained in all material respects. An audit of internal control over financial
reporting includes obtaining an understanding of internal control over financial reporting,
assessing the risk that a material weakness exists, testing and evaluating the design and operating
effectiveness of internal control based on the assessed risk, and performing such other procedures
as we consider necessary in the circumstances. We believe that our audit provides a reasonable
basis for our opinion.
A companys internal control over financial reporting is a process designed to provide
reasonable assurance regarding the reliability of financial reporting and the preparation of
financial statements for external purposes in accordance with generally accepted accounting
principles. A companys internal control over financial reporting includes those policies and
procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately
and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide
reasonable assurance that transactions are recorded as necessary to permit preparation of financial
statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and
directors of the company; and (iii) provide reasonable assurance regarding prevention or timely
detection of unauthorized acquisition, use, or disposition of the companys assets that could have
a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent
or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are
subject to the risk that controls may become inadequate because of changes in conditions, or that
the degree of compliance with the policies or procedures may deteriorate.
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/s/ PricewaterhouseCoopers LLP |
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Calgary, Alberta, Canada |
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February 26, 2008 |
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F-2
Consolidated statement of income
|
|
|
|
|
|
|
|
|
|
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|
millions of Canadian dollars |
|
|
|
|
|
|
|
|
|
For the years ended December 31 |
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
Revenues and other income |
|
|
|
|
|
|
|
|
|
|
|
|
Operating revenues (a)(b)(c) |
|
|
25,069 |
|
|
|
24,505 |
|
|
|
27,797 |
|
Investment and other income (note 10) |
|
|
374 |
|
|
|
283 |
|
|
|
417 |
|
|
Total revenues and other income |
|
|
25,443 |
|
|
|
24,788 |
|
|
|
28,214 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
106 |
|
|
|
32 |
|
|
|
43 |
|
Purchases of crude oil and products (b)(d) |
|
|
14,026 |
|
|
|
13,793 |
|
|
|
17,168 |
|
Production and manufacturing (e) |
|
|
3,474 |
|
|
|
3,446 |
|
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|
3,327 |
|
Selling and general |
|
|
1,335 |
|
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|
1,284 |
|
|
|
1,577 |
|
Federal excise tax (a) |
|
|
1,307 |
|
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|
1,274 |
|
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|
1,278 |
|
Depreciation and depletion |
|
|
780 |
|
|
|
831 |
|
|
|
895 |
|
Financing costs (note 14)(f) |
|
|
36 |
|
|
|
28 |
|
|
|
8 |
|
|
Total expenses |
|
|
21,064 |
|
|
|
20,688 |
|
|
|
24,296 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income before income taxes |
|
|
4,379 |
|
|
|
4,100 |
|
|
|
3,918 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Income taxes (note 5) |
|
|
1,191 |
|
|
|
1,056 |
|
|
|
1,318 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
3,188 |
|
|
|
3,044 |
|
|
|
2,600 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Per-share information (Canadian dollars) |
|
|
|
|
|
|
|
|
|
|
|
|
Net income per common share - basic (note 12) |
|
|
3.43 |
|
|
|
3.12 |
|
|
|
2.54 |
|
Net income per common share - diluted (note 12) |
|
|
3.41 |
|
|
|
3.11 |
|
|
|
2.53 |
|
Dividends |
|
|
0.35 |
|
|
|
0.32 |
|
|
|
0.31 |
|
|
(a) |
|
Operating revenues include federal excise tax of $1,307 million (2006 - $1,274 million, 2005
- $1,278 million). |
|
(b) |
|
Operating revenues in 2005 included $4,894 million for purchases/sales contracts with the
same counterparty. Associated costs were included in purchases of crude oil and products.
Effective January 1, 2006, these purchases/sales were recorded on a net basis with no
resulting impact on net income, (note 1). |
|
(c) |
|
Operating revenues include amounts from related parties of $1,772 million (2006 - $1,955
million, 2005 - $1,346 million), (note 16). |
|
(d) |
|
Purchases of crude oil and products include amounts from related parties of $3,331 million
(2006 - $3,937 million, 2005 - $3,887 million), (note 16). |
|
(e) |
|
Production and manufacturing expenses include amounts to related parties of $194 million
(2006 - $156 million, 2005 - $102 million), (note 16). |
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(f) |
|
Financing costs include amounts to related parties of $32 million (2006 - $33 million, 2005 -
$22 million), (note 16). |
The information on pages F-7 through F-20 is an integral part of these consolidated financial
statements.
F-3
Consolidated statement of cash flows
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars |
|
|
|
|
|
|
|
|
|
Inflow/(outflow) |
|
|
|
|
|
|
|
|
|
For the years ended December 31 |
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
Operating activities |
|
|
|
|
|
|
|
|
|
|
|
|
Net income |
|
|
3,188 |
|
|
|
3,044 |
|
|
|
2,600 |
|
Adjustments for non-cash items: |
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and depletion |
|
|
780 |
|
|
|
831 |
|
|
|
895 |
|
(Gain)/loss on asset sales, after tax |
|
|
(156) |
|
|
|
(96) |
|
|
|
(233) |
|
Deferred income taxes and other |
|
|
16 |
|
|
|
254 |
|
|
|
(116) |
|
Changes in operating assets and liabilities: |
|
|
|
|
|
|
|
|
|
|
|
|
Accounts receivable |
|
|
(261) |
|
|
|
203 |
|
|
|
(414) |
|
Inventories and prepaids |
|
|
13 |
|
|
|
(97) |
|
|
|
(67) |
|
Income taxes payable |
|
|
(77) |
|
|
|
(225) |
|
|
|
304 |
|
Accounts payable |
|
|
250 |
|
|
|
(86) |
|
|
|
644 |
|
All other
items - net (a) |
|
|
(127) |
|
|
|
(241) |
|
|
|
(162) |
|
|
Cash from operating activities |
|
|
3,626 |
|
|
|
3,587 |
|
|
|
3,451 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Investing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Additions to property, plant and equipment and intangibles |
|
|
(899) |
|
|
|
(1,177) |
|
|
|
(1,432) |
|
Proceeds from asset sales |
|
|
279 |
|
|
|
212 |
|
|
|
440 |
|
|
Cash from (used in) investing activities |
|
|
(620) |
|
|
|
(965) |
|
|
|
(992) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Financing activities |
|
|
|
|
|
|
|
|
|
|
|
|
Short-term
debt - net |
|
|
(65) |
|
|
|
72 |
|
|
|
18 |
|
Repayment of long-term debt |
|
|
(1,726) |
|
|
|
(74) |
|
|
|
(21) |
|
Long-term debt issued |
|
|
500 |
|
|
|
|
|
|
|
|
|
Issuance of common shares under stock option plan |
|
|
12 |
|
|
|
10 |
|
|
|
38 |
|
Common shares purchased (note 12) |
|
|
(2,358) |
|
|
|
(1,818) |
|
|
|
(1,795) |
|
Dividends paid |
|
|
(319) |
|
|
|
(315) |
|
|
|
(317) |
|
|
Cash from (used in) financing activities |
|
|
(3,956) |
|
|
|
(2,125) |
|
|
|
(2,077) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Increase (decrease) in cash |
|
|
(950) |
|
|
|
497 |
|
|
|
382 |
|
Cash at beginning of year |
|
|
2,158 |
|
|
|
1,661 |
|
|
|
1,279 |
|
|
Cash at end of year (b) |
|
|
1,208 |
|
|
|
2,158 |
|
|
|
1,661 |
|
|
(a) |
|
Includes contribution to registered pension plans of $163 million (2006 - $395 million, 2005
- $350 million). |
|
(b) |
|
Cash is composed of cash in bank and cash equivalents at cost. Cash equivalents are all
highly liquid securities with maturity of three months or less when purchased. |
The information on pages F-7 through F-20 is an integral part of these consolidated financial
statements.
F-4
Consolidated balance sheet
|
|
|
|
|
|
|
|
|
millions of Canadian dollars |
|
|
|
|
|
|
At December 31 |
|
2007 |
|
|
2006 |
|
|
Assets |
|
|
|
|
|
|
|
|
Current assets |
|
|
|
|
|
|
|
|
Cash |
|
|
1,208 |
|
|
|
2,158 |
|
Accounts receivable, less estimated doubtful amounts |
|
|
2,132 |
|
|
|
1,871 |
|
Inventories of crude oil and products (note 13) |
|
|
566 |
|
|
|
556 |
|
Materials, supplies and prepaid expenses |
|
|
128 |
|
|
|
151 |
|
Deferred income tax assets (note 5) |
|
|
660 |
|
|
|
573 |
|
|
Total current assets |
|
|
4,694 |
|
|
|
5,309 |
|
Long-term receivables, investments and other long-term assets |
|
|
766 |
|
|
|
104 |
|
Property, plant and equipment,
less accumulated depreciation and depletion (note 3) |
|
|
10,561 |
|
|
|
10,457 |
|
Goodwill (note 3) |
|
|
204 |
|
|
|
204 |
|
Other intangible assets, net |
|
|
62 |
|
|
|
67 |
|
|
Total assets (note 3) |
|
|
16,287 |
|
|
|
16,141 |
|
|
|
|
|
|
|
|
|
|
|
Liabilities |
|
|
|
|
|
|
|
|
Current liabilities |
|
|
|
|
|
|
|
|
Short-term debt |
|
|
105 |
|
|
|
171 |
|
Accounts payable and accrued liabilities (a) |
|
|
3,335 |
|
|
|
3,080 |
|
Income taxes payable |
|
|
1,498 |
|
|
|
1,190 |
|
Current portion of long-term debt (b) |
|
|
3 |
|
|
|
907 |
|
|
Total current liabilities |
|
|
4,941 |
|
|
|
5,348 |
|
Long-term debt (note 4)(c) |
|
|
38 |
|
|
|
359 |
|
Other long-term obligations (note 7) |
|
|
1,914 |
|
|
|
1,683 |
|
Deferred income tax liabilities (note 5) |
|
|
1,471 |
|
|
|
1,345 |
|
|
Total liabilities |
|
|
8,364 |
|
|
|
8,735 |
|
|
|
|
|
|
|
|
|
|
|
Commitments and contingent liabilities (note 11) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity |
|
|
|
|
|
|
|
|
Common shares at stated value (note 12)(d) |
|
|
1,600 |
|
|
|
1,677 |
|
Earnings reinvested |
|
|
7,071 |
|
|
|
6,462 |
|
Accumulated other comprehensive income |
|
|
(748) |
|
|
|
(733) |
|
|
Total shareholders equity |
|
|
7,923 |
|
|
|
7,406 |
|
|
|
|
|
|
|
|
|
|
|
Total liabilities and shareholders equity |
|
|
16,287 |
|
|
|
16,141 |
|
|
(a) |
|
Accounts payable and accrued liabilities include amounts to related parties of $260 million
(2006 - $151 million), (note 16). |
|
(b) |
|
Current portion of long-term debt in 2006 included $500 million to related parties. There is
no current portion of long-term debt to related parties in 2007, (note 4). |
|
(c) |
|
Long-term debt in 2006 included $318 million to related parties. There is no long-term debt
to related parties in 2007, (note 4). |
|
(d) |
|
Number of common shares outstanding was 903 million (2006 - 953 million), (note 12). |
The information on pages F-7 through F-20 is an integral part of these consolidated financial
statements.
Approved by the directors
|
|
|
/s/ T.J. Hearn
|
|
/s/ Paul A. Smith |
Chairman, and
|
|
Senior vice-president, |
chief executive officer
|
|
finance and administration, and treasurer |
F-5
Consolidated statement of shareholders equity
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars |
|
|
|
|
|
|
|
|
|
At December 31 |
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
Common shares at stated value (note 12) |
|
|
|
|
|
|
|
|
|
|
|
|
At beginning of year |
|
|
1,677 |
|
|
|
1,747 |
|
|
|
1,801 |
|
Issued under the stock option plan |
|
|
12 |
|
|
|
10 |
|
|
|
38 |
|
Share purchases at stated value |
|
|
(89) |
|
|
|
(80) |
|
|
|
(92) |
|
|
At end of year |
|
|
1,600 |
|
|
|
1,677 |
|
|
|
1,747 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Earnings reinvested |
|
|
|
|
|
|
|
|
|
|
|
|
At beginning of year |
|
|
6,462 |
|
|
|
5,466 |
|
|
|
4,889 |
|
Cumulative effect of accounting change (note 2) |
|
|
14 |
|
|
|
|
|
|
|
|
|
Net income for the year |
|
|
3,188 |
|
|
|
3,044 |
|
|
|
2,600 |
|
Share purchases in excess of stated value |
|
|
(2,269) |
|
|
|
(1,737) |
|
|
|
(1,703) |
|
Dividends |
|
|
(324) |
|
|
|
(311) |
|
|
|
(320) |
|
|
At end of year |
|
|
7,071 |
|
|
|
6,462 |
|
|
|
5,466 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Accumulated other comprehensive income |
|
|
|
|
|
|
|
|
|
|
|
|
At beginning of year |
|
|
(733) |
|
|
|
(580) |
|
|
|
(368) |
|
Post-retirement benefits liability adjustment (note 6) |
|
|
(87) |
|
|
|
(733) |
|
|
|
|
|
Amortization
of post-retirement benefits liability adjustment included in net periodic benefit cost |
|
|
72 |
|
|
|
|
|
|
|
|
|
Minimum pension liability adjustment (note 6) |
|
|
|
|
|
|
580 |
|
|
|
(212) |
|
|
At end of year |
|
|
(748) |
|
|
|
(733) |
|
|
|
(580) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shareholders equity at end of year |
|
|
7,923 |
|
|
|
7,406 |
|
|
|
6,633 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Comprehensive income for the year |
|
|
|
|
|
|
|
|
|
|
|
|
Net income for the year |
|
|
3,188 |
|
|
|
3,044 |
|
|
|
2,600 |
|
Post-retirement benefits liability adjustment (note 18) |
|
|
(15) |
|
|
|
|
|
|
|
|
|
Minimum pension liability adjustment (note 18) |
|
|
|
|
|
|
334 |
|
|
|
(212) |
|
|
Total comprehensive income for the year |
|
|
3,173 |
|
|
|
3,378 |
|
|
|
2,388 |
|
|
The information on pages F-7 through F-20 is an integral part of these consolidated financial
statements.
F-6
Notes to consolidated financial statements
|
|
The accompanying consolidated financial statements and the supporting and supplemental material
are the responsibility of the management of Imperial Oil Limited. |
|
|
|
The companys principal business is energy, involving the exploration, production,
transportation and sale of crude oil and natural gas and the manufacture, transportation and
sale of petroleum products. The company is also a major manufacturer and marketer of
petrochemicals. |
|
|
|
The consolidated financial statements have been prepared in accordance with generally accepted
accounting principles in the United States of America. The financial statements include certain
estimates that reflect managements best judgment. Certain reclassifications to prior years have
been made to conform to the 2007 presentation. All amounts are in Canadian dollars unless
otherwise indicated. |
|
1. |
|
Summary of significant accounting policies |
|
|
|
Principles of consolidation
The consolidated financial statements include the accounts of Imperial Oil Limited and its
subsidiaries. Intercompany accounts and transactions are eliminated. Subsidiaries include those
companies in which Imperial 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 share of undivided 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. |
|
|
|
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 costs. |
|
|
|
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 Imperials share of
earnings since the investment was made, less dividends received. Imperials share of the
after-tax earnings of these companies is included in investment and
other income in the consolidated statement of income. 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 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. Imperial does not invest in these companies in order
to remove liabilities from its balance sheet. |
|
|
|
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 uses the successful-efforts method to account for its exploration and development
activities. Under this method, costs are accumulated on a field-by-field basis with certain
exploratory expenditures and exploratory dry holes being expensed as incurred. The company
carries as an asset exploratory well costs if (a) the well found a sufficient quantity of
reserves to justify its completion as a producing well and (b) the company is making sufficient
progress assessing the reserves and the economic and operating viability of the project.
Exploratory well costs not meeting these criteria were charged to expense. Costs of productive
wells and development dry holes are capitalized and amortized on the unit-of-production method
for each field. The company uses this accounting policy instead of the full-cost method because
it provides a more timely accounting of the success or failure of the companys 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.
These costs, sometimes referred to as lifting costs, include such items as labour cost to
operate the wells and related equipment; repair and maintenance costs on the wells and
equipment; materials, supplies and energy costs required to operate the wells and related
equipment; and administrative expenses related to the production activity. |
|
|
|
Depreciation and depletion for assets associated with producing properties begin at the time
when production commences on a regular basis. Depreciation for other assets begins when the
asset is in place and ready for its intended use. Assets under construction are not depreciated
or depleted. Acquisition costs of proved properties are amortized using a unit-of-production
method, computed on the basis of total proved oil and gas reserves. Unit-of-production
depreciation is applied to those wells, plant and equipment assets associated with productive
depletable properties and the unit-of-production rates are based on the amount of proved
developed reserves of oil and gas. 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. |
F-7
|
|
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. |
|
|
|
In general, impairment analyses are based on proved reserves. Where probable reserves exist, an
appropriately risk-adjusted amount of these reserves may be included in the impairment
evaluation. An asset would be impaired if the undiscounted cash flows were less than its
carrying value. Impairments are measured by the amount by which the carrying value exceeds its
fair value. |
|
|
|
Acquisition costs for the companys oil sands(a) operation are capitalized as incurred. Oil
sands exploration costs are expensed as incurred. The capitalization of project development
costs begins when there are no major uncertainties that exist which would preclude management
from making a significant funding commitment within a reasonable time period. The company
expenses stripping costs during the production phase as incurred. |
|
|
|
Depreciation of oil sands assets begins at the time when production commences on a regular
basis. Assets under construction are not depreciated. Investments in extraction facilities,
which separate the crude from sand, as well as the upgrading facilities, are depreciated on a
unit-of-production method based on proven developed reserves. Investments in mining and
transportation systems are generally depreciated on a straight-line basis over a 15-year life. |
|
|
|
Oil sands assets held and used by the company are reviewed for impairment whenever events or
changes in circumstances indicate that the carrying amounts are not recoverable. The impairment
evaluation for oil sands assets is based on a comparison of undiscounted cash flows to book
carrying value. |
|
|
|
Gains or losses on assets sold are included in investment and other income in the consolidated
statement of income. |
|
|
|
(a) Oil sands are a semi-solid material composed of bitumen, sand, water and clays, and are
recovered through surface mining methods. Currently, the companys oil sands production volumes
and reserves are the companys share of production volumes and reserves in the Syncrude joint
venture. |
|
|
|
Interest capitalization
Interest costs relating to major capital projects under construction are capitalized as part of
property, plant and equipment. The project construction phase commences with the development of
the detailed engineering design and ends when the constructed assets are ready for their
intended use. |
|
|
|
Goodwill and other intangible assets
Goodwill is not subject to amortization. Goodwill is tested for impairment annually or more
frequently if events or circumstances indicate it 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 income. |
|
|
|
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. These obligations primarily relate to soil remediation and decommissioning and
removal costs of oil and gas wells and related facilities. 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 those manufacturing, distribution and marketing
facilities with an indeterminate useful life. Asset retirement obligations for these facilities
generally become firm at the time the facilities are permanently shut down and dismantled. These
obligations may include the costs of asset disposal and additional soil remediation. However,
these sites have indeterminate lives based on plans for continued operations, and as such, the
fair value of the conditional legal obligations cannot be measured, since it is impossible to
estimate the future settlement dates of such obligations. Provision for environmental
liabilities of these assets is made when it is probable that obligations have been incurred and
the amount can be reasonably estimated. These liabilities are not discounted. 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 income. |
|
|
|
Financial instruments
The fair values of cash, 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 the companys other financial instruments, which are mainly long-term
receivables, 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 does not use derivative instruments to
speculate on the future direction of currency or commodity prices and does not sell forward any
part of production from any business segment. |
|
|
|
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 collectibility 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 income. Delivery costs
from final storage to customer are recorded as a marketing expense in selling and general
expenses. |
F-8
Notes to consolidated financial statements (continued)
|
|
Effective January 1, 2006, the company adopted the Emerging Issues Task Force (EITF) consensus
on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same
Counterparty. The EITF concluded that purchases and sales of inventory with the same
counterparty that are entered into in contemplation of one another should be combined and
recorded as exchanges measured at the book value of the item sold. In prior periods, the company
recorded certain crude oil, natural gas, petroleum product and chemical sales and purchases
contemporaneously negotiated with the same counterparty as revenues and purchases. As a result
of the EITF consensus, beginning in 2006, the companys accounts operating revenues and
purchases of crude oil and products on the consolidated statement of income have been reduced
by associated amounts with no impact on net income. All operating segments were affected by this
change, with the largest impact in the petroleum products segment. |
|
|
|
Share-based compensation
The company awards share-based compensation to employees in the form of restricted stock units.
Compensation expense is measured each reporting period based on the companys current stock
price and is recorded as selling and general expenses in the consolidated statement of income
over the requisite service period of each award. See note 9 to the consolidated financial
statements for further details. |
|
|
|
Consumer taxes
Taxes levied on the consumer and collected by the company are excluded from the consolidated
statement of income. These are primarily provincial taxes on motor fuels and the federal goods
and services tax. |
|
2. |
|
Accounting change for uncertainty in income taxes |
|
|
Effective January 1, 2007, the company adopted the FASB Interpretation No. 48 (FIN 48),
Accounting for Uncertainty in Income Taxes. FIN 48 is an interpretation of FASB Statement No.
109, Accounting for Income Taxes and prescribes a comprehensive model for recognizing,
measuring, presenting and disclosing in the financial statements uncertain tax positions that
the company has taken or expects to take in its income tax returns. Upon the adoption of FIN 48,
the company recognized a transition gain of $14 million in shareholders equity, reflected as
cumulative effect of accounting change in the consolidated statement of shareholders equity.
The gain reflected the recognition of several refund claims with associated interest, partly
offset by increased income tax reserves. FIN 48 also resulted in a reclassification of amounts
previously reported net on the balance sheet. The balance sheet reclassification resulted in a
$534 million increase to long-term receivables, investments and other long-term assets; a $363
million increase to income taxes payable; a $142 million increase to other long-term
obligations; and a $15 million increase to deferred tax liabilities. See note 5, Income taxes,
for additional disclosures. |
|
3. |
|
Business segments |
|
|
The company operates its business in Canada. The natural resources, petroleum products and
chemicals functions best define the operating segments of the business that are reported
separately. The factors used to identify these reportable segments are based on the nature of
the operations that are undertaken by each segment and the structure of the companys internal
organization. The natural resources segment is organized and operates to explore for and
ultimately produce crude oil and its equivalent, and natural gas. The petroleum products segment
is organized and operates to refine crude oil into petroleum products and the distribution and
marketing of these products. The chemicals segment is organized and operates to manufacture and
market hydrocarbon-based chemicals and chemical products. The above segmentation has been the
long-standing practice of the company and is broadly understood across the petroleum and
petrochemical industries. |
|
|
|
These functions have been defined as the operating segments of the company because they are the
segments (a) that engage in business activities from which revenues are earned and expenses are
incurred; (b) whose operating results are regularly reviewed by the companys chief operating
decision maker to make decisions about resources to be allocated to each segment and assess its
performance; and (c) for which discrete financial information is available. |
|
|
|
Corporate and other includes assets and liabilities that do not specifically relate to business
segments primarily cash, long-term debt and liabilities associated with incentive compensation
and post-retirement benefits liability adjustment. Net income in this segment primarily includes
financing costs, interest income and incentive compensation expenses. |
|
|
|
Segment accounting policies are the same as those described in the 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.
Intersegment sales are made essentially at prevailing market prices. Assets and liabilities that
are not identifiable by segment are allocated. |
F-9
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Natural resources (a) |
|
|
Petroleum products |
|
|
Chemicals |
|
millions of dollars |
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
Revenues and other income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External sales (b) |
|
|
4,539 |
|
|
|
4,619 |
|
|
|
4,702 |
|
|
|
19,230 |
|
|
|
18,527 |
|
|
|
21,793 |
|
|
|
1,300 |
|
|
|
1,359 |
|
|
|
1,302 |
|
Intersegment sales |
|
|
4,146 |
|
|
|
3,837 |
|
|
|
3,487 |
|
|
|
2,305 |
|
|
|
2,256 |
|
|
|
2,224 |
|
|
|
335 |
|
|
|
345 |
|
|
|
363 |
|
Investment and other income |
|
|
233 |
|
|
|
111 |
|
|
|
331 |
|
|
|
52 |
|
|
|
105 |
|
|
|
60 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
8,918 |
|
|
|
8,567 |
|
|
|
8,520 |
|
|
|
21,587 |
|
|
|
20,888 |
|
|
|
24,077 |
|
|
|
1,635 |
|
|
|
1,704 |
|
|
|
1,665 |
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
106 |
|
|
|
32 |
|
|
|
43 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of crude oil and products |
|
|
3,113 |
|
|
|
2,841 |
|
|
|
2,837 |
|
|
|
16,469 |
|
|
|
16,178 |
|
|
|
19,212 |
|
|
|
1,230 |
|
|
|
1,209 |
|
|
|
1,191 |
|
Production and manufacturing |
|
|
2,057 |
|
|
|
1,994 |
|
|
|
1,931 |
|
|
|
1,232 |
|
|
|
1,266 |
|
|
|
1,203 |
|
|
|
185 |
|
|
|
189 |
|
|
|
195 |
|
Selling and general (c) |
|
|
8 |
|
|
|
13 |
|
|
|
36 |
|
|
|
987 |
|
|
|
1,018 |
|
|
|
1,096 |
|
|
|
71 |
|
|
|
76 |
|
|
|
81 |
|
Federal excise tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,307 |
|
|
|
1,274 |
|
|
|
1,278 |
|
|
|
|
|
|
|
|
|
|
|
|
|
Depreciation and depletion |
|
|
519 |
|
|
|
584 |
|
|
|
651 |
|
|
|
244 |
|
|
|
233 |
|
|
|
230 |
|
|
|
12 |
|
|
|
11 |
|
|
|
12 |
|
Financing costs (note 14) |
|
|
4 |
|
|
|
2 |
|
|
|
|
|
|
|
1 |
|
|
|
6 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total expenses |
|
|
5,807 |
|
|
|
5,466 |
|
|
|
5,498 |
|
|
|
20,240 |
|
|
|
19,975 |
|
|
|
23,021 |
|
|
|
1,498 |
|
|
|
1,485 |
|
|
|
1,479 |
|
|
Income before income taxes |
|
|
3,111 |
|
|
|
3,101 |
|
|
|
3,022 |
|
|
|
1,347 |
|
|
|
913 |
|
|
|
1,056 |
|
|
|
137 |
|
|
|
219 |
|
|
|
186 |
|
|
Income taxes (note 5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
682 |
|
|
|
602 |
|
|
|
955 |
|
|
|
491 |
|
|
|
174 |
|
|
|
409 |
|
|
|
42 |
|
|
|
60 |
|
|
|
69 |
|
Deferred |
|
|
60 |
|
|
|
123 |
|
|
|
59 |
|
|
|
(65) |
|
|
|
115 |
|
|
|
(47) |
|
|
|
(2) |
|
|
|
16 |
|
|
|
(4) |
|
|
Total income tax expense |
|
|
742 |
|
|
|
725 |
|
|
|
1,014 |
|
|
|
426 |
|
|
|
289 |
|
|
|
362 |
|
|
|
40 |
|
|
|
76 |
|
|
|
65 |
|
|
Net income |
|
|
2,369 |
|
|
|
2,376 |
|
|
|
2,008 |
|
|
|
921 |
|
|
|
624 |
|
|
|
694 |
|
|
|
97 |
|
|
|
143 |
|
|
|
121 |
|
|
Cash flow from (used in) operating activities |
|
|
2,411 |
|
|
|
3,024 |
|
|
|
2,440 |
|
|
|
1,151 |
|
|
|
507 |
|
|
|
799 |
|
|
|
109 |
|
|
|
161 |
|
|
|
94 |
|
|
Capital and exploration expenditures |
|
|
744 |
|
|
|
787 |
|
|
|
937 |
|
|
|
187 |
|
|
|
361 |
|
|
|
478 |
|
|
|
11 |
|
|
|
13 |
|
|
|
19 |
|
|
Property, plant and equipment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost |
|
|
15,285 |
|
|
|
14,926 |
|
|
|
14,229 |
|
|
|
6,655 |
|
|
|
6,581 |
|
|
|
6,350 |
|
|
|
718 |
|
|
|
702 |
|
|
|
701 |
|
Accumulated depreciation and depletion |
|
|
(8,474) |
|
|
|
(8,255) |
|
|
|
(7,780) |
|
|
|
(3,320) |
|
|
|
(3,178) |
|
|
|
(3,037) |
|
|
|
(496) |
|
|
|
(484) |
|
|
|
(474) |
|
|
Net property, plant and equipment(d)(e) |
|
|
6,811 |
|
|
|
6,671 |
|
|
|
6,449 |
|
|
|
3,335 |
|
|
|
3,403 |
|
|
|
3,313 |
|
|
|
222 |
|
|
|
218 |
|
|
|
227 |
|
|
Total assets |
|
|
8,171 |
|
|
|
7,513 |
|
|
|
7,289 |
|
|
|
6,727 |
|
|
|
6,450 |
|
|
|
6,257 |
|
|
|
476 |
|
|
|
504 |
|
|
|
500 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Corporate and other |
|
|
Eliminations |
|
|
Consolidated |
|
millions of dollars |
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
2007 |
|
|
2006 |
|
|
2005 |
|
|
Revenues and other income |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
External sales (b) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
25,069 |
|
|
|
24,505 |
|
|
|
27,797 |
|
Intersegment sales |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,786) |
|
|
|
(6,438) |
|
|
|
(6,074) |
|
|
|
|
|
|
|
|
|
|
|
|
|
Investment and other income |
|
|
89 |
|
|
|
67 |
|
|
|
26 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
374 |
|
|
|
283 |
|
|
|
417 |
|
|
|
|
|
89 |
|
|
|
67 |
|
|
|
26 |
|
|
|
(6,786) |
|
|
|
(6,438) |
|
|
|
(6,074) |
|
|
|
25,443 |
|
|
|
24,788 |
|
|
|
28,214 |
|
|
Expenses |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Exploration |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
106 |
|
|
|
32 |
|
|
|
43 |
|
Purchases of crude oil and products |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(6,786) |
|
|
|
(6,435) |
|
|
|
(6,072) |
|
|
|
14,026 |
|
|
|
13,793 |
|
|
|
17,168 |
|
Production and manufacturing |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(3) |
|
|
|
(2) |
|
|
|
3,474 |
|
|
|
3,446 |
|
|
|
3,327 |
|
Selling and general (c) |
|
|
269 |
|
|
|
177 |
|
|
|
364 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,335 |
|
|
|
1,284 |
|
|
|
1,577 |
|
Federal excise tax |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,307 |
|
|
|
1,274 |
|
|
|
1,278 |
|
Depreciation and depletion |
|
|
5 |
|
|
|
3 |
|
|
|
2 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
780 |
|
|
|
831 |
|
|
|
895 |
|
Financing costs (note 14) |
|
|
31 |
|
|
|
20 |
|
|
|
6 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
36 |
|
|
|
28 |
|
|
|
8 |
|
|
Total expenses |
|
|
305 |
|
|
|
200 |
|
|
|
372 |
|
|
|
(6,786) |
|
|
|
(6,438) |
|
|
|
(6,074) |
|
|
|
21,064 |
|
|
|
20,688 |
|
|
|
24,296 |
|
|
Income before income taxes |
|
|
(216) |
|
|
|
(133) |
|
|
|
(346) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
4,379 |
|
|
|
4,100 |
|
|
|
3,918 |
|
|
Income taxes (note 5) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Current |
|
|
(52) |
|
|
|
(60) |
|
|
|
(72) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,163 |
|
|
|
776 |
|
|
|
1,361 |
|
Deferred |
|
|
35 |
|
|
|
26 |
|
|
|
(51) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
28 |
|
|
|
280 |
|
|
|
(43) |
|
|
Total income tax expense |
|
|
(17) |
|
|
|
(34) |
|
|
|
(123) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,191 |
|
|
|
1,056 |
|
|
|
1,318 |
|
|
Net income |
|
|
(199) |
|
|
|
(99) |
|
|
|
(223) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,188 |
|
|
|
3,044 |
|
|
|
2,600 |
|
|
Cash flow from (used in) operating activities |
|
|
(45) |
|
|
|
(105) |
|
|
|
118 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
3,626 |
|
|
|
3,587 |
|
|
|
3,451 |
|
|
Capital and exploration expenditures |
|
|
36 |
|
|
|
48 |
|
|
|
41 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
978 |
|
|
|
1,209 |
|
|
|
1,475 |
|
|
Property, plant and equipment |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cost |
|
|
304 |
|
|
|
269 |
|
|
|
246 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22,962 |
|
|
|
22,478 |
|
|
|
21,526 |
|
Accumulated depreciation and depletion |
|
|
(111) |
|
|
|
(104) |
|
|
|
(103) |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(12,401) |
|
|
|
(12,021) |
|
|
|
(11,394) |
|
|
Net property, plant and equipment (d)(e) |
|
|
193 |
|
|
|
165 |
|
|
|
143 |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
10,561 |
|
|
|
10,457 |
|
|
|
10,132 |
|
|
|