IMPERIAL OIL LTD - Annual Report: 2006 (Form 10-K)
Table of Contents
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
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2006 | Commission file number: 0-12014 |
IMPERIAL OIL LIMITED
(Exact name of registrant as specified in its charter)
CANADA | 98-0017682 | |
(State or other jurisdiction of incorporation or organization) |
(I.R.S. Employer Identification No.) |
|
237 FOURTH AVENUE S.W., CALGARY, AB, CANADA (Address of principal executive offices) |
T2P 3M9 (Postal Code) |
Registrants telephone number, including area code:
1-800-567-3776
Securities registered pursuant to Section 12(b) of the Act:
1-800-567-3776
Securities registered pursuant to Section 12(b) of the Act:
Title of each class None |
Name of each exchange on which registered None |
|
Securities registered pursuant to Section 12(g) of the Act:
Common Shares (without par value)
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 þ Noo
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 o No þ
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 þ Noo
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 þ Noo
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated
filer, or a non-accelerated filer (see definition of accelerated filer and large accelerated
filer in Rule 12b-2 of the Securities Exchange Act of 1934).
Large accelerated filer þ Accelerated filero Non-accelerated filero
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 o No þ
As of the last business day of the 2006 second fiscal quarter, the aggregate market value of
the voting stock held by non-affiliates of the registrant was Canadian $12,075,765,770 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 15, 2007, was 949,989,788.
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Item 2. | 18 | |||||
Item 3. | 18 | |||||
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Item 5. | 19 | |||||
Item 6. | 20 | |||||
Item 7. | 20 | |||||
Item 7A. | 30 | |||||
Item 8. | 31 | |||||
Item 9. | 36 | |||||
Item 9A. | 36 | |||||
Item 10. | 37 | |||||
Item 11. | 39 | |||||
Item 12. | 48 | |||||
Item 13. | 49 | |||||
Item 14. | 50 | |||||
Item 15. | 51 | |||||
Index to Financial Statements | F-1 | |||||
Managements Report on Internal Control over Financial Reporting | F-2 | |||||
Report of Independent Registered Public Accounting Firm | F-2 |
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.
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(dollars) | ||||||||||||||||||||
Rate at end of period |
0.8582 | 0.8579 | 0.8310 | 0.7738 | 0.6329 | |||||||||||||||
Average rate during period |
0.8844 | 0.8276 | 0.7702 | 0.7186 | 0.6368 | |||||||||||||||
High |
0.9100 | 0.8690 | 0.8493 | 0.7738 | 0.6619 | |||||||||||||||
Low |
0.8528 | 0.7872 | 0.7158 | 0.6349 | 0.6200 |
On February 15, 2007, 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
$0.8590 U.S. = $1.00 Canadian.
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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)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
External sales (1) : |
||||||||||||||||||||
Natural resources |
$ | 4,619 | $ | 4,702 | $ | 3,689 | $ | 3,390 | $ | 2,573 | ||||||||||
Petroleum products |
18,527 | 21,793 | 17,503 | 14,710 | 13,362 | |||||||||||||||
Chemicals |
1,359 | 1,302 | 1,216 | 994 | 955 | |||||||||||||||
Corporate and other |
| | | | | |||||||||||||||
$ | 24,505 | $ | 27,797 | $ | 22,408 | $ | 19,094 | $ | 16,890 | |||||||||||
Intersegment sales: |
||||||||||||||||||||
Natural resources |
$ | 3,837 | $ | 3,487 | $ | 2,891 | $ | 2,224 | $ | 2,217 | ||||||||||
Petroleum products |
2,256 | 2,224 | 1,666 | 1,294 | 1,038 | |||||||||||||||
Chemicals |
345 | 363 | 293 | 238 | 209 | |||||||||||||||
Net income (2) : |
||||||||||||||||||||
Natural resources |
$ | 2,376 | $ | 2,008 | $ | 1,517 | $ | 1,174 | $ | 1,052 | ||||||||||
Petroleum products |
624 | 694 | 556 | 462 | 147 | |||||||||||||||
Chemicals |
143 | 121 | 109 | 44 | 54 | |||||||||||||||
Corporate and other (3) /eliminations |
(99 | ) | (223 | ) | (130 | ) | 25 | (39 | ) | |||||||||||
$ | 3,044 | $ | 2,600 | $ | 2,052 | $ | 1,705 | $ | 1,214 | |||||||||||
Identifiable assets at December 31 (4) : |
||||||||||||||||||||
Natural resources |
$ | 7,513 | $ | 7,289 | $ | 6,822 | $ | 6,397 | $ | 5,982 | ||||||||||
Petroleum products |
6,450 | 6,257 | 5,509 | 5,225 | 5,034 | |||||||||||||||
Chemicals |
504 | 500 | 490 | 433 | 417 | |||||||||||||||
Corporate and other/eliminations |
1,674 | 1,536 | 1,206 | 282 | 570 | |||||||||||||||
$ | 16,141 | $ | 15,582 | $ | 14,027 | $ | 12,337 | $ | 12,003 | |||||||||||
Capital and exploration expenditures: |
||||||||||||||||||||
Natural resources |
$ | 787 | $ | 937 | $ | 1,113 | $ | 1,007 | $ | 986 | ||||||||||
Petroleum products |
361 | 478 | 283 | 478 | 589 | |||||||||||||||
Chemicals |
13 | 19 | 15 | 41 | 25 | |||||||||||||||
Corporate and other |
48 | 41 | 34 | 33 | 12 | |||||||||||||||
$ | 1,209 | $ | 1,475 | $ | 1,445 | $ | 1,559 | $ | 1,612 | |||||||||||
(1) | Export sales are reported in note 3 to the consolidated financial statements on page F-9. Total external sales include $4,894 million for 2005, $3,584 million for 2004, $2,851 million for 2003 and $2,431 million for 2002 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) | 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) | Includes primarily interest charges on the debt obligations of the company, interest income on investments, incentive compensation expenses, and intersegment consolidating adjustments. | |
(4) | 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, $89 million for 2003 and $114 million in 2002. This change has no impact on total identifiable assets at December 31 of 2005 and prior years. |
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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, 2006, was as follows:
2006 | 2005 | 2004 | 2003 | 2002 | |||||||||||||||||
(thousands a day) | |||||||||||||||||||||
Conventional (including natural gas liquids): |
|||||||||||||||||||||
Cubic metres |
Gross (1) | 8.7 | 11.0 | 12.1 | 11.8 | 12.4 | |||||||||||||||
Net (2) | 6.7 | 8.6 | 9.4 | 9.1 | 9.5 | ||||||||||||||||
Barrels |
Gross (1) | 55 | 69 | 76 | 74 | 78 | |||||||||||||||
Net (2) | 42 | 54 | 59 | 57 | 60 | ||||||||||||||||
Heavy Oil (3): |
|||||||||||||||||||||
Cubic metres |
Gross (1) | 24.1 | 22.1 | 20.0 | 20.5 | 17.8 | |||||||||||||||
Net (2) | 20.1 | 19.7 | 17.7 | 18.4 | 16.9 | ||||||||||||||||
Barrels |
Gross (1) | 152 | 139 | 126 | 129 | 112 | |||||||||||||||
Net (2) | 127 | 124 | 112 | 116 | 106 | ||||||||||||||||
Oil Sands (4): |
|||||||||||||||||||||
Cubic metres |
Gross (1) | 10.3 | 8.4 | 9.5 | 8.4 | 9.1 | |||||||||||||||
Net (2) | 9.3 | 8.4 | 9.4 | 8.3 | 9.1 | ||||||||||||||||
Barrels |
Gross (1) | 65 | 53 | 60 | 53 | 57 | |||||||||||||||
Net (2) | 58 | 53 | 59 | 52 | 57 | ||||||||||||||||
Total: |
|||||||||||||||||||||
Cubic metres |
Gross (1) | 43.1 | 41.5 | 41.6 | 40.7 | 39.3 | |||||||||||||||
Net (2) | 36.1 | 36.7 | 36.5 | 35.8 | 35.5 | ||||||||||||||||
Barrels |
Gross (1) | 272 | 261 | 262 | 256 | 247 | |||||||||||||||
Net (2) | 227 | 231 | 230 | 225 | 223 |
(1) | 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) | Net production is gross production less the mineral owners or governments share or both. | |
(3) | 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) | Oil sands are a semi-solid material composed of bitumen, sand, water and clays which are recovered through surface mining methods. Imperials oil sands production volumes are the companys share of production volumes in the Syncrude joint venture. |
In 2003, conventional production declined mainly due to natural decline of the companys
conventional oil fields. In 2004, conventional production increased primarily due to increased
natural gas liquids production from the Wizard Lake gas cap. In 2005 and 2006 conventional
production declined mainly due to the natural decline of the companys conventional fields. In
2003, Cold Lake net production increased as a result of a full year of production of phases 11 to
13, which was offset in part by the timing of steaming cycles and higher royalties. Syncrude
production decreased in 2003 due to extended maintenance of upgrading facilities. In 2004, Cold
Lake production declined due to the timing of steaming cycles and higher royalty, and Syncrude
production increased due to fewer disruptions 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 greater
maintenance downtime 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.
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The companys average daily production and sales of natural gas during the five years ended
December 31, 2006 are set forth below. All gas volumes in this report are calculated at a pressure
base of, in the case of cubic metres, 101.325 kilopascals absolute at 15 degrees Celsius and, in
the case of cubic feet, 14.73 pounds per square inch absolute at 60 degrees Fahrenheit.
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions a day) | ||||||||||||||||||||
Sales (1) : |
||||||||||||||||||||
Cubic metres |
14.5 | 15.2 | 14.7 | 13.0 | 14.1 | |||||||||||||||
Cubic feet |
513 | 536 | 520 | 460 | 499 | |||||||||||||||
Gross Production (2): |
||||||||||||||||||||
Cubic metres |
15.8 | 16.4 | 16.1 | 14.5 | 15.0 | |||||||||||||||
Cubic feet |
556 | 580 | 569 | 513 | 530 | |||||||||||||||
Net Production (2): |
||||||||||||||||||||
Cubic metres |
14.1 | 14.6 | 14.7 | 12.9 | 13.1 | |||||||||||||||
Cubic feet |
496 | 514 | 518 | 457 | 463 |
(1) | Sales are sales of the companys share of production (before deduction of the mineral owners and/or governments share) and sales of gas purchased, processed and/or resold. | |
(2) | Gross production of natural gas is the companys share of production (excluding purchases) before deducting the shares of mineral owners or governments or both. Net production excludes those shares. Production data include amounts used for internal consumption with the exception of amounts reinjected. |
In 2003, natural gas production decreased primarily due to the depletion of gas caps in
Alberta and increased maintenance activity at gas processing facilities. 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.
Most of the companys natural gas sales are made under short term contracts.
The companys average sales price and production costs for crude oil and natural gas liquids
and natural gas for the five years ended December 31, 2006, were as follows:
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Average Sales Price: |
||||||||||||||||||||
Crude oil and natural gas liquids: |
||||||||||||||||||||
Per cubic metre |
$ | 283.84 | $ | 234.04 | $ | 207.26 | $ | 181.92 | $ | 174.72 | ||||||||||
Per barrel |
45.13 | 37.21 | 32.95 | 28.92 | 27.78 | |||||||||||||||
Natural gas: |
||||||||||||||||||||
Per thousand cubic metres |
$ | 255.58 | $ | 317.71 | $ | 239.34 | $ | 232.99 | $ | 141.91 | ||||||||||
Per thousand cubic feet |
7.24 | 9.00 | 6.78 | 6.60 | 4.02 | |||||||||||||||
Average Production Costs Per
Unit of Net Production (1),(2): |
||||||||||||||||||||
Per cubic metre |
$ | 69.69 | $ | 67.82 | $ | 58.16 | $ | 60.78 | $ | 53.09 | ||||||||||
Per barrel |
11.08 | 10.78 | 9.25 | 9.66 | 8.44 |
(1) | 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.
Canadian natural gas prices are determined by North American gas markets and are also
volatile. 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 2003 and 2005, average unit production costs increased mainly due to higher costs of
purchased natural gas at Cold Lake. In 2004, average unit production costs decreased mainly due to
higher production from the Wizard Lake gas cap. 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.
The company has interests in a large number of facilities related to the production of crude
oil and natural gas. Among these facilities are 22 plants that process natural gas to produce
marketable gas and recover natural gas liquids or sulphur. The company is the principal owner and
operator of 11 of the plants.
The companys production of conventional 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
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December 31, 2006, 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 |
1,241 | 794 | 4,791 | 2,612 | 6,032 | 3,406 | ||||||||||||||||||
Heavy Oil wells |
3,983 | 3,983 | | | 3,983 | 3,983 |
(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 55 percent of the companys
net production of conventional crude oil (approximately 61 percent of gross production). In 2006,
net production of crude oil and natural gas liquids was about 2,000 cubic metres (12,700 barrels)
per day and gross production was about 3,000 cubic metres (18,900 barrels) per day. The Government
of Canada has a one-third carried interest and receives a production royalty of five percent in the
Norman Wells oil field. The Government of Canadas carried interest entitles it to receive payment
of a one-third share of an amount based on revenues from the sale of Norman Wells production, net
of operating and capital costs. Under a shipping agreement, the company pays for the construction,
operating and other costs of the 870 kilometre (540 mile) pipeline which transports the crude oil
and natural gas liquids from the project. In 2006, 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 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 78,000 hectares (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 2006, average net production at Cold Lake was about 20,100 cubic metres (126,700
barrels) per day and gross production was about 24,100 cubic metres (151,800 barrels) per day.
To maintain production at Cold Lake, capital expenditures for additional production wells and
associated facilities will be required periodically. In 2006, the company spent $213 million and
executed a development drilling program of 174 wells on existing phases. In 2007, a development
drilling program of more than 100 wells is planned within the currently approved development area
to add productive capacity from undeveloped areas of existing Cold Lake phases. In addition,
opportunities are also being evaluated to improve utilization of the existing infrastructure.
In 2004, the company received regulatory approval for further expansion of its operations at
Cold Lake. Production began in 2006 from part of the approved expansion, the development of which
is expected to cost about $400 million and is expected to have gross production of about 4,800
cubic metres (30,000 barrels) per day by the end of the decade. Development plans for the remainder
of the approved expansion are being examined to reduce development costs through increased
integration with 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 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 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. In late 2000, the company
entered into an agreement with the Province of Alberta, effective January 1, 2000, on a
transitional royalty arrangement that will apply to all of the companys current and proposed
operations at Cold Lake until the end of 2007, at which time the generic Alberta regulations for
heavy oil royalties will apply. The post-transition royalty regulation, which will become effective
in 2008, provides for a royalty calculated at the greater of one
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percent of gross revenue or 25 percent of an amount based on revenue net of operating and capital costs, but with no gas royalty waiver. The transition agreement,
which is effective between 2000 and 2007 inclusive, makes 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). This transition will bring all phases of the companys Cold Lake
operations under one royalty agreement with common terms and conditions. The transition is not
expected to materially change the amount of royalties that the company would have otherwise paid
under the pre-existing royalty arrangements. The effective royalty on gross production was 17
percent in 2006, 11 percent in 2005 and 2004, 10 percent in 2003 and five percent in 2002.
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 totalling about 68,000 leased net
hectares (168,000 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), exploits a portion of the
Athabasca Oil Sands Deposit. The location is readily accessible by public road. The produced
synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands
Pipeline Ltd. Since startup in 1978, Syncrude has produced about 1.7 billion barrels of synthetic
crude oil.
![(MAP)](https://www.sec.gov/Archives/edgar/data/0000049938/000090956707000270/o34815o3481501.gif)
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 100,500 hectares (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
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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.
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 (lease 17) has now
been mined out and only remnants are being removed using trucks and shovels. 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 675,000 tonnes (740,000 tons) of oil sands a day, producing about 24
million cubic metres (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 sand 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 2006, the upgrading process yielded 0.849 cubic metres of synthetic
crude oil per cubic metre of crude bitumen (0.849 barrels of synthetic crude oil per barrel of
crude bitumen). In 2006, about 44 percent of the synthetic crude oil was processed by Edmonton area
refineries and the remaining 56 percent was pipelined to refineries in 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 2006, Syncrudes net production of synthetic crude oil was about 37,100 cubic metres
(233,600 barrels) per day and gross production was about 41,000 cubic metres (258,100 barrels) per
day. The companys share of net production in 2006 was about 9,300 cubic metres (58,400 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 35 kilometres (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 56,400 cubic metres (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 November 1, 2006, the company announced that it plans to enter into a management services
agreement with Syncrude to provide operational, technical and business management services to
Syncrude. The company has a final checkpoint in the second quarter of 2007 to confirm or cancel the
agreement following completion of an opportunity assessment study.
8
Table of Contents
The following table sets forth certain operating statistics for the Syncrude operations:
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Total mined overburden (1) |
||||||||||||||||||||
millions of cubic metres |
98.0 | 74.2 | 76.6 | 83.5 | 77.9 | |||||||||||||||
millions of cubic yards |
128.2 | 97.1 | 100.3 | 109.2 | 102.0 | |||||||||||||||
Mined overburden to oil sands ratio (1) |
1.18 | 1.02 | 0.94 | 1.15 | 1.05 | |||||||||||||||
Oil sands mined |
||||||||||||||||||||
millions of tonnes |
175.0 | 152.7 | 170.9 | 152.4 | 156.5 | |||||||||||||||
millions of tons |
195.5 | 168.0 | 188.0 | 168.0 | 172.1 | |||||||||||||||
Average bitumen grade (weight percent) |
11.4 | 11.1 | 11.1 | 11.0 | 11.2 | |||||||||||||||
Crude bitumen in mined oil sands |
||||||||||||||||||||
millions of tonnes |
19.9 | 16.9 | 19.0 | 16.8 | 17.5 | |||||||||||||||
millions of tons |
22.2 | 18.6 | 20.9 | 18.5 | 19.2 | |||||||||||||||
Average extraction recovery (percent) |
90.3 | 89.1 | 87.3 | 88.6 | 89.9 | |||||||||||||||
Crude bitumen production (2) |
||||||||||||||||||||
millions of cubic metres |
17.7 | 15.1 | 16.4 | 14.7 | 15.5 | |||||||||||||||
millions of barrels |
111.6 | 94.2 | 103.3 | 92.3 | 97.8 | |||||||||||||||
Average upgrading yield (percent) |
84.9 | 85.3 | 85.5 | 86.0 | 86.3 | |||||||||||||||
Gross synthetic crude oil produced |
||||||||||||||||||||
millions of cubic metres |
15.2 | 12.6 | 14.1 | 12.5 | 13.5 | |||||||||||||||
millions of barrels |
95.5 | 79.3 | 88.4 | 78.4 | 84.8 | |||||||||||||||
Companys net share (3) |
||||||||||||||||||||
millions of cubic metres |
3.4 | 3.1 | 3.4 | 3.0 | 3.3 | |||||||||||||||
millions of barrels |
21.3 | 19.3 | 21.6 | 19.1 | 20.7 |
(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 13,500 hectares (33,400 acres) of
surface mineable oil sands associated with the Kearl project in the Athabasca region of northern
Alberta. The company is assessing a potential phased development of its oil sands in the area as
part of the Kearl oil sands mining project. The company would hold about a 70 percent interest and
would act as operator in the potential joint project with ExxonMobil Canada. A 400 well delineation
drilling program to better define the available resource within the project area began in 2003 and
was completed in 2005. The company filed a regulatory application with the Alberta Energy and
Utilities Board for the Kearl oil sands project in July 2005. Hearings were held in November 2006
and a regulatory decision is expected in early 2007.
The company is continuing to evaluate other undeveloped oil sands acreage.
9
Table of Contents
Land Holdings
At December 31, 2006 and 2005, the company held the following oil and gas rights, and
heavy oil and oil sands leases:
Hectares | Acres | |||||||||||||||||||||||||||||||||||||||||||||||
Developed | Undeveloped | Total | Developed | Undeveloped | Total | |||||||||||||||||||||||||||||||||||||||||||
2006 | 2005 | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | 2006 | 2005 | |||||||||||||||||||||||||||||||||||||
(thousands) | ||||||||||||||||||||||||||||||||||||||||||||||||
Western Provinces |
||||||||||||||||||||||||||||||||||||||||||||||||
Conventional |
||||||||||||||||||||||||||||||||||||||||||||||||
Gross (1) |
1,032 | 1,055 | 154 | 181 | 1,186 | 1,236 | 2,550 | 2,607 | 381 | 447 | 2,931 | 3,054 | ||||||||||||||||||||||||||||||||||||
Net (2) |
407 | 430 | 95 | 109 | 502 | 539 | 1,006 | 1,063 | 235 | 269 | 1,241 | 1,332 | ||||||||||||||||||||||||||||||||||||
Heavy Oil |
||||||||||||||||||||||||||||||||||||||||||||||||
Gross (1) |
41 | 41 | 174 | 193 | 215 | 234 | 101 | 101 | 430 | 477 | 531 | 578 | ||||||||||||||||||||||||||||||||||||
Net (2) |
41 | 41 | 105 | 105 | 146 | 146 | 101 | 101 | 260 | 260 | 361 | 361 | ||||||||||||||||||||||||||||||||||||
Oil Sands |
||||||||||||||||||||||||||||||||||||||||||||||||
Gross (1) |
47 | 47 | 119 | 72 | 166 | 119 | 116 | 116 | 294 | 178 | 410 | 294 | ||||||||||||||||||||||||||||||||||||
Net (2) |
12 | 11 | 54 | 31 | 66 | 42 | 30 | 27 | 133 | 77 | 163 | 104 | ||||||||||||||||||||||||||||||||||||
Canada Lands (3): |
||||||||||||||||||||||||||||||||||||||||||||||||
Conventional |
||||||||||||||||||||||||||||||||||||||||||||||||
Gross (1) |
31 | 31 | 322 | 322 | 353 | 353 | 77 | 77 | 795 | 795 | 872 | 872 | ||||||||||||||||||||||||||||||||||||
Net (2) |
3 | 3 | 98 | 98 | 101 | 101 | 7 | 7 | 242 | 242 | 249 | 249 | ||||||||||||||||||||||||||||||||||||
Atlantic Offshore |
||||||||||||||||||||||||||||||||||||||||||||||||
Conventional |
||||||||||||||||||||||||||||||||||||||||||||||||
Gross (1) |
17 | 17 | 2,600 | 2,600 | 2,617 | 2,617 | 42 | 42 | 6,425 | 6,425 | 6,467 | 6,467 | ||||||||||||||||||||||||||||||||||||
Net (2) |
2 | 2 | 616 | 616 | 618 | 618 | 5 | 5 | 1,522 | 1,522 | 1,527 | 1,527 | ||||||||||||||||||||||||||||||||||||
Total (4) : |
||||||||||||||||||||||||||||||||||||||||||||||||
Gross (1) |
1,168 | 1,191 | 3,369 | 3,368 | 4,537 | 4,559 | 2,886 | 2,943 | 8,325 | 8,322 | 11,211 | 11,265 | ||||||||||||||||||||||||||||||||||||
Net (2) |
465 | 487 | 968 | 959 | 1,433 | 1,446 | 1,149 | 1,203 | 2,392 | 2,370 | 3,541 | 3,573 |
(1) | Gross hectares or acres include the interests of others. | |
(2) | Net hectares or acres exclude the interests of others. | |
(3) | Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and Other Northwest Territories, Nunavut and the Yukon. | |
(4) | Certain land holdings are subject to modification under agreements whereby others may earn interests in the companys holdings by performing certain exploratory work (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 (which include the Arctic Islands, the Beaufort
Sea/Mackenzie Delta, and Other Northwest Territories, Nunavut and the Yukon) and in the Atlantic
Offshore.
The companys exploration strategy in the Western Provinces is to search for hydrocarbons on
its existing land holdings and especially near established facilities. Higher risk areas are
evaluated through shared ventures with other companies.
10
Table of Contents
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,
2006.
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Western and Atlantic Provinces: |
||||||||||||||||||||
Conventional
|
||||||||||||||||||||
Exploratory |
||||||||||||||||||||
Oil |
| | | | | |||||||||||||||
Gas |
1 | | 2 | 3 | 1 | |||||||||||||||
Dry Holes |
| | 1 | 1 | 2 | |||||||||||||||
Development |
||||||||||||||||||||
Oil |
| 2 | 3 | 4 | 1 | |||||||||||||||
Gas |
192 | 155 | 207 | 89 | 42 | |||||||||||||||
Dry Holes |
1 | 1 | 1 | 3 | 3 | |||||||||||||||
Heavy Oil (Cold Lake and other)
|
||||||||||||||||||||
Development |
||||||||||||||||||||
Oil |
174 | 87 | 218 | 118 | 332 | |||||||||||||||
Total |
368 | 245 | 432 | 218 | 381 | |||||||||||||||
The 174 heavy oil development wells in 2006 were drilled to add new productive capacity
from undeveloped areas of existing phases at Cold Lake. In 2004, there was an increase in gas
development wells related to an increase in drilling in shallow gas fields. 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, 2006, the company was participating in the drilling of 221 gross (181 net)
exploratory and development wells.
Western Provinces
In 2006, the company had a working interest in three gross (one net) exploratory wells
and 520 gross (366 net) development wells. The majority of the exploratory wells were directed
toward extending reserves around existing fields.
Beaufort Sea/Mackenzie Delta
Substantial quantities of gas have been found by the company and others in the Beaufort
Sea/Mackenzie Delta.
In 1999, the company and three other companies entered into an agreement to study the
feasibility of developing Mackenzie Delta gas, anchored by three large onshore natural gas fields.
The company retains a 100 percent interest in one 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. There are complex issues to be
resolved and many interested parties to be consulted, before any development could proceed.
In October 2001, the four companies and the Aboriginal Pipeline Group (APG), which
represents aboriginal peoples of the Northwest Territories, signed a memorandum of understanding to
pursue economic and timely development of a Mackenzie Valley pipeline. In 2002, the four companies
completed a preliminary study of the feasibility of developing existing discoveries of Mackenzie
Delta gas and based on the results of the study announced, together with the APG, their intention
to begin preparing the regulatory applications needed to develop the gas resources, including
construction of a Mackenzie Valley pipeline. In 2003, the Preliminary Information Package for the
Mackenzie Gas Project was submitted to the regulatory authorities, and funding and participation
agreements among the four companies, the APG and TransCanada PipeLines Limited were reached for the
proposed Mackenzie Valley pipeline. In late 2004, the four companies and the APG signed agreements
covering the development and operations of the Mackenzie Valley pipeline. In October 2004, the main
regulatory applications and environmental impact statement for the project were filed with the
National Energy Board and other boards, panels and agencies responsible for assessing and
regulating energy developments in the Northwest Territories. In November 2005, the National Energy
Board was notified of the project proponents readiness to proceed to public hearings on the
project. The public hearings by the Joint Review Panel and the National Energy Board commenced in
early 2006. The National Energy Board concluded their scheduled hearings in December, while the
Joint Review Panel, conducting the environmental and socio-economic review, extended hearings into
2007, announcing that it would require several extra months of hearings, and additional time to
compile its report. In November 2006, a federal court
ruling, relating to traditional land use by a First Nation along the pipeline route in
Northern Alberta, added further delay to the process.
11
Table of Contents
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 two exploration licences for about 45,000 gross
hectares (110,000 gross acres) acquired in 1998 and 1999 in the Sable Island area. One exploratory
well was completed on each licence, without commercial success.
Also, the company retains a 70 percent interest in one exploration licence for about 113,000
gross hectares (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 2,125,000 gross hectares (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. An exploration well was spud in August 2006 with anticipated
completion in early 2007. Two more exploration wells are planned by the end of 2008.
The company retains 100 percent interest in a single exploration licence for about 192,000
gross hectares (474,000 gross acres) in the Laurentian basin area offshore Newfoundland and
Labrador.
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 competitive prices mainly
through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil
throughout the world).
Refining
The company owns and operates four refineries. Two of these, the Sarnia refinery and the
Strathcona refinery, have lubricating oil production facilities. The Strathcona refinery processes
Canadian crude oil, and the Dartmouth, Sarnia and Nanticoke refineries process a combination of
Canadian and foreign crude oil. In addition to crude oil, the company purchases finished products
to supplement its refinery production.
In 2006, capital expenditures of about $230 million were made at the companys refineries.
About 40 percent of those expenditures were on new facilities required to meet Government of Canada
regulations on motor fuels with the remaining expenditures being primarily on safety and efficiency
improvements, and environmental improvement projects.
12
Table of Contents
The approximate average daily volumes of refinery throughput during the five years ended
December 31, 2006, and the daily rated capacities of the refineries at December 31, 2001 and 2006,
were as follows:
Average Daily Volumes of | Daily Rated | |||||||||||||||||||||||||||
Refinery Throughput (1) | Capacities at | |||||||||||||||||||||||||||
Year Ended December 31 | December 31 (2) | |||||||||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | 2006 | 2001 | ||||||||||||||||||||||
(thousands of cubic metres) | ||||||||||||||||||||||||||||
Strathcona, Alberta |
25.5 | 27.6 | 27.1 | 27.6 | 26.0 | 29.8 | 29.0 | |||||||||||||||||||||
Sarnia, Ontario |
17.6 | 16.9 | 17.2 | 14.7 | 16.5 | 19.2 | 19.2 | |||||||||||||||||||||
Dartmouth, Nova Scotia |
12.3 | 12.5 | 12.7 | 13.0 | 12.5 | 13.1 | 13.1 | |||||||||||||||||||||
Nanticoke, Ontario |
14.9 | 17.2 | 17.3 | 16.3 | 16.2 | 17.8 | 17.8 | |||||||||||||||||||||
Total |
70.3 | 74.1 | 74.3 | 71.6 | 71.2 | 79.9 | 79.1 | |||||||||||||||||||||
Average Daily Volumes of | Daily Rated | |||||||||||||||||||||||||||
Refinery Throughput (1) | Capacities at | |||||||||||||||||||||||||||
Year Ended December 31 | December 31 (2) | |||||||||||||||||||||||||||
2006 | 2005 | 2004 | 2003 | 2002 | 2006 | 2001 | ||||||||||||||||||||||
(thousands of barrels) | ||||||||||||||||||||||||||||
Strathcona, Alberta |
160 | 174 | 170 | 174 | 163 | 187 | 182 | |||||||||||||||||||||
Sarnia, Ontario |
111 | 106 | 108 | 92 | 104 | 121 | 121 | |||||||||||||||||||||
Dartmouth, Nova Scotia |
77 | 79 | 80 | 82 | 78 | 82 | 82 | |||||||||||||||||||||
Nanticoke, Ontario |
94 | 108 | 109 | 102 | 102 | 112 | 112 | |||||||||||||||||||||
Total |
442 | 466 | 467 | 450 | 447 | 502 | 497 | |||||||||||||||||||||
(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 2006, 5 percentage points below the
previous year, primarily due to scheduled maintenance and project work.
Distribution
The company maintains a nation-wide distribution system, including 30 primary terminals, to
handle bulk and packaged petroleum products moving from refineries to market by pipeline, tanker,
rail and road transport. The company owns and operates crude oil, natural gas liquids and products
pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of two products
and three crude oil pipeline companies.
At December 31, 2006, the company did not own or operate any marine vessels.
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 1,960 sites of which about 650 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 three
company operated Home Comfort facilities in urban markets. The company also sells petroleum
products to large industrial and commercial accounts as well as to other refiners and marketers.
13
Table of Contents
The approximate daily volumes of net petroleum products (excluding purchases/sales contracts
with the same counterparty) sold during the five years ended December 31, 2006, are set out in the
following table:
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(thousands a day) | ||||||||||||||||||||
Gasolines: |
||||||||||||||||||||
Cubic metres |
32.7 | 33.4 | 33.2 | 33.0 | 32.9 | |||||||||||||||
Barrels |
206 | 210 | 209 | 208 | 207 | |||||||||||||||
Heating, Diesel and Jet Fuels: |
||||||||||||||||||||
Cubic metres |
26.4 | 26.9 | 27.3 | 26.2 | 25.0 | |||||||||||||||
Barrels |
166 | 169 | 172 | 165 | 157 | |||||||||||||||
Heavy Fuel Oils: |
||||||||||||||||||||
Cubic metres |
5.1 | 6.0 | 5.9 | 5.4 | 4.9 | |||||||||||||||
Barrels |
32 | 38 | 37 | 34 | 31 | |||||||||||||||
Lube Oils and Other Products
|
||||||||||||||||||||
Cubic metres |
7.7 | 7.6 | 7.0 | 5.8 | 6.4 | |||||||||||||||
Barrels |
49 | 48 | 44 | 36 | 41 | |||||||||||||||
Net petroleum product sales: |
||||||||||||||||||||
Cubic metres |
71.9 | 73.9 | 73.4 | 70.4 | 69.2 | |||||||||||||||
Barrels |
453 | 465 | 462 | 443 | 436 |
The total domestic sales of petroleum products as a percentage of total sales of
petroleum products during the five years ended December 31, 2006, were as follows:
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
96.1 | % | 95.3 | % | 93.0 | % | 93.3 | % | 91.5 | % |
The company continues to evaluate and adjust its Esso service station and distribution
system to increase productivity and efficiency. During 2006, the company closed or debranded about
110 Esso service stations, about 40 of which were company owned, and added about 70 sites. The
companys average annual throughput in 2006 per Esso service station was 3.6 million litres, the
same as in 2005. Average throughput per company owned or leased Esso service station was 6.1
million litres in 2006, an increase of about 0.3 million litres from 2005.
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,
2006, were as follows:
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(thousands a day) | ||||||||||||||||||||
Petrochemicals: |
||||||||||||||||||||
Tonnes |
3.0 | 3.0 | 3.3 | 3.3 | 3.5 | |||||||||||||||
Tons |
3.3 | 3.3 | 3.6 | 3.6 | 3.9 |
Research
In 2006, the companys research expenditures in Canada, before deduction of investment tax
credits, were $56 million, as compared with $50 million in 2005, and $40 million in 2004. Those
funds were used mainly for developing improved heavy crude oil recovery methods and better
lubricants.
A research facility to support the companys natural resources operations is located in
Calgary, Alberta. Research in these laboratories is aimed at developing new technology for the
production and processing of crude bitumen. About 40 people were involved in this type of research
in 2006. 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 120 people were employed in this type of
research at the end of 2006. Also in Sarnia, there are about 15 people engaged in new product
development for the companys and Exxon Mobil Corporations polyethylene injection and rotational
molding businesses.
The company has scientific research agreements with affiliates of Exxon Mobil Corporation
which provide for technical and engineering work to be performed by all parties, the exchange of
technical information and the
14
Table of Contents
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 $1.2 billion on
environmental protection and facilities. In 2006, the companys capital expenditures relating to
environmental protection totalled approximately $155 million, and are expected to be about $160
million in 2007.
The increased environmental expenditures over the past four years primarily reflect spending
on two major projects. One project completed in 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. In 2006, there were capital expenditures of about $95 million on this second project,
which cost about $500 million in total. Capital expenditures on safety related projects in 2006
were approximately $15 million.
Human Resources
At December 31, 2006, the company employed full-time approximately 4,900 persons compared with
about 5,100 at the end of 2005 and 6,100 at the end of 2004. During 2005, the company transferred
about 700 employees to an affiliated company that provides services to the company and others.
About nine percent of the companys employees are members of unions. The company continues to
maintain a broad range of benefits, including illness, disability and survivor benefits, a savings
plan and pension plan.
Competition
The Canadian petroleum, natural gas and chemical industries are highly competitive.
Competition includes the search for and development of new sources of supply, the construction and
operation of crude oil, 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 National
Energy Board (the NEB) and the Government of Canada.
Natural Gas
Production
The maximum allowable gross production of natural gas from wells in Canada is subject to
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
2006 gas production rates. As well, these limitations do not apply to gas fields where there are no
associated oil reserves.
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Exports
The Government of Canada has the authority to regulate the export price for natural gas
and has a gas export pricing policy which accommodates export prices for natural gas negotiated
between Canadian exporters and U.S. importers.
Exports of natural gas from Canada require approval by the NEB and the Government of Canada.
The Government of Canada allows the export of natural gas by NEB order without volume limitation
for terms not exceeding 24 months.
Royalties
The Government of Canada and the provinces in which the company produces crude oil and natural
gas impose royalties on production from lands where they own the mineral rights. Some producing
provinces also receive revenue by imposing taxes on production from lands where they do not own the
mineral rights.
Different royalties are imposed by the Government of Canada and each of the producing
provinces. Royalties imposed by the producing provinces on crude oil vary depending on well
production volumes, selling prices, recovery methods and the date of initial production. Royalties
imposed by the producing provinces on natural gas and natural gas liquids vary depending on well
production volumes, selling prices and the date of initial production. For information with respect
to royalty rates for Norman Wells, Cold Lake and Syncrude, see Natural Resources Petroleum and
Natural Gas Production.
Investment Canada Act
The Investment Canada Act requires Government of Canada approval, in certain cases, of the
acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In
certain circumstances, the acquisition of natural resource properties may be considered to be a
transaction that constitutes an acquisition of control of a Canadian business requiring Government
of Canada approval.
The Act requires notification of the establishment of new unrelated businesses in Canada by
entities not controlled by Canadians, but does not require Government of Canada approval except
when the new business is related to Canadas cultural heritage or national identity. By virtue of
the majority stock ownership of the company by Exxon Mobil Corporation, the company is considered
to be an entity which is not controlled by Canadians.
The Company Online
The companys website www.imperialoil.ca contains a variety of corporate and investor
information which 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, and the production costs associated with
heavy oil are often relatively higher than for lighter grades. 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.
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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 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
The Government of Canada has published a Notice of Intent to regulate emissions of carbon
dioxide, methane, nitrous oxide and other emissions commonly referred to as greenhouse gases from
various industrial activities, including oil and natural gas exploration and production, petroleum
refining, and some chemical manufacturing. The Province of Alberta may also issue regulations under
Albertas Climate Change and Emissions Management Act limiting greenhouse gas emissions. Other
provinces may also issue regulations limiting greenhouse gas emissions. Mandatory emissions limits
may result in increased operating costs and capital expenditures for oil and natural gas producers,
refiners and chemical manufacturers, and also may reduce demand for the companys products,
possibly adversely affecting the companys business, financial condition, results of operations and
cash flows. However, while the government has outlined broad guidelines of a possible regulatory
framework, it has not determined what specific measures it might impose on companies. Consequently
attempts to assess the magnitude of any impact on the company can only be speculative.
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.
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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.
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 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.
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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
2006 | 2005 | |||||||||||||||||||||||||||||||
three months ended | three months ended | |||||||||||||||||||||||||||||||
Mar. 31 | June 30 | Sept. 30 | Dec. 31 | Mar. 31 | June 30 | Sept. 30 | Dec. 31 | |||||||||||||||||||||||||
(millions of dollars) | (millions of dollars) | |||||||||||||||||||||||||||||||
Financial data |
||||||||||||||||||||||||||||||||
Total revenues and other income (a) |
5,818 | 6,688 | 6,651 | 5,631 | 5,958 | 6,802 | 7,711 | 7,743 | ||||||||||||||||||||||||
Total expenses (a) |
4,928 | 5,604 | 5,421 | 4,735 | 5,370 | 5,989 | 6,753 | 6,184 | ||||||||||||||||||||||||
Income before income taxes |
890 | 1,084 | 1,230 | 896 | 588 | 813 | 958 | 1,559 | ||||||||||||||||||||||||
Income taxes |
(299 | ) | (247 | ) | (408 | ) | (102 | ) | (195 | ) | (274 | ) | (306 | ) | (543 | ) | ||||||||||||||||
Net income |
591 | 837 | 822 | 794 | 393 | 539 | 652 | 1,016 | ||||||||||||||||||||||||
Per-share information (b) | (dollars) |
(dollars) |
||||||||||||||||||||||||||||||
Net earnings basic |
0.60 | 0.85 | 0.84 | 0.83 | 0.38 | 0.52 | 0.64 | 1.00 | ||||||||||||||||||||||||
Net earnings diluted |
0.59 | 0.85 | 0.84 | 0.83 | 0.37 | 0.52 | 0.64 | 1.00 | ||||||||||||||||||||||||
Dividends (declared quarterly) |
0.08 | 0.08 | 0.08 | 0.08 | 0.07 | 0.08 | 0.08 | 0.08 | ||||||||||||||||||||||||
Share prices (b) | (dollars) |
(dollars) |
||||||||||||||||||||||||||||||
Toronto Stock Exchange |
||||||||||||||||||||||||||||||||
High |
42.28 | 43.33 | 45.20 | 44.80 | 31.44 | 34.99 | 45.79 | 45.39 | ||||||||||||||||||||||||
Low |
35.36 | 36.18 | 35.33 | 34.31 | 22.50 | 27.37 | 33.33 | 32.28 | ||||||||||||||||||||||||
Close |
41.91 | 40.78 | 37.47 | 42.93 | 30.67 | 34.01 | 44.67 | 38.47 | ||||||||||||||||||||||||
American Stock Exchange | ($U.S.) |
($U.S.) |
||||||||||||||||||||||||||||||
High |
36.67 | 39.64 | 40.38 | 38.93 | 25.73 | 28.38 | 39.14 | 38.93 | ||||||||||||||||||||||||
Low |
30.54 | 32.50 | 31.64 | 29.99 | 18.27 | 21.57 | 27.46 | 27.47 | ||||||||||||||||||||||||
Close |
35.85 | 36.50 | 33.55 | 36.83 | 25.38 | 27.75 | 38.35 | 33.20 |
(a) | Amounts for purchases/sales with same counterparty are included in both total revenues and other income and total expenses in 2005 quarterly data. 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 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 15, 2007 there were 13,490 holders of record of common shares of the company.
During the period October 1, 2006 to December 31, 2006, the company issued 176,325 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.
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Issuer purchases of equity securities (1)
(c) Total number of shares | (d) Maximum number | |||||||||||||||
(a) Total number | purchased as part | (or approximate dollar value) | ||||||||||||||
of shares | (b) Average price | of publicly | of shares that may yet be | |||||||||||||
(or units) | paid per share | announced plans | purchased under the plans or | |||||||||||||
Period | purchased | (or unit) | or programs | programs | ||||||||||||
October 2006 (October 1 - October 31) |
1,315,785 | $ | 36.14 | 1,315,785 | 34,336,470 | |||||||||||
November 2006 (November 1 - November 30) |
5,554,679 | $ | 41.65 | 5,554,679 | 28,721,476 | |||||||||||
December 2006 (December 1 - December 31) |
3,031,537 | $ | 43.99 | 3,031,537 | 25,632,528 |
(1) | The purchases were pursuant to a 12 month normal course share purchase program that was renewed on June 23, 2006 under which the company may purchase up to 48,772,466 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 22, 2007. |
Item 6. Selected Financial Data.
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Total operating revenues (a) |
$ | 24,505 | $ | 27,797 | $ | 22,408 | $ | 19,094 | $ | 16,890 | ||||||||||
Net income |
3,044 | 2,600 | 2,052 | 1,705 | 1,214 | |||||||||||||||
Total assets |
16,141 | 15,582 | 14,027 | 12,337 | 12,003 | |||||||||||||||
Long term debt |
359 | 863 | 367 | 859 | 1,466 | |||||||||||||||
Other long term obligations |
1,683 | 1,728 | 1,525 | 1,314 | 1,822 | |||||||||||||||
(dollars) | ||||||||||||||||||||
Net
income/share basic (b) |
3.12 | 2.54 | 1.92 | 1.53 | 1.07 | |||||||||||||||
Net
income/share diluted (b) |
3.11 | 2.53 | 1.91 | 1.53 | 1.07 | |||||||||||||||
Cash dividends/share (b) |
0.32 | 0.31 | 0.29 | 0.29 | 0.28 |
(a) | Total operating revenues include $4,894 million for 2005, $3,584 million for 2004, $2,851 million for 2003 and $2,431 million for 2002 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 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
risk-assessed, 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.
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Business environment and outlook
Natural resources
Imperial produces crude oil and natural gas for sale into large North American markets.
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
slightly less than 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 slightly less
than two 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 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 a rate of about one percent per year. Oil and
gas are expected to continue to supply 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 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
one-third 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.
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 the Far North, where
Imperial has large undeveloped resource opportunities.
Petroleum products
The downstream industry environment remains very competitive. While refining margins in
2006 were strong, long-term real refining margins globally 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. 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). 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 about 1,960 Esso-branded service stations, of which about 650 are company-owned or leased,
and wholesale and industrial operations through a network of 30 primary distribution terminals, as
well as a secondary distribution network.
Chemicals
Although the current business environment is favourable, 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 Dartmouth with the refineries. The
company also
21
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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 2006 was $3,044 million or $3.11 a share the best year on record
surpassing the previous record of $2,600 million or $2.53 a share in 2005 (2004 $2,052 million
or $1.91 a share). Higher realizations for Cold Lake heavy oil and conventional crude oil
contributed about $640 million and stronger refining, marketing and petrochemical margins about $60
million more to earnings when compared with 2005. Also positive to earnings were higher benefits
from resolution of tax matters and the impact of tax rate changes of about $340 million and lower
share-based compensation expenses of about $105 million. Partially offsetting these positive
factors were the impacts of a stronger Canadian dollar of about $275 million, lower natural gas
realizations of about $150 million, lower gains on asset divestments of about $130 million, higher
planned refinery maintenance and capital project effects of about $100 million and a heavier mix of
resources volumes of about $60 million.
Natural resources
Net income from natural resources was a record $2,376 million, exceeding the previous record
achieved in 2005 of $2,008 million (2004 $1,517 million). Cold Lake heavy oil and conventional
crude oil realizations were stronger by about $640 million compared with 2005. These positive items
were partially offset by lower natural gas realizations of about $150 million and the negative
impact of a higher Canadian dollar of about $200 million. The impact of natural resources volumes
was unfavourable by about $60 million due to mix effects with lower conventional crude oil volumes
being partially offset by higher Syncrude volumes. Higher production at Cold Lake was essentially
offset by higher royalties. Tax expense in 2006 was lower by about $290 million, primarily from
reductions in federal and Alberta tax rates and higher benefits from resolution of tax matters.
Gains from asset divestments were lower by about $130 million compared with 2005.
Financial statistics
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Net income |
$ | 2,376 | $ | 2,008 | $ | 1,517 | $ | 1,174 | $ | 1,052 | ||||||||||
Operating revenues |
8,456 | 8,189 | 6,580 | 5,584 | 4,790 |
World crude oil prices, denominated in U.S. dollars, were higher in 2006 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 $65 (U.S.) a barrel in 2006, a more
than 19 percent increase over the average price of $55 in 2005 (2004 $38). 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 $68.58 (Cdn) a barrel, an increase of six percent from $64.48 in 2005 (2004 $48.96).
Average realizations for Cold Lake heavy oil were higher by over 40 percent in 2006,
reflecting both increases in light crude oil prices and a narrowing price spread between light
crude oil and Cold Lake heavy oil more consistent with historical trend levels.
Prices for Canadian natural gas in 2006 were lower than the previous year. The average of
30-day spot prices for natural gas at the AECO hub in Alberta was about $7.41 a thousand cubic feet
in 2006, compared with $9.01 in 2005 (2004 $6.80). The companys average realizations on natural
gas sales were $7.24 a thousand cubic feet, compared with $9 in 2005 (2004 $6.78).
Average realizations and prices
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(Canadian dollars) | ||||||||||||||||||||
Conventional crude oil realizations (a
barrel) |
$ | 68.58 | $ | 64.48 | $ | 48.96 | $ | 40.10 | $ | 36.81 | ||||||||||
Natural gas liquids realizations (a barrel) |
40.75 | 40.00 | 33.78 | 32.09 | 23.38 | |||||||||||||||
Natural gas realizations (a thousand cubic feet) |
7.24 | 9.00 | 6.78 | 6.60 | 4.02 | |||||||||||||||
Par crude oil price at Edmonton (a barrel) |
73.75 | 69.86 | 53.26 | 43.93 | 40.44 | |||||||||||||||
Heavy oil price at Hardisty (Bow River, a barrel) |
51.90 | 45.62 | 37.98 | 33.00 | 31.85 |
Total gross production of crude oil and natural gas liquids (NGLs) averaged 272,000
barrels a day, compared with 261,000 barrels in 2005 (2004 262,000).
Gross heavy oil production at the companys wholly owned facilities at Cold Lake was a record
152,000 barrels a day, surpassing the previous record of 139,000 barrels in 2005 (2004 126,000),
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 2006 as a result of lower maintenance activities and new production
volume from the new coker unit at the Stage 3 expansion project. Gross production of upgraded crude
oil increased to 258,000 barrels a day from
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214,000 barrels in 2005 (2004 238,000). Imperials share of average gross
production increased to 65,000 barrels a day from 53,000 barrels in 2005 (2004 60,000).
Gross production of conventional oil decreased to 31,000 barrels a day from 38,000 barrels in
2005 (2004 43,000) as a result of the impact of divested properties and the natural decline in
Western Canadian reservoirs.
Gross production of NGLs available for sale averaged 24,000 barrels a day in 2006, down from
31,000 barrels in 2005 (2004 33,000), mainly due to the declining NGL content of Wizard Lake gas
production.
Gross production of natural gas decreased to 556 million cubic feet a day from 580 million
cubic feet in 2005 (2004 569 million). Lower production volumes were primarily due to the
natural decline in the Western Canadian Basin.
In 2006, the company realized a gain of $76 million on divestment of assets. In 2005, the
gain on divestment of assets was approximately $208 million.
Crude oil and NGLs production and sales (a)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||||||||||
gross | net | gross | net | gross | net | gross | net | gross | net | |||||||||||||||||||||||||||||||
(thousands of barrels a day) | ||||||||||||||||||||||||||||||||||||||||
Cold Lake |
152 | 127 | 139 | 124 | 126 | 112 | 129 | 116 | 112 | 106 | ||||||||||||||||||||||||||||||
Syncrude |
65 | 58 | 53 | 53 | 60 | 59 | 53 | 52 | 57 | 57 | ||||||||||||||||||||||||||||||
Conventional crude oil |
31 | 23 | 38 | 29 | 43 | 33 | 46 | 35 | 51 | 39 | ||||||||||||||||||||||||||||||
Total crude oil production |
248 | 208 | 230 | 206 | 229 | 204 | 228 | 203 | 220 | 202 | ||||||||||||||||||||||||||||||
NGLs available for sale |
24 | 19 | 31 | 25 | 33 | 26 | 28 | 22 | 27 | 21 | ||||||||||||||||||||||||||||||
Total crude oil and NGL production |
272 | 227 | 261 | 231 | 262 | 230 | 256 | 225 | 247 | 223 | ||||||||||||||||||||||||||||||
Cold Lake sales, including diluent (b) |
198 | 183 | 167 | 170 | 145 | |||||||||||||||||||||||||||||||||||
NGL sales |
29 | 39 | 42 | 39 | 40 |
Natural gas production and sales (a)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||||||||||||||||||||||
gross | net | gross | net | gross | net | gross | net | gross | net | |||||||||||||||||||||||||||||||
(millions of cubic feet a day) | ||||||||||||||||||||||||||||||||||||||||
Production (c) |
556 | 496 | 580 | 514 | 569 | 518 | 513 | 457 | 530 | 463 | ||||||||||||||||||||||||||||||
Sales |
513 | 536 | 520 | 460 | 499 |
(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 decreased by one percent in 2006. Lower energy and other operating costs
more than offset higher Syncrude expenses.
In November, the company announced plans to enter into a management services agreement with
Syncrude Canada Ltd., the operating company for the Syncrude joint venture. The company has a final
checkpoint in the second quarter of 2007 to confirm or cancel the agreement following completion of
an opportunity assessment study.
Petroleum products
Net income from petroleum products was $624 million or 2.4 cents a litre in 2006, compared
with $694 million or 2.6 cents a litre in 2005 (2004 $556 million or 2.1 cents a litre).
Earnings were negatively impacted by higher planned refinery maintenance and ultra-low sulphur
diesel project activities, which impacted both refinery utilization and expenses by a total of
about $100 million versus the prior year. Lower product sales volumes during the year were
primarily a result of lower refinery production and had limited impact on earnings, as the
reduction was primarily in lower margin refining and marketing sales channels. Earnings were also
negatively impacted by a stronger Canadian dollar of about $65 million. These factors were
partially offset by the net positive effect of resolution of tax matters and the impact of the tax
rate change, totalling about $55 million, and stronger refining and marketing margins.
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Financial statistics
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Net income |
$ | 624 | $ | 694 | $ | 556 | $ | 462 | $ | 147 | ||||||||||
Operating revenues (a) |
20,783 | 24,017 | 19,169 | 16,004 | 14,400 |
Sales of petroleum products
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions of litres a day (b)) | ||||||||||||||||||||
Gasolines |
32.7 | 33.4 | 33.2 | 33.0 | 32.9 | |||||||||||||||
Heating, diesel and jet fuels |
26.4 | 26.9 | 27.3 | 26.2 | 25.0 | |||||||||||||||
Heavy fuel oils |
5.1 | 6.0 | 5.9 | 5.4 | 4.9 | |||||||||||||||
Lube oils and other products |
7.7 | 7.6 | 7.0 | 5.8 | 6.4 | |||||||||||||||
Net petroleum product sales |
71.9 | 73.9 | 73.4 | 70.4 | 69.2 | |||||||||||||||
Total domestic sales of petroleum products (percent) |
96.1 | 95.3 | 93.0 | 93.3 | 91.5 | |||||||||||||||
Refinery utilization
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(thousands of barrels a day (b)) | ||||||||||||||||||||
Total refinery throughput (c) |
442 | 466 | 467 | 450 | 447 | |||||||||||||||
Refinery capacity at December 31 |
502 | 502 | 502 | 502 | 499 | |||||||||||||||
Utilization of total refinery capacity (percent) |
88 | 93 | 93 | 90 | 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-9. | |
(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 is approximately 6.3 barrels.
Margins were stronger in the refining segment of the industry in 2006. However, the
effects of stronger industry margins were reduced partially by a higher Canadian dollar. Marketing
margins in 2006 were slightly higher than the low levels of 2005.
Impacted by higher planned maintenance and ultra-low sulphur diesel project activities,
refinery utilization for 2006 at 88 percent was lower than the record performance level of 93
percent in both 2005 and 2004.
The companys total sales volumes, excluding those resulting from reciprocal supply agreements
with other companies, were 71.9 million litres a day, compared with 73.9 million litres in 2005
(2004 73.4 million). Lower refinery production was the main reason for the decline.
Operating costs in 2006 were essentially the same as the previous year.
Chemicals
Net income from chemicals operations was $143 million in 2006, the best on record, compared
with $121 million in 2005 (2004 $109 million). Improved industry margins for polyethylene and
intermediate products were the main contributors to higher earnings.
Financial statistics
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Net income |
$ | 143 | $ | 121 | $ | 109 | $ | 44 | 54 | |||||||||||
Operating revenues |
1,704 | 1,665 | 1,509 | 1,232 | 1,164 |
Sales
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(thousands of tonnes a day (a)) | ||||||||||||||||||||
Polymers and basic chemicals |
2.2 | 2.1 | 2.4 | 2.4 | 2.5 | |||||||||||||||
Intermediate and others |
0.8 | 0.9 | 0.9 | 0.9 | 1.0 | |||||||||||||||
Total chemicals |
3.0 | 3.0 | 3.3 | 3.3 | 3.5 | |||||||||||||||
(a) | Calculated by dividing total volumes for the year by the number of days in the year. |
The average industry price of polyethylene was $1,703 a tonne in 2006, essentially
unchanged from $1,708 a tonne in 2005 (2004 $1,584).
Sales of chemicals were 3,000 tonnes a day, unchanged from 2005 (2004 3,300 tonnes).
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Operating costs in the chemicals segment for 2006 were about four percent lower than 2005,
reflecting lower direct operating expenses.
Corporate and other
Net income from corporate and other was negative $99 million in 2006, compared with negative
$223 million in 2005 (2004 negative $130 million). Favourable earnings effects were due mainly
to lower share-based compensation expenses.
Liquidity and capital resources
Sources and uses of cash
2006 | 2005 | |||||||
(millions of dollars) | ||||||||
Cash provided by/(used in)
|
||||||||
Operating activities |
$ | 3,587 | $ | 3,451 | ||||
Investing activities |
(965 | ) | (992 | ) | ||||
Financing activities |
(2,125 | ) | (2,077 | ) | ||||
Increase/(decrease) in cash and cash equivalents |
497 | 382 | ||||||
Cash and cash equivalents at end of year |
$ | 2,158 | $ | 1,661 | ||||
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 as they arise.
Cash flows from operating activities are highly dependent on crude oil and natural gas prices
and product margins. In addition, the company will need to continually find and develop new
resources, and continue to develop and apply new technologies and recovery processes to existing
fields, in order to maintain or increase production and resulting cash flows in future periods.
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 $3,587 million, versus $3,451 million in 2005
(2004 $3,312 million). Increases in cash flow in 2006 were driven primarily by higher net income
and lower overall working capital balances.
Capital and exploration expenditures
Total capital and exploration expenditures were $1,209 million in 2006, compared with
$1,475 million in 2005 (2004 $1,445 million).
The funds were used mainly to invest in Cold Lake and Syncrude to maintain and expand
production capacity, improve operating efficiency, reduce the sulphur content of diesel fuel and
upgrade the network of Esso retail outlets. About $170 million was spent on projects related to
reducing the environmental impact of the companys operations and improving safety, including about
$95 million on the $500-million project to produce ultra-low sulphur diesel.
The following table shows the companys capital and exploration expenditures for natural
resources during the five years ending December 31, 2006:
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Exploration |
$ | 32 | $ | 43 | $ | 60 | $ | 57 | $ | 39 | ||||||||||
Production |
237 | 232 | 234 | 181 | 143 | |||||||||||||||
Heavy oil and oil sands |
518 | 662 | 819 | 769 | 804 | |||||||||||||||
Total capital and exploration expenditures |
$ | 787 | $ | 937 | $ | 1,113 | $ | 1,007 | $ | 986 | ||||||||||
For the natural resources segment, about 85 percent of the capital and exploration
expenditures in 2006 was focused on growth opportunities. Significant expenditures during the year
were made to ongoing development
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drilling at Cold Lake and to Syncrude for the companys share of
the Stage 3 upgrader expansion project. Sustained operation of the upgrader expansion project began
in August 2006, following a prolonged start-up period.
Other 2006 investment included drilling at conventional fields in Western Canada, advancing
the Mackenzie gas and Kearl oil sands projects, and exploration off the East Coast of Canada.
The Mackenzie gas project is facing significant cost and schedule pressures brought on by
unprecedented global demands for energy infrastructure. There are also uncertainties related to the
regulatory and permitting process and the remaining benefits and access agreements. The companys
current work efforts are focused on completing regulatory hearings, advancing approval of
permits, finalizing remaining benefits and access agreements, establishing an appropriate fiscal
framework with the federal government, advancing potential shipping agreements and continuing paced
engineering, technical and cost-reduction efforts.
Regulatory hearings by the joint federal and provincial review panel on the Kearl oil sands
project were completed in November 2006 and a decision is expected in early 2007. The companys
current efforts are focused on design optimization to improve project economics and reduce project
execution risk. Once this work is completed and a regulatory decision is received, project timing
will be determined.
Drilling of a wildcat exploration well began with co-venturers in the Orphan Basin, a frontier
basin located off the East Coast of Newfoundland. Two more exploration wells are planned by the end
of 2008. Imperial holds a 15-percent interest in eight deepwater exploration licences in the basin.
Planned capital and exploration expenditures in natural resources are expected to be about
$700 million in 2007, with over 75 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 Mackenzie gas project, the
Kearl oil sands 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, 2006:
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Marketing |
$ | 97 | $ | 91 | $ | 85 | $ | 91 | $ | 133 | ||||||||||
Refining and supply |
248 | 368 | 178 | 369 | 399 | |||||||||||||||
Other (a) |
16 | 19 | 20 | 18 | 57 | |||||||||||||||
Total capital expenditures |
$ | 361 | $ | 478 | $ | 283 | $ | 478 | $ | 589 | ||||||||||
(a) | Consists primarily of real estate purchases. |
For the petroleum products segment, capital expenditures were $361 million in 2006,
compared with $478 million in 2005 (2004 $283 million). The company invested about $95 million
in refining operations and other facilities during the year as part of a three-year, $500-million
project to reduce sulphur content in diesel. The project was completed in 2006 and the company was
able to fully meet all new government regulations on ultra-low sulphur diesel from all of its
facilities across Canada by the required schedules. More than $150 million was invested in other
refinery projects to improve energy efficiency and increase yield. Major investments were also made
to upgrade the network of Esso service stations during the year.
Capital expenditures for the petroleum products segment in 2007 are expected to be about $250
million. Major items include additional investment in the refineries on improving energy
efficiencies and increasing yield and continued enhancements to the companys retail network.
The following table shows the companys capital expenditures for its chemicals operations
during the five years ending December 31, 2006:
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Capital expenditures |
$ | 13 | $ | 19 | $ | 15 | $ | 41 | $ | 25 |
Of the capital expenditures for chemicals in 2006, the major investment focused on
improving energy efficiency and yields.
Planned capital expenditures for chemicals in 2007 will be about $15 million.
Total capital and exploration expenditures for the company in 2007, which will focus mainly on
growth and productivity improvements, are expected to total about $1 billion and will be financed
from internally generated funds.
Cash flow from financing activities
In June, the company renewed the normal course issuer bid (share-repurchase program) for
another 12 months. During 2006, the company purchased about 45.5 million shares for $1,818 million
(2005 52.5 million
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shares for $1,795 million). Since Imperial initiated its first
share-repurchase program in 1995, the company has purchased close to 800 million shares
representing about 46 percent of the total outstanding at the start of the program with
resulting distributions to shareholders of about $10.5 billion.
The company declared dividends totalling 32 cents a share in 2006, up from 31 cents in 2005
(2004 29 cents). Regular annual per-share dividends paid have increased in each of the past 12
years and, since 1986, payments per share have grown by 80 percent.
Total debt outstanding at the end of 2006, excluding the companys share of equity company
debt, was $1,437 million, compared with $1,439 million at the end of 2005 (2004 $1,443 million).
Debt represented 17 percent of the companys capital structure at the end of 2006, compared with 18
percent at the end of 2005 (2004 19 percent).
Debt-related interest incurred in 2006, before capitalization of interest, was $63 million, up
from $45 million in 2005 (2004 $37 million). The average effective interest rate on the
companys debt was 4.2 percent in 2006, compared with 3.1 percent in 2005 (2004 2.8 percent).
Financial percentages and ratios
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
Total debt as a percentage of capital (a) |
17 | 18 | 19 | 21 | 24 | |||||||||||||||
Interest coverage ratios |
||||||||||||||||||||
Earnings basis (b) |
66 | 88 | 83 | 64 | 46 | |||||||||||||||
Cash-flow basis (c) |
77 | 101 | 108 | 80 | 63 |
(a) | Current and long-term portions of debt (page F-5), 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.
Effective May 23, 2006, the issued common shares of the company were split on a three-for-one
basis and the number of authorized shares was increased from 450 million to 1,100 million. The
prior period number of shares outstanding and shares purchased, as well as net income and dividends
per share, have been adjusted to reflect the three-for-one split.
Contractual obligations
The following table shows the companys contractual obligations outstanding at December
31, 2006. It provides data for easy reference from the consolidated balance sheet and from
individual notes to the consolidated financial statements.
Financial | Payment due by period | |||||||||||||||||||
Statement | ||||||||||||||||||||
Note Reference | ||||||||||||||||||||
2008 to | 2012 and | Total | ||||||||||||||||||
2007 | 2011 | beyond | Amount | |||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Long-term debt and capital leases(a) |
Note 4 | $ | 907 | $ | 332 | $ | 27 | $ | 1,266 | |||||||||||
Operating leases(b) |
Note 11 | 53 | 172 | 48 | 273 | |||||||||||||||
Unconditional purchase obligations(c) |
Note 11 | 58 | 167 | 40 | 265 | |||||||||||||||
Firm capital commitments(d) |
Note 11 | 149 | 29 | | 178 | |||||||||||||||
Pension and other post-retirement obligations(e) |
Note 6 | 226 | 173 | 669 | 1,068 | |||||||||||||||
Asset retirement obligations(f) |
Note 7 | 52 | 282 | 88 | 422 | |||||||||||||||
Other long-term agreements(g) |
Note 11 | 271 | 677 | 240 | 1,188 |
(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 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 2006 was $41 million associated with the companys share of capital projects at Syncrude. | |
(e) | The amount by which the projected 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 2007 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 agreements include primarily raw material supply and transportation services agreements. |
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The company was contingently liable at December 31, 2006, for a maximum of $87 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.
Various lawsuits are pending 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. There are no events or uncertainties known to
management beyond those already included in reported financial information that would indicate a
material change in future operating results or financial condition.
Recently issued Statement of Financial Accounting Standards
Accounting for uncertainty in income taxes
In June 2006, the Financial Accounting Standards Board (FASB) issued 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 must be adopted by the company no later than
January 1, 2007. The interpretation 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 tax returns. The new standard requires that a tax benefit be
recognized in the books only if it is more likely than not that a tax position will be sustained.
Otherwise, a liability will need to be recorded to reflect the difference between the as-filed tax
basis and the book tax basis. The new standard does not allow a restatement of the comparative
prior periods.
The company expects to recognize a transition gain of approximately $14 million in
shareholders equity upon adoption of FIN 48 in the first quarter of 2007. This gain reflects the
recognition of several refund claims and associated interest, partly offset by increased liability
reserves.
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 with 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 commitment toward the development of the
reserves prior to booking.
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 and significant changes in long-term oil and gas price levels.
Beginning in 2004, 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. Regulations preclude the company
from showing in 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
28
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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 to
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 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 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 and gas 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 significantly, industry prices
over the long term will continue to be driven by market supply and demand. Accordingly, any
impairment tests that the company performs make use of the companys price assumptions developed in
the annual planning and budgeting process for the crude oil and natural gas markets, petroleum
products and chemicals. These are the same price assumptions that are used for capital investment
decisions. The corporate plan is a fundamental annual management process that is the basis for
setting near-term risk assessed operating and capital objectives in addition to providing the
longer-term economic assumptions used for investment evaluation purposes. Any impairment tests that
the company performs also make use of annual volumes based on individual field production profiles,
which are also updated as part of the annual plan process.
The standardized measure of discounted future cash flows on page 35 is based on the year-end
2006 price applied for all future years, as required under Statement of Financial Accounting
Standards No. 69 (SFAS 69). Future 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
29
Table of Contents
in
market rates and outlook. The long-term expected rate of return on plan assets of 8.25 percent used
in 2006 compares to actual returns of 9.82 percent and 9.99 percent achieved over the last 10- and
20- year periods ending December 31, 2006. 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 versus long-term expected returns are
not recorded in pension expense in the year the differences occur, but rather are amortized in
pension expense as permitted by GAAP, along with other actuarial gains and losses, over the
expected remaining service life of employees. Pension expense represented less than one percent of
total expenses in 2006.
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 2006, the obligations were discounted at
six percent and the accretion expense was $22 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.
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 October 2006, the Government of Canada indicated its intent to introduce regulations to
control greenhouse-gas emissions from major industrial facilities, although details of what
measures will be imposed on companies have not been determined. Consequently, attempts to assess
the impact on Imperial can only be speculative. The company will continue to monitor the
development of legal requirements in this area.
Other risks, such as changes in international commodity prices and currency-exchange rates,
are beyond the companys control. The companys size, strong financial position and the
complementary nature of its natural resources, petroleum products and chemicals segments help
mitigate the companys exposure to changes in these other risks. The companys potential exposure
to these types of risks is summarized in the earnings sensitivity table below.
The company does not use derivative markets to speculate on the future direction of currency
or commodity prices and does not sell forward any part of production from any business segment.
30
Table of Contents
The following table 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 | ||||||||
Six dollars (U.S.) a barrel change in crude oil prices |
+(- | ) | $ | 270 | ||||
Ninety cents a thousand cubic feet change in natural gas prices |
+(- | ) | 27 | |||||
One cent (U.S) a litre change in sales margins for total petroleum products |
+(- | ) | 175 | |||||
One cent (U.S.) a pound change in sales margins for polyethylene |
+(- | ) | 7 | |||||
One-quarter percent decrease (increase) in short-term interest rates |
+(- | ) | 2 | |||||
Nine 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 2006. 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 the Canadian dollar versus the U.S. dollar
decreased from year-end 2005 by about $8 million (after tax) a year for each one-cent change,
primarily due to the decrease in industry refining margins.
The sensitivity to changes in natural gas prices decreased from 2005 year-end by about $3
million (after tax) for each 10-cent change, primarily due to the companys lower natural gas
production.
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 15 to 45 metres (50 to 150 feet) of overburden, have
bitumen grades ranging from 4 to 14 weight percent and ore thickness of 35 to 50 metres (115 to 160
feet). Estimates of synthetic crude oil reserves are based on detailed geological and engineering
assessments of in-place crude bitumen 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 125 metres (150 wells per
section) and in future mining areas, the well spacing is approximately 350 metres (20 wells per
section). Proven reserves include the operating Base and North mines and the Aurora mine. In
accordance with the long range mine plan approved by the Syncrude owners, there are an estimated
1,675 million tonnes (1,845 million tons) of extractable oil sands in the Base and North mines,
with an average bitumen grade of 10.6 weight percent. In addition, at the Aurora mine, there are an
estimated 4,155 million tonnes (4,580 million tons) of extractable oil sands at an average bitumen
grade of 11.2 weight percent. After deducting royalties payable to the Province of Alberta, the
company estimates its 25 percent net share of proven reserves at year end 2006 was equivalent to
114 million cubic metres (718 million barrels) of synthetic crude oil. Imperials reserve
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.
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 cubic metres) | ||||||||||||
Beginning of year 2004 |
53 | 71 | 124 | |||||||||
Revision of previous estimate |
(16 | ) | 16 | | ||||||||
Production |
(2 | ) | (2 | ) | (4 | ) | ||||||
End of year 2004 |
35 | 85 | 120 | |||||||||
Revision of previous estimate |
| | | |||||||||
Production |
(1 | ) | (2 | ) | (3 | ) | ||||||
End of year 2005 |
34 | 83 | 117 | |||||||||
Revision of previous estimate |
| | | |||||||||
Production |
(2 | ) | (1 | ) | (3 | ) | ||||||
End of year 2006 |
32 | 82 | 114 | |||||||||
31
Table of Contents
Synthetic Crude Oil | ||||||||||||
Base mine and | Aurora mine | Total | ||||||||||
North mine | ||||||||||||
(millions of barrels) | ||||||||||||
Beginning of year 2004 |
331 | 450 | 781 | |||||||||
Revision of previous estimate |
(103 | ) | 100 | (3 | ) | |||||||
Production |
(11 | ) | (10 | ) | (21 | ) | ||||||
End of year 2004 |
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 | |||||||||
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
2006 | 2005 | 2004 | ||||||||||
(millions of dollars) | ||||||||||||
Sales to customers (1) |
$ | 2,601 | $ | 2,739 | $ | 2,160 | ||||||
Intersegment sales(1) (2) |
1,251 | 1,013 | 976 | |||||||||
$ | 3,852 | $ | 3,752 | $ | 3,136 | |||||||
Production expenses |
1,016 | 1,035 | 870 | |||||||||
Exploration expenses |
32 | 31 | 44 | |||||||||
Depreciation and depletion |
467 | 583 | 565 | |||||||||
Income taxes |
564 | 716 | 547 | |||||||||
Results of operations |
$ | 1,773 | $ | 1,387 | $ | 1,110 | ||||||
Capital and exploration expenditures
2006 | 2005 | 2004 | ||||||||||
(millions of dollars) | ||||||||||||
Property costs(3) |
||||||||||||
Proved |
$ | | $ | | $ | | ||||||
Unproved |
| 7 | 1 | |||||||||
Exploration costs |
32 | 37 | 43 | |||||||||
Development costs |
496 | 330 | 408 | |||||||||
Total capital and exploration expenditures |
$ | 528 | $ | 374 | $ | 452 | ||||||
Property, plant and equipment
2006 | 2005 | |||||||
(millions of dollars) | ||||||||
Property costs(3) |
||||||||
Proved |
$ | 3,226 | $ | 3,231 | ||||
Unproved |
139 | 162 | ||||||
Producing assets |
6,392 | 6,111 | ||||||
Support facilities |
184 | 174 | ||||||
Incomplete construction |
595 | 432 | ||||||
Total cost |
$ | 10,536 | $ | 10,110 | ||||
Accumulated depreciation and depletion |
7,326 | 6,934 | ||||||
Net property, plant and equipment |
$ | 3,210 | $ | 3,176 | ||||
(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. |
32
Table of Contents
Oil and Gas Reserves
Crude oil and natural gas liquids | Natural Gas | |||||||||||||||
Conventional | Heavy Oil (2) | Total | Total | |||||||||||||
(millions of cubic metres) | (billions of cubic | |||||||||||||||
metres) | ||||||||||||||||
Proved developed and undeveloped reserves (1) |
||||||||||||||||
Beginning of year 2004 |
20 | 121 | 141 | 29 | ||||||||||||
Revisions and improved recovery |
1 | (78 | ) | (77 | ) | (2 | ) | |||||||||
(Sale)/purchase of reserves in place |
| | | | ||||||||||||
Discoveries and extensions |
| | | | ||||||||||||
Production |
(3 | ) | (6 | ) | (9 | ) | (5 | ) | ||||||||
End of year 2004 |
18 | 37 | 55 | 22 | ||||||||||||
Revisions and improved recovery |
| 56 | 56 | 4 | ||||||||||||
(Sale)/purchase of reserves in place |
(2 | ) | | (2 | ) | | ||||||||||
Discoveries and extensions |
| 2 | 2 | | ||||||||||||
Production |
(3 | ) | (7 | ) | (10 | ) | (5 | ) | ||||||||
End of year 2005 |
13 | 88 | 101 | 21 | ||||||||||||
Revisions and improved recovery |
| 37 | 37 | 4 | ||||||||||||
(Sale)/purchase of reserves in place |
| | | | ||||||||||||
Discoveries and extensions |
| | | | ||||||||||||
Production |
(2 | ) | (7 | ) | (9 | ) | (5 | ) | ||||||||
End of year 2006 |
11 | 118 | 129 | 20 | ||||||||||||
(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 101.325 kilopascals absolute at 15 degrees Celsius. | |
(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. |
Crude oil and natural gas liquids | Natural Gas | |||||||||||||||
Conventional | Heavy Oil(2) | Total | Total | |||||||||||||
(millions of barrels) | (billions of | |||||||||||||||
cubic feet) | ||||||||||||||||
Beginning of year 2004 |
126 | 763 | 889 | 1,023 | ||||||||||||
Revisions and improved recovery |
11 | (490 | ) | (479 | ) | (32 | ) | |||||||||
(Sale)/purchase of reserves in place |
| | | (13 | ) | |||||||||||
Discoveries and extensions |
| | | 3 | ||||||||||||
Production |
(22 | ) | (41 | ) | (63 | ) | (190 | ) | ||||||||
End of year 2004 |
115 | 232 | 347 | 791 | ||||||||||||
Revisions and improved recovery |
| 350 | 350 | 137 | ||||||||||||
(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 and improved recovery |
4 | 236 | 240 | 140 | ||||||||||||
(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 | ||||||||||||
(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. |
33
Table of Contents
The information on the previous page describes changes during the years and balances of
proved oil and gas and reserves at year-end 2004, 2005 and 2006. 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. Beginning in 2004, 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.
Regulations preclude the company from showing in 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 to 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.
Net proved reserves are determined by deducting the estimated future share of mineral owners
or governments or both. For conventional crude oil (excluding enhanced oil-recovery projects) and
natural gas, net proved reserves are based on estimated future royalty rates representative of
those existing as of the date the estimate is made. Actual future royalty rates may vary with
production and price. For enhanced oil-recovery projects and Cold Lake, net proved reserves are
based on the companys best estimate of average royalty rates over the life of each project. Actual
future royalty rates may vary with production, price and costs.
Reserves data do not include crude oil and natural gas, such as those discovered in the
Beaufort Sea-Mackenzie Delta and the Arctic islands, or the heavy oil and oil sands, other than
reserves attributable to commercial phases of Cold Lake production operations.
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)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions) | ||||||||||||||||||||
Crude Oil: |
||||||||||||||||||||
Conventional |
||||||||||||||||||||
Cubic metres |
11 | 13 | 18 | 20 | 23 | |||||||||||||||
Barrels |
71 | 83 | 115 | 126 | 146 | |||||||||||||||
Heavy Oil |
||||||||||||||||||||
Cubic metres |
118 | 88 | 37 | 121 | 127 | |||||||||||||||
Barrels |
741 | 551 | 232 | 763 | 801 | |||||||||||||||
Total |
||||||||||||||||||||
Cubic metres |
129 | 101 | 55 | 141 | 150 | |||||||||||||||
Barrels |
812 | 634 | 347 | 889 | 947 | |||||||||||||||
Natural Gas
|
(billions) | |||||||||||||||||||
Cubic metres |
20 | 21 | 22 | 29 | 35 | |||||||||||||||
Cubic feet |
710 | 747 | 791 | 1,023 | 1,224 |
(1) | Net reserves are the companys share of reserves after deducting the shares of mineral owners or governments or both. |
34
Table of Contents
Net proved developed reserves of crude oil and natural gas as of December 31(1)
2006 | 2005 | 2004 | 2003 | 2002 | ||||||||||||||||
(millions) | ||||||||||||||||||||
Crude Oil: |
||||||||||||||||||||
Conventional |
||||||||||||||||||||
Cubic metres |
11 | 13 | 18 | 19 | 22 | |||||||||||||||
Barrels |
71 | 81 | 111 | 121 | 139 | |||||||||||||||
Heavy Oil |
||||||||||||||||||||
Cubic metres |
80 | 58 | 37 | 63 | 49 | |||||||||||||||
Barrels |
501 | 368 | 232 | 398 | 308 | |||||||||||||||
Total |
||||||||||||||||||||
Cubic metres |
91 | 71 | 55 | 82 | 71 | |||||||||||||||
Barrels |
572 | 449 | 343 | 519 | 447 | |||||||||||||||
Natural Gas |
(billions) | |||||||||||||||||||
Cubic metres |
17 | 18 | 20 | 24 | 27 | |||||||||||||||
Cubic feet |
608 | 643 | 704 | 859 | 959 |
(1) | Net reserves are the companys share of reserves after deducting the shares of mineral owners or governments or both. |
Standardized measure of discounted future net cash flows related to proved oil and gas
reserves
As required by the Financial Accounting Standards Board, 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.
2006 | 2005 | 2004 | ||||||||||
(millions of dollars) | ||||||||||||
Future cash flows |
$ | 36,751 | $ | 21,911 | $ | 11,625 | ||||||
Future production costs |
(16,290 | ) | (11,376 | ) | (3,123 | ) | ||||||
Future development costs |
(2,633 | ) | (2,039 | ) | (1,492 | ) | ||||||
Future income taxes |
(5,039 | ) | (2,777 | ) | (2,260 | ) | ||||||
Future net cash flows |
12,789 | 5,719 | 4,750 | |||||||||
Annual discount of 10 percent for estimated timing of cash flows |
(6,374 | ) | (1,405 | ) | (1,433 | ) | ||||||
Discounted future net cash flows |
$ | 6,415 | $ | 4,314 | $ | 3,317 | ||||||
Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves
2006 | 2005 | 2004 | ||||||||||
(millions of dollars) | ||||||||||||
Balance at beginning of year |
$ | 4,314 | $ | 3,317 | $ | 4,738 | ||||||
Changes resulting from: |
||||||||||||
Sales and transfers of oil and gas produced, net of production costs |
(2,839 | ) | (2,650 | ) | (2,240 | ) | ||||||
Net changes in prices, development costs and production costs |
4,221 | 3,343 | (3,692 | ) | ||||||||
Extensions, discoveries, additions and improved recovery, less related costs |
(4 | ) | (513 | ) | (43 | ) | ||||||
Development costs incurred during the year |
411 | 272 | 345 | |||||||||
Revisions of previous quantity estimates |
87 | 660 | 1,838 | |||||||||
Accretion of discount |
568 | 417 | 663 | |||||||||
Net change in income taxes |
(343 | ) | (532 | ) | 1,708 | |||||||
Net change |
2,101 | 997 | (1,421 | ) | ||||||||
Balance at end of year |
$ | 6,415 | $ | 4,314 | $ | 3,317 | ||||||
Within the past 12 months, the company has not filed oil and gas reserve estimates with
any authority or agency of the United States.
35
Table of Contents
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 31.1 and 31.2 of this report, the
companys principal executive officer and principal financial officer have evaluated the companys
disclosure controls and procedures as of December 31, 2006. Based on that evaluation, these
officers have concluded that the companys disclosure controls and procedures are appropriate and
effective for the purpose of ensuring that material information relating to the company, including
its consolidated subsidiaries, is made known to them by others within those entities, particularly
during the period in which this annual report is being prepared.
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 managements assessment on internal control over financial reporting.
There has not been any change in the companys internal control over financial reporting that
occurred during the companys fourth fiscal quarter of 2006 that has materially affected, or is
reasonably likely to materially affect, the companys internal control over financial reporting.
36
Table of Contents
PART III
Item 10. Directors and Executive Officers of the Registrant.
The company currently has eight directors. Each director is elected to hold office until
the close of the next annual meeting.
Each of the eight directors listed below has been nominated for re-election at the annual
meeting of shareholders to be held May 1, 2007. All of the nominees are now directors and have been
since the dates indicated.
The following table provides information on the nominees for election as directors.
Last major | ||||||||||
position or office with the | ||||||||||
Name and current principal | company or Exxon Mobil | |||||||||
occupation or employment | Corporation | Director since | Holdings (3)(4)(5) | |||||||
R.L. (Randy) Broiles |
Global planning manager, | July 21, 2005 | Common shares of | |||||||
Senior vice-president, |
ExxonMobil Production | Imperial Oil Limited | 5,000 | |||||||
resources division, |
Company | Deferred share units of | ||||||||
Imperial Oil Limited |
Imperial Oil Limited | 0 | ||||||||
Restricted stock units of | ||||||||||
Imperial Oil Limited | 0 | |||||||||
Shares of Exxon Mobil | ||||||||||
Corporation(6) | 59,641 | |||||||||
T.J. (Tim) Hearn |
President, | January 1, 2002 | Common shares of | |||||||
Chairman, president and |
Imperial Oil Limited | Imperial Oil Limited | 92,597 | |||||||
chief executive officer, |
Deferred share units of | |||||||||
Imperial Oil Limited |
Imperial Oil Limited | 305 | ||||||||
Restricted stock units of | ||||||||||
Imperial Oil Limited | 681,400 | |||||||||
Shares of | ||||||||||
Exxon Mobil Corporation | 10,106 | |||||||||
J.M. (Jack) Mintz |
| April 21, 2005 | Common shares of | |||||||
Professor, Joseph L. Rotman |
Imperial Oil Limited | 1,000 | ||||||||
School of Management, |
Deferred share units | |||||||||
University of Toronto (1)(2) |
of Imperial Oil Limited | 394 | ||||||||
Restricted stock units | ||||||||||
of Imperial Oil Limited | 6,000 | |||||||||
Shares of | ||||||||||
Exxon Mobil Corporation | 0 | |||||||||
R. (Roger) Phillips |
| April 23, 2002 | Common shares of | |||||||
Retired president and |
Imperial Oil Limited | 9,000 | ||||||||
chief executive officer, |
Deferred share units of | |||||||||
IPSCO Inc. |
Imperial Oil Limited | 13,503 | ||||||||
(steel manufacturing)(1)(2) |
Restricted stock units | |||||||||
of Imperial Oil Limited | 11,625 | |||||||||
Shares of | ||||||||||
Exxon Mobil Corporation | 2,000 |
(Table continued on following page)
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Table of Contents
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) | |||||||
J.F. (Jim) Shepard |
| October 21, 1997 | Common shares of | |||||||
Retired chairman and |
Imperial Oil Limited | 9,000 | ||||||||
chief executive officer, |
Deferred share units of | |||||||||
Finning International Inc. |
Imperial Oil Limited | 21,428 | ||||||||
(sale, lease, repair and |
Restricted stock units of | |||||||||
financing of heavy |
Imperial Oil Limited | 11,625 | ||||||||
equipment)(1)(2) |
Shares of | |||||||||
Exxon Mobil Corporation | 0 | |||||||||
P.A. (Paul) Smith |
Corporate finance manager, | February 1, 2002 | Common shares of | |||||||
Controller and |
Exxon Mobil Corporation | Imperial Oil Limited | 13,371 | |||||||
senior vice-president, |
Deferred share units of | |||||||||
finance and administration, |
Imperial Oil Limited | 0 | ||||||||
Imperial Oil Limited(2) |
Restricted stock units of | |||||||||
Imperial Oil Limited | 192,000 | |||||||||
Shares of | ||||||||||
Exxon Mobil Corporation | 1,190 | |||||||||
S.D. (Sheelagh) Whittaker |
| April 19, 1996 | Common shares of | |||||||
Retired managing director, |
Imperial Oil Limited | 9,000 | ||||||||
Electronic Data Systems |
Deferred share units of | |||||||||
Limited (business and |
Imperial Oil Limited | 28,957 | ||||||||
information technology |
Restricted stock units of | |||||||||
services)(1)(2) |
Imperial Oil Limited | 11,625 | ||||||||
Shares of | ||||||||||
Exxon Mobil Corporation | 0 | |||||||||
V.L. (Victor) Young |
| April 23, 2002 | Common shares of | |||||||
Corporate director of several |
Imperial Oil Limited | 10,250 | ||||||||
corporations (1)(2) |
Deferred share units of | |||||||||
Imperial Oil Limited | 4,961 | |||||||||
Restricted stock units | ||||||||||
of Imperial Oil Limited | 11,625 | |||||||||
Shares of Exxon Mobil | ||||||||||
Corporation | 0 |
(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 45 and pages 46 and 47, respectively. | |
(5) | 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 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 16,641 common shares and 43,000 restricted shares 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 49, Timothy J. Hearn 62, Jack M. Mintz 55, Roger
Phillips 67, James F. Shepard 68, Paul A. Smith 53, Sheelagh D. Whittaker 59, Victor L. Young 61,
Rob F. Lipsett 60, and John F. Kyle 64.
Certain of the directors hold positions as directors of other Canadian and U.S. reporting
issuers as follows: Timothy J. Hearn Royal Bank of Canada; Jack M. Mintz Brookfield Asset
Management Inc. and CHC Helicopter Corporation; Roger Phillips Canadian Pacific Railway Company,
Canadian Pacific Railway Limited, Cleveland-
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Cliffs Inc. and The Toronto-Dominion Bank; Sheelagh D.
Whittaker CanWest Media Works Income Fund; 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 Jack M. Mintz 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, Jack M. Mintz was
president and chief executive officer of The C.D. Howe Institute until he retired in July 2006
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.
Name and Office | Office held since | |
Timothy J. Hearn
|
April 23, 2002 | |
chairman of the board, president |
||
and chief executive officer |
||
Paul A. Smith
|
February 1, 2002 | |
controller and senior vice-president, |
||
finance and administration |
||
Randy L. Broiles
|
July 1, 2005 | |
senior vice-president, resources division |
||
Rob F. Lipsett
|
October 1, 1999 | |
vice-president, human resources |
||
John F. Kyle
|
June 1, 1991 | |
vice-president and treasurer |
All of the above senior executives have been engaged for more than five years at their current
occupations or in other executive capacities with the company or its affiliates. All senior
executives hold office until their appointment is rescinded by the directors, or by the chief
executive officer.
Audit committee
The company has an audit committee of the board of directors. The following directors are 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.
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
39
Table of Contents
executive and officer positions, including the chief executive officer. During 2006, 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
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. The appraisal program is a disciplined annual program that assesses business performance
measures relevant to each employee, including the means by which performance is achieved, and
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 which has been in place for more than 50 years and
is 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.
Base Salary
The companys salary ranges for executives were increased by 1.5 percent in 2005,
2.5 percent in 2006 and eight percent in 2007. The larger increase in 2007 was required
to maintain 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 about 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 2006, the overall bonus pool was increased by 7.5 percent over the previous year to reflect
improved financial results and operating performance. In relation to this, the companys net income
for 2006 was a record $3.044 billion (up 17 percent ), return on shareholders equity was 44
percent, return on capital employed was 36 percent and total annual shareholders return was 13
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 in use today. This plan is made available to selected executives to promote
individual contribution to sustained 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 2006, 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 2006, similar to the cash
bonus pool, the earnings bonus units pool was increased by 7.5 percent over the previous year.
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Table of Contents
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 non employee 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 past 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 compared to earlier years.
Each unit granted in 2006 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 2006, 964 employees were granted restricted stock units, including 92 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 operation.
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 cash bonus was increased by 11
percent in 2006 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 an 11 percent increase in his earnings bonus unit award compared to 2005 for the same
reasons noted above for Mr. Hearns cash bonus award.
For 2006, the committee adjusted the restricted stock unit grant for T.J. Hearn on an
approximately two-for-one basis, as compared to the share split of three-for-one. This was
consistent with the treatment for all other high performing executives and had the effect of
reducing the award value on the grant date for T.J. Hearn.
Directors compensation
Directors fees are paid only to non-employee directors. For 2006, non-employee directors were
paid an annual retainer of $35,000 and 3,000 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 non-employee directors have the same
features as the restricted stock units for selected key employees described on pages 46 and 47.
Starting in 1999, the non-employee directors have been able to receive all or part of their
directors fees in the form of deferred share units for non-employee directors. The purpose of the
deferred share unit plan for non-employee 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 45.
While serving as directors in 2006, the aggregate cash remuneration paid to non-employee
directors, as a group, was $418,125, and they received an additional 4,953 deferred share units,
based on an aggregate of $234,375 of cash remuneration elected to be received as deferred share
units. The non-employee directors, as a group, received an additional 444 deferred share units
granted as the equivalent to the cash dividend paid on company shares during 2006 for previously
granted deferred share units. In addition, the non-employee directors received 15,000 restricted
stock units.
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Table of Contents
Senior executive compensation
Summary Compensation Table
The following table shows the compensation for the chairman, president and chief executive
officer and the four other senior executives of the company who were serving as senior executives
at the end of 2006. This information includes the dollar value of base salaries, cash bonus awards,
and units of other long term incentive compensation and certain other compensation.
Annual Compensation | Long-Term Compensation | |||||||||||||||||||||||||||||||||||||||
Awards | Payouts | |||||||||||||||||||||||||||||||||||||||
Shares or | Shares or | |||||||||||||||||||||||||||||||||||||||
Securities | Units | Units | ||||||||||||||||||||||||||||||||||||||
under | Subject to | Subject to | ||||||||||||||||||||||||||||||||||||||
Other Annual | options/ | Resale | Resale | LTIP | All Other | Total | ||||||||||||||||||||||||||||||||||
Name and | Bonus | Compensation | SARs | Restrictions | Restrictions | Payouts | Compensation | Compensation | ||||||||||||||||||||||||||||||||
Principal | Salary | (2) | (3) | Granted (4) | (5)(6) | (5)(6) | (7) | (8) | (9) | |||||||||||||||||||||||||||||||
Position | Year | ($) | ($) | ($) | (#) | (#) | ($) | ($) | ($) | ($) | ||||||||||||||||||||||||||||||
T.J.Hearn |
2006 | 1,140,000 | 1,000,050 | 562,665 | | 130,000 | 5,623,800 | 900,000 | 34,200 | 9,260,801 | ||||||||||||||||||||||||||||||
Chairman, |
restricted | |||||||||||||||||||||||||||||||||||||||
president and |
stock units | |||||||||||||||||||||||||||||||||||||||
chief executive |
2 | 86 | ||||||||||||||||||||||||||||||||||||||
officer |
deferred | |||||||||||||||||||||||||||||||||||||||
share units | ||||||||||||||||||||||||||||||||||||||||
2005 | 1,100,000 | 900,000 | 385,028 | | 193,200 | 7,432,404 | 870,000 | 33,000 | 10,720,52 | |||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||
3 | 94 | |||||||||||||||||||||||||||||||||||||||
deferred | ||||||||||||||||||||||||||||||||||||||||
share units | ||||||||||||||||||||||||||||||||||||||||
2004 | 1,000,000 | 872,266 | 246,249 | | 193,200 | 4,582,060 | 750,000 | 30,000 | 7,487,609 | |||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||
300 | 7,034 | |||||||||||||||||||||||||||||||||||||||
deferred | ||||||||||||||||||||||||||||||||||||||||
share units | ||||||||||||||||||||||||||||||||||||||||
P.A. Smith |
2006 | 404,167 | 197,267 | 111,279 | | 35,100 | 1,518,426 | 193,050 | 24,250 | 2,448,439 | ||||||||||||||||||||||||||||||
Controller and |
restricted | |||||||||||||||||||||||||||||||||||||||
senior vice- |
stock units | |||||||||||||||||||||||||||||||||||||||
president, |
2005 | 398,333 | 193,675 | 87,198 | | 55,200 | 2,123,544 | 193,125 | 23,900 | 3,019,775 | ||||||||||||||||||||||||||||||
finance and |
restricted | |||||||||||||||||||||||||||||||||||||||
administration |
stock units | |||||||||||||||||||||||||||||||||||||||
2004 | 378,333 | 193,600 | 67,022 | | 57,900 | 1,373,195 | 183,000 | 22,700 | 2,217,850 | |||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||
R.L. Broiles (1) |
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 | ||||||||||||||||||||||||||||||
Senior vice- |
restricted | |||||||||||||||||||||||||||||||||||||||
president, |
stock units | |||||||||||||||||||||||||||||||||||||||
resources |
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 | ||||||||||||||||||||||||||||||
division (from |
restricted | |||||||||||||||||||||||||||||||||||||||
July 1,2005) |
stock units | |||||||||||||||||||||||||||||||||||||||
R.F. Lipsett |
2006 | 364,583 | 191,406 | 140,106 | | 28,800 | 1,245,888 | 178,650 | 10,938 | 2,131,571 | ||||||||||||||||||||||||||||||
Vice-president, |
restricted | |||||||||||||||||||||||||||||||||||||||
human |
stock units | |||||||||||||||||||||||||||||||||||||||
resources |
2005 | 360,000 | 178,850 | 107,810 | | 42,300 | 1,627,281 | 178,500 | 10,800 | 2,463,241 | ||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||
2004 | 340,000 | 179,000 | 78,581 | | 47,100 | 1,117,055 | 166,700 | 10,200 | 1,891,536 | |||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||
J.F. Kyle |
2006 | 365,000 | 119,145 | 124,081 | | 20,800 | 899,808 | 112,500 | 21,900 | 1,642,434 | ||||||||||||||||||||||||||||||
Vice-president |
restricted | |||||||||||||||||||||||||||||||||||||||
and treasurer |
stock units | |||||||||||||||||||||||||||||||||||||||
2005 | 364,166 | 112,500 | 90,821 | | 33,900 | 1,304,133 | 171,375 | 21,850 | 2,064,845 | |||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||
2004 | 359,583 | 172,105 | 74,585 | | 39,600 | 939,180 | 171,000 | 21,575 | 1,738,028 | |||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||
stock units |
42
Table of Contents
(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 Exxon Mobil Corporation in United States dollars, and is disclosed in United States dollars. Also, he received employee benefits under Exxon Mobil Corporations employee benefit plans, and not under the companys employee benefit plans. The company reimburses Exxon Mobil Corporation for the compensation paid and employee benefits provided to him. | |
(2) | Any part of bonus elected to be received as deferred share units is excluded. | |
(3) | Amounts under Other Annual Compensation, except for 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 2006, the dividend equivalent payments were $195,792 for T.J. Hearn, $55,308 for P.A. Smith, $44,628 for R.F. Lipsett and $38,112 for J.F. Kyle. In 2006, the interest paid in respect of deferred payments of bonuses and earnings bonus units was $228,293 for T.J. Hearn, $10,971 for P.A. Smith, $58,746 for R.F. Lipsett and $37,185 for J.F. Kyle. Also included is an earned benefits allowance. The earned benefits allowance in 2006 was $90,000 for T.J. Hearn, $45,000 for P.A. Smith, $35,000 for R.F. Lipsett and $35,000 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 46. | |
(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 46 and 47 and page 45, respectively. The number of restricted stock units and deferred share units for 2006 are the number of units actually received. The numbers shown for restricted stock units and deferred share units for 2004 and 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 $23.72 in 2004, $38.47 in 2005 and $43.26 for 2006 (all on a post-split basis). The values of the deferred share units shown are the number of units multiplied by the closing price of the companys shares for the five consecutive days before the grant of the deferred share unit. T.J. Hearn is the only senior executive who holds deferred share units. 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 was granted 11,000 restricted shares in 2006, whose value on the date of grant (November 28, 2006) was $815,760 U.S., based on a closing price of Exxon Mobil Corporation shares on the date of grant of $74.16 U.S. | |
(6) | The table below shows the number and value of restricted stock units and deferred share units held as of December 31, 2006. 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 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, 2006 was $42.93. 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 43,000 restricted shares whose value on December 31, 2006 was $3,295,090 U.S. based on a closing price for Exxon Mobil Corporation shares on December 31, 2006 of $76.63 U.S. |
Restricted Stock Units | Deferred Share Units | |||||||||||||||
Name | Total (#) | Total ($) | Total (#) | Total ($) | ||||||||||||
T.J. Hearn |
681,400 | 29,252,502 | 305 | 13,094 | ||||||||||||
P.A. Smith |
192,000 | 8,242,560 | 0 | 0 | ||||||||||||
R.L. Broiles |
| | | | ||||||||||||
R.F. Lipsett |
154,650 | 6,639,125 | 0 | 0 | ||||||||||||
J.F. Kyle |
127,300 | 5,464,989 | 0 | 0 |
(7) | Payouts were from 2005 earnings bonus unit that reached maximum value of $4.50 per unit in 2006. That plan is described on page 46. R.L. Broiles participates in Exxon Mobil Corporations earnings bonus unit plan, which is similar to the companys earnings bonus unit plan. | |
(8) | Amounts under All Other Compensation, except for R.L. Broiles, are the companys contributions to the savings plan, which is a plan available to all employees. Under one of the options of that plan to which the senior executives subscribe, except for R.L. Broiles, the company matched employee contributions up to six percent of base salary per year; however, an employee may elect to receive an enhanced pension under the companys pension plan by foregoing three percent of the companys matching contributions. The plan is intended to be primarily for retirement savings, although employees may withdraw their contributions prior to retirement. For R.L. Broiles, the amount is Exxon Mobil Corporations contributions to its employee savings plan. | |
(9) | Total Compensation for each of 2004, 2005 and 2006 consists of the total dollar value of Salary, Bonus, Other Annual Compensation, Shares or Units Subject to Resale Restrictions, LTIP Payouts and All Other Compensation for each such year. |
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Earnings Bonus Unit Plan awards in most recently completed financial year
The following table provides information on earnings bonus units granted in 2006 to the
named senior executives. The earnings bonus unit plan is described in more detail on
page 46.
Performance | |||||||||||||||||||||||
Securities | or Other | Estimated Future Payouts Under | |||||||||||||||||||||
Units or | Period Until | Non-Securities-Price Based Plans | |||||||||||||||||||||
Other Rights | Maturation or | Threshold | Target | Maximum | |||||||||||||||||||
Name | (#) | Payout (1) | ($) | ($)(2) | ($)(2) | ||||||||||||||||||
T.J. Hearn |
571,400 | Nov. 20, 2011 | 0 | 1.75 | 1.75 | ||||||||||||||||||
P.A. Smith |
112,700 | Nov. 20, 2011 | 0 | 1.75 | 1.75 | ||||||||||||||||||
R.L. Broiles(3) |
| | | | | ||||||||||||||||||
R.F. Lipsett |
109,200 | Nov. 20, 2011 | 0 | 1.75 | 1.75 | ||||||||||||||||||
J.F. Kyle |
68,000 | Nov. 20, 2011 | 0 | 1.75 | 1.75 |
(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 2006. | |
(3) | R.L. Broiles participates in Exxon Mobil Corporations earnings bonus unit plan which is similar to the companys earnings bonus unit plan. In 2006, R.L Broiles was granted 37,474 units under that plan for which the maximum settlement value payable per earnings bonus unit is $4.25 U.S. |
Aggregated option/SAR exercises during the most recently completed financial year and
financial year end option/SAR values
The following table provides information on the exercise in 2006 and the aggregate holdings at
the end of 2006 of incentive share units (referred to in the table as SARs) by the named senior
executives. The incentive share unit plan is described in more detail on page 45. The number of
incentive share units in the table below is equal to three times the number of incentive share
units held before the three-for-one share split in May 2006.
Value of | ||||||||||||||||||||||||
Unexercised | ||||||||||||||||||||||||
Unexercised | in-the-Money | |||||||||||||||||||||||
Options/SARs | Options/SARs | |||||||||||||||||||||||
at Financial | at Financial | |||||||||||||||||||||||
Securities | Aggregate | Year End | Year End | |||||||||||||||||||||
Acquired | Value | (#) | ($) | |||||||||||||||||||||
on Exercise | Realized | Unexercisable | Unexercisable | |||||||||||||||||||||
Name | (#) | ($) | Exercisable | (1) | Exercisable | (1) | ||||||||||||||||||
T.J. Hearn |
| 948,300 | 90,000 | 0 | 2,693,700 | 0 | ||||||||||||||||||
P.A. Smith |
| 0 | 135,000 | 0 | 4,202,550 | 0 | ||||||||||||||||||
R.L. Broiles |
| | | | | | ||||||||||||||||||
R.F. Lipsett |
| 1,103,750 | 37,500 | 0 | 1,122,375 | 0 | ||||||||||||||||||
J.F. Kyle |
| 0 | 0 | 0 | 0 | 0 |
(1) | Unexercisable units are units for which the conditions for exercise have not been met. |
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The following table provides information on the exercise in 2006 and the aggregate
holdings at the end of 2006 of stock options by the named senior executives. The stock option plan
is described in more detail on page 46.
Value of | ||||||||||||||||||||||||
Unexercised | ||||||||||||||||||||||||
Unexercised | in-the-Money | |||||||||||||||||||||||
Options/SARs | Options/SARs | |||||||||||||||||||||||
at Financial | at Financial | |||||||||||||||||||||||
Securities | Aggregate | Year End | Year End | |||||||||||||||||||||
Acquired | Value | (#) (1) | ($) | |||||||||||||||||||||
on Exercise | Realized | Unexercisable | Unexercisable | |||||||||||||||||||||
Name | (#) (1) | ($) | Exercisable | (2) | Exercisable | (2) | ||||||||||||||||||
T.J. Hearn |
12,000 | 296,948 | 165,000 | 0 | 4,525,950 | 0 | ||||||||||||||||||
P.A. Smith |
0 | 0 | 75,000 | 0 | 2,057,250 | 0 | ||||||||||||||||||
R.L. Broiles (3) |
| | | | | | ||||||||||||||||||
R.F. Lipsett |
0 | 0 | 75,000 | 0 | 2,057,250 | 0 | ||||||||||||||||||
J.F. Kyle |
30,000 | 871,083 | 57,000 | 0 | 1,563,510 | 0 |
(1) | The number for the stock options represents three times the number of stock options granted 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 2006, R.L. Broiles held options to acquire 111,994 Exxon Mobil Corporation shares of which all options were exercisable. The value of R.L. Broiles exercisable options was $4,390,984 U.S. at the end of 2006. In 2006, R.L. Broiles exercised 11,078 options and realized an aggregate value of $479,265 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 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 2006,
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
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director elected to receive as deferred share units by the average closing price immediately
prior to the last day of the calendar quarter.
Starting in 2001, 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 selected 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 15, 2007, there have been 4,139,439 common shares issued upon exercise of
stock options and 5,426,811 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 1.0
percent of the companys currently outstanding common shares. The companys directors, officers and
vice-presidents as a group hold 9.7 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 165,000 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
1,935,658 units were granted on December 4, 2006.
There are 6,230,974 common shares issuable upon future exercise of restricted stock units,
which represent about 0.66 percent of the companys currently outstanding common shares. The
companys directors, officers and vice-presidents have available, as a group, 19 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
423,200 common shares, which is about 0.04 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
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Table of Contents
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 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
Pension Plan Table
Remuneration for | ||||||||||||||||||||||||
determining | ||||||||||||||||||||||||
payments | Estimated undiscounted payments on retirement | |||||||||||||||||||||||
on retirement | at the age of 65 after years of service indicated below ($) | |||||||||||||||||||||||
($) | 20 Years | 25 Years | 30 Years | 35 Years | 40 Years | 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 |
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 42 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 44 is also included in the employees final three year average earnings for the
year of grant of such units. As of February 15, 2007, the number of completed years of service with
Imperial Oil Limited used to determine payments on retirement was 40 for T.J. Hearn, 26 for P.A.
Smith, 37 for R.F. Lipsett and 30 for J.F. Kyle.
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 27 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 42, 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.
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Executive Pension Value Disclosure (1) (2)
Accrued | Annual Pension | |||||||||||||||||||||||
Current 2006 | Obligations at | Benefit Payable at | Age | Normal | ||||||||||||||||||||
Service Cost ($) | Dec. 31, 2006 | age 65 | (at Dec. 31, | Credited | Retirement | |||||||||||||||||||
Name | (3) | (4) | (5) | 2006) | Service | Age | ||||||||||||||||||
T.J. Hearn |
593,000 | 25,575,000 | 2,185,400 | 62 | 40 | 65 | ||||||||||||||||||
P.A. Smith |
144,100 | 3,930,000 | 481,600 | 53 | 26 | 65 | ||||||||||||||||||
R.L. Broiles |
| | | 49 | 27 | 65 | ||||||||||||||||||
R.F. Lipsett |
144,200 | 5,618,000 | 509,100 | 60 | 37 | 65 | ||||||||||||||||||
J.F. Kyle |
91,900 | 3,706,000 | 298,900 | 64 | 30 | 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, R.F. Lipsett 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 2006 service cost was $139,963 U.S., the accrued obligations at December 31, 2006 with respect to R.L. Broiles was $1,232,150 U.S. and his annual pension benefit payable at age 65 will be $412,000 U.S. | |
(3) | Service cost is the value of the projected pension for the calendar year 2006. Amounts shown are consistent with disclosure in Note 6 of the 2006 Consolidated Financial Statements. | |
(4) | Accrued obligation is the value of the projected pension earned for service to December 31, 2006. 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 2006 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 15, 2007, 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 661,175,328 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 15, 2007, R.F. Lipsett was the owner of 4,163 common shares of the company, held
options to acquire 75,000 common shares of the company and held 154,650 restricted share units of
the company. As of February 15, 2006, J.F. Kyle was the owner of 12,215 common shares of the
company, held options to acquire 57,000 common shares of the company and held 127,300 restricted
share units of the company.
The directors and the senior executives of the company consist of 10 persons, who, as a group,
own beneficially 155,346 common shares of the company, being approximately 0.02 percent of the
total number of outstanding shares of the company, and 72,937 shares of Exxon Mobil Corporation.
This information not being within the knowledge of the company has been provided by the directors
and the senior executives individually. As a group, the directors and senior executives of the
company held options to acquire 372,000 common shares of the company and held restricted stock
units to acquire 1,196,225 common shares of the company, as of February 15, 2007.
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Table of Contents
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 2006 pursuant to compensation plans of the company.
Number of securities | ||||||||||||
Number of securities to | remaining available for future | |||||||||||
be issued upon exercise | Weighted-average | issuance under equity | ||||||||||
of outstanding options, | exercise price of | compensation plans (excluding | ||||||||||
warrants and | outstanding options, | securities reflected in | ||||||||||
rights | warrants and rights | column (a)) | ||||||||||
(3) | ($) | (3) | ||||||||||
Plan category | (a) | (b) | (c) | |||||||||
Equity compensation
plans approved by
security holders (1) |
5,527,665 | 15.50 | 0 | |||||||||
Equity compensation
plans not approved
by security holders (2) |
6,236,404 | | 4,263,596 | |||||||||
Total |
11,764,069 | 15.50 | 4,263,596 |
(1) | This is a stock option plan, which is described on page 46. | |
(2) | This is a restricted stock unit plan, which is described on page 46 and 47. | |
(3) | The number of securities reserved for the stock option plan represents three times the number of stock options granted before the three-for-one share split in May 2006 and still outstanding. The number of securities reserved for the restricted stock unit plan represent the securities reserved for restricted stock units issued in 2006 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, 2005, the company implemented another 12-month normal course
share-purchase program under which it purchased 50,251,542 of its outstanding shares between June
23, 2005 and June 22, 2006. On June 23, 2006, another 12-month normal course program was
implemented under which the company may purchase up to 48,772,466 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 2006, such purchases
cost $1,817 million, of which $1,247 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 2006 was $34 million. The average effective interest rate for the loans
was 4.2 percent for 2006.
The amounts of purchases and sales by the company and its subsidiaries for other transactions
in 2006 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $4,292 million
and $1,948 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, 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. During 2005, the
company and an affiliate of Exxon Mobil Corporation in Canada agreed to operate their respective
Western Canada production organizations as one single organization. Under the consolidation, the
company will operate all Western Canada properties. There are no asset ownership changes.
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Table of Contents
Item 14. Principal Accountant Fees and Services.
Auditor Fees
The aggregate fees of the companys auditors for professional services rendered for the audit
of the companys financial statements and other services for the fiscal years ended December 31,
2006 and December 31, 2005 were as follows:
Dollars (thousands) | 2006 | 2005 | ||||||
Audit Fees |
1,117 | 1,117 | ||||||
Audit-Related Fees |
62 | 64 | ||||||
Tax Fees |
815 | 770 | ||||||
All Other Fees |
Nil | Nil | ||||||
Total Fees |
1,994 | 1,951 | ||||||
Audit fees include the audit of the companys annual financial statements, audit of
managements report on internal control over financial reporting, and a review of the first three
quarterly financial statements in 2006.
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 auditors for any other services.
The audit committee recommends the external auditors to be appointed by the shareholders,
fixes their remuneration and oversees their work. The audit committee also approves the proposed
current year audit program of the external auditors, assesses the results of the program after the
end of the program period and approves in advance any non-audit services to be performed by the
external auditors after considering the effect of such services on their independence.
All of the services rendered by the auditors to the company were approved by the audit
committee.
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Table of Contents
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-K 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)). |
51
Table of Contents
(13 | ) | Amendment to Alberta Crown Agreement, dated November 25, 1987 (Incorporated herein by reference to Exhibit (10)(ii)(13) of the companys Annual Report on Form 10-K for the year ended December 31, 1987 (File No. 0-12014)). | ||||||
(14 | ) | Amendment to Syncrude Ownership and Management Agreement, dated March 10, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(14) of the companys Annual Report on Form 10-K for the year ended December 31, 1989 (File No. 0-12014)). | ||||||
(15 | ) | Amendment to Alberta Crown Agreement, dated August 1, 1991 (Incorporated herein by reference to Exhibit (10)(ii)(15) of the companys Annual Report on Form 10-K for the year ended December 31, 1991 (File No. 0-12014)). | ||||||
(16 | ) | Norman Wells Settlement Agreement, dated July 31, 1996. (Incorporated herein by reference to Exhibit (10)(ii)(16) of the companys Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0-12014)). | ||||||
(17 | ) | Amendment to Alberta Crown Agreement, dated January 1, 1997. (Incorporated herein by reference to Exhibit (10)(ii)(17) of the companys Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0-12014)). | ||||||
(18 | ) | Norman Wells Pipeline Amending Agreement, dated December 12, 1997. (Incorporated herein by reference to Exhibit (10)(ii)(18) of the companys Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)). | ||||||
(19 | ) | Norman Wells Pipeline 1999 Amending Agreement, dated May 1, 1999. (Incorporated herein by reference to Exhibit (10)(ii)(19) of the companys Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 0-12014)). | ||||||
(20 | ) | Alberta Cold Lake Transition Agreement, effective January 1, 2000, relating to the royalties payable in respect of the Cold Lake production project and terminating the Alberta Cold Lake Crown Agreement. (Incorporated herein by reference to Exhibit (10)(ii)(20) of the companys Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 0-12014)). | ||||||
(21 | ) | Amendment to Alberta Crown Agreement effective January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(21) of the companys Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)). | ||||||
(22 | ) | Amendment to Syncrude Ownership and Management Agreement effective January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(22) of the companys Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)). | ||||||
(23 | ) | Amendment to Syncrude Ownership and Management Agreement effective September 16, 1994 (Incorporated herein by reference to Exhibit (10)(ii)(23) of the companys Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)). | ||||||
(24 | ) | Amendment to Alberta Crown Agreement dated November 29, 1995 (Incorporated herein by reference to Exhibit (10)(ii)(24) of the companys Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)). | ||||||
(iii) | (A) | (1) | Form of Letter relating to Supplemental Retirement Income (Incorporated herein by reference to Exhibit (10)(c)(3) of the companys Annual Report on Form 10-K for the year ended December 31, 1980 (File No. 2-9259)). | |||||
(2) | Incentive Share Unit Plan and Incentive Share Units granted in 2001 are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the companys Annual Report on Form 10-K for the year ended December 31, 2001. Units granted in 2000 are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the companys Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 0-12014); units granted in 1999 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the companys Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 0-12014); units granted in 1998 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the companys Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014); units granted in 1997 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the companys Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 0-12014). |
52
Table of Contents
(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.
53
Table of Contents
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 27, 2007 by the
undersigned, thereunto duly authorized.
Imperial Oil Limited | ||||||
By | /s/ T.J. Hearn | |||||
(Timothy J. Hearn, Chairman of the Board, | ||||||
President and Chief Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been
signed below on February 27, 2007 by the following persons on behalf of the registrant and in the
capacities indicated.
Signature | Title | |
/s/ T.J. Hearn
|
Chairman of the Board, President, Chief Executive Officer and Director (Principal Executive Officer) | |
/s/ Paul A. Smith
|
Controller and Senior Vice-President, Finance and Administration and Director (Principal Accounting Officer and Principal Financial Officer) | |
/s/ R.L. Broiles
|
Director | |
/s/ J.M. Mintz
|
Director | |
/s/ Roger Phillips
|
Director | |
/s/ J.F. Shepard
|
Director | |
/s/ Sheelagh D. Whittaker
|
Director | |
/s/ V.L. Young
|
Director | |
(Victor L. Young) |
54
Table of Contents
INDEX TO FINANCIAL STATEMENTS
Pages in this | ||
Report | ||
Managements report on internal control over financial reporting |
F-2 | |
Report of independent registered public accounting firm |
F-2 | |
Financial statements: |
||
F-3 | ||
F-4 | ||
F-5 | ||
F-6 | ||
F-7 F-20 |
F-1
Table of Contents
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, 2006.
Managements assessment of the effectiveness of internal control over financial reporting as
of December 31, 2006, was audited by PricewaterhouseCoopers LLP, an independent registered public
accounting firm, as stated in their report which is included herein.
/s/ T.J. Hearn
|
/s/ Paul A. Smith | |||
T.J. Hearn
|
P.A. Smith | |||
Chairman, president and chief executive officer
|
Controller and senior vice-president, finance and administration | |||
(Principal accounting officer and principal financial officer) |
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the
Shareholders of Imperial Oil Limited
We have completed integrated audits of Imperial Oil Limiteds consolidated financial
statements and of its internal control over financial reporting as of December 31, 2006, in
accordance with the standards of the Public Company Accounting Oversight Board (United States). 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, 2006, and 2005, and the results of their operations and their
cash flows for each of the three years in the period ended December 31, 2006 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, managements assessment, included in the
accompanying Managements Report on Internal
Control Over Financial Reporting, that the company maintained effective
internal control over financial reporting as of December 31, 2006, based on criteria established in
Internal Control Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria.
Furthermore, in our opinion, the company maintained, in all material respects, effective internal
control over financial reporting as of December 31, 2006, based on criteria established in Internal
Control Integrated Framework issued by the 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. Our responsibility is to express
opinions on managements assessment and 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, evaluating managements assessment, testing and
evaluating the design and operating effectiveness of internal control, and performing such other
procedures as we consider necessary in the circumstances. We believe that our audit provides a
reasonable basis for our opinions.
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.
/s/ PricewaterhouseCoopers LLP
|
||
Calgary, Alberta, Canada |
||
February 27, 2007 |
F-2
Table of Contents
Consolidated statement of income
millions of Canadian dollars | ||||||||||||
For the years ended December 31 | 2006 | 2005 | 2004 | |||||||||
Revenues and other income |
||||||||||||
Operating revenues (a)(b)(c) |
24,505 | 27,797 | 22,408 | |||||||||
Investment and other income (note 10)(d) |
283 | 417 | 52 | |||||||||
Total revenues and other income |
24,788 | 28,214 | 22,460 | |||||||||
Expenses |
||||||||||||
Exploration |
32 | 43 | 59 | |||||||||
Purchases of crude oil and products (b)(e) |
13,793 | 17,168 | 13,094 | |||||||||
Production and manufacturing (f) |
3,446 | 3,327 | 2,820 | |||||||||
Selling and general |
1,284 | 1,577 | 1,281 | |||||||||
Federal excise tax (a) |
1,274 | 1,278 | 1,264 | |||||||||
Depreciation and depletion |
831 | 895 | 908 | |||||||||
Financing costs (note 14)(g) |
28 | 8 | 7 | |||||||||
Total expenses |
20,688 | 24,296 | 19,433 | |||||||||
Income before income taxes |
4,100 | 3,918 | 3,027 | |||||||||
Income taxes (note 5) |
1,056 | 1,318 | 975 | |||||||||
Net income |
3,044 | 2,600 | 2,052 | |||||||||
Per-share information (Canadian dollars) |
||||||||||||
Net income per common share basic (note 12) |
3.12 | 2.54 | 1.92 | |||||||||
Net income per common share diluted (note 12) |
3.11 | 2.53 | 1.91 | |||||||||
Dividends |
0.32 | 0.31 | 0.29 | |||||||||
(a) | Operating revenues include federal excise tax of $1,274 million (2005 $1,278 million, 2004 $1,264 million). | |
(b) | Amounts included in operating revenues for purchase/sale contracts with the same counterparty (associated costs are included in purchases of crude oil and products resulting in no impact to net income) are nil (2005 $4,894 million, 2004 $3,584 million), (note 1). | |
(c) | Operating revenues include amounts from related parties of $1,927 million (2005 $1,325 million, 2004 $1,142 million), (note 15). | |
(d) | Investment and other income include amounts from related parties of $31 million (2005 $24 million, 2004 $23 million), (note 15). | |
(e) | Purchases of crude oil and products include amounts from related parties of $4,119 million (2005 $3,650 million, 2004 $3,169 million), (note 15). | |
(f) | Production and manufacturing expenses include amounts to related parties of $219 million (2005 $175 million, 2004 $43 million), (note 15). | |
(g) | Financing costs include amounts to related parties of $33 million (2005 $22 million, 2004 - $20 million), (note 15). |
The information on pages F-7 through F-20 is an integral part of these consolidated financial
statements.
F-3
Table of Contents
Consolidated statement of cash flows
millions of Canadian dollars | ||||||||||||
Inflow/(outflow) | ||||||||||||
For the years ended December 31 | 2006 | 2005 | 2004 | |||||||||
Operating activities |
||||||||||||
Net income |
3,044 | 2,600 | 2,052 | |||||||||
Adjustments for non-cash items: |
||||||||||||
Depreciation and depletion |
831 | 895 | 908 | |||||||||
(Gain)/loss
on asset sales, after tax |
(96 | ) | (233 | ) | (32 | ) | ||||||
Deferred income taxes and other |
254 | (116 | ) | (90 | ) | |||||||
Changes in operating assets and liabilities: |
||||||||||||
Accounts receivable |
203 | (414 | ) | (311 | ) | |||||||
Inventories and prepaids |
(97 | ) | (67 | ) | (32 | ) | ||||||
Income taxes payable |
(225 | ) | 304 | 462 | ||||||||
Accounts payable |
(86 | ) | 644 | 308 | ||||||||
All other items net (a) |
(241 | ) | (162 | ) | 47 | |||||||
Cash from operating activities |
3,587 | 3,451 | 3,312 | |||||||||
Investing activities |
||||||||||||
Additions to property, plant and equipment and intangibles |
(1,177 | ) | (1,432 | ) | (1,376 | ) | ||||||
Proceeds from asset sales |
212 | 440 | 102 | |||||||||
Loans to equity company |
| | (32 | ) | ||||||||
Cash from (used in) investing activities |
(965 | ) | (992 | ) | (1,306 | ) | ||||||
Financing activities |
||||||||||||
Short-term debt net |
72 | 18 | 9 | |||||||||
Repayment of long-term debt |
(74 | ) | (21 | ) | (8 | ) | ||||||
Issuance of common shares under stock option plan |
10 | 38 | 13 | |||||||||
Common shares purchased (note 12) |
(1,818 | ) | (1,795 | ) | (872 | ) | ||||||
Dividends paid |
(315 | ) | (317 | ) | (317 | ) | ||||||
Cash from (used in) financing activities |
(2,125 | ) | (2,077 | ) | (1,175 | ) | ||||||
Increase (decrease) in cash |
497 | 382 | 831 | |||||||||
Cash at beginning of year |
1,661 | 1,279 | 448 | |||||||||
Cash at end of year (b) |
2,158 | 1,661 | 1,279 | |||||||||
(a) | Includes contribution to registered pension plans of $395 million (2005 $350 million, 2004 $114 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
Table of Contents
Consolidated balance sheet
millions of Canadian dollars | ||||||||
At December 31 | 2006 | 2005 | ||||||
Assets |
||||||||
Current assets
|
||||||||
Cash |
2,158 | 1,661 | ||||||
Accounts receivable, less estimated doubtful amounts |
1,871 | 2,073 | ||||||
Inventories of crude oil and products (note 13) |
556 | 481 | ||||||
Materials, supplies and prepaid expenses |
151 | 130 | ||||||
Deferred income tax assets (note 5) |
573 | 654 | ||||||
Total current assets |
5,309 | 4,999 | ||||||
Investments and other long-term assets |
104 | 94 | ||||||
Property, plant and equipment,
less accumulated depreciation and depletion (note 3) |
10,457 | 10,132 | ||||||
Goodwill (note 3) |
204 | 204 | ||||||
Other intangible assets, net |
67 | 153 | ||||||
Total assets (note 3) |
16,141 | 15,582 | ||||||
Liabilities |
||||||||
Current liabilities
|
||||||||
Short-term debt |
171 | 99 | ||||||
Accounts payable and accrued liabilities (a) |
3,080 | 3,170 | ||||||
Income taxes payable |
1,190 | 1,399 | ||||||
Current portion of long-term debt (b) |
907 | 477 | ||||||
Total current liabilities |
5,348 | 5,145 | ||||||
Long-term debt (note 4)(c) |
359 | 863 | ||||||
Other long-term obligations (note 7) |
1,683 | 1,728 | ||||||
Deferred income tax liabilities (note 5) |
1,345 | 1,213 | ||||||
Commitments and contingent liabilities (note 11) |
||||||||
Total liabilities |
8,735 | 8,949 | ||||||
Shareholders equity |
||||||||
Common shares at stated value (note 12)(d) |
1,677 | 1,747 | ||||||
Earnings reinvested |
6,462 | 5,466 | ||||||
Accumulated other nonowner changes in equity |
(733 | ) | (580 | ) | ||||
Total shareholders equity |
7,406 | 6,633 | ||||||
Total liabilities and shareholders equity |
16,141 | 15,582 | ||||||
(a) | Accounts payable and accrued liabilities include amounts to related parties of $151 million (2005 $224 million), (note 15). | |
(b) | Current portion of long-term debt includes amounts to related parties of $500 million (2005 - Nil), (note 4). | |
(c) | Long-term debt includes amounts to related parties of $318 million (2005 $818 million), (note 4). | |
(d) | Number of common shares outstanding was 953 million (2005 998 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, president and
|
Controller and senior vice-president, | |
chief executive officer
|
finance and administration |
F-5
Table of Contents
Consolidated statement of shareholders equity
millions of Canadian dollars | ||||||||||||
At December 31 | 2006 | 2005 | 2004 | |||||||||
Common shares at stated value (note 12) |
||||||||||||
At beginning of year |
1,747 | 1,801 | 1,859 | |||||||||
Issued under the stock option plan |
10 | 38 | 13 | |||||||||
Share purchases at stated value |
(80 | ) | (92 | ) | (71 | ) | ||||||
At end of year |
1,677 | 1,747 | 1,801 | |||||||||
Earnings reinvested |
||||||||||||
At beginning of year |
5,466 | 4,889 | 3,952 | |||||||||
Net income for the year |
3,044 | 2,600 | 2,052 | |||||||||
Share purchases in excess of stated value |
(1,737 | ) | (1,703 | ) | (801 | ) | ||||||
Dividends |
(311 | ) | (320 | ) | (314 | ) | ||||||
At end of year |
6,462 | 5,466 | 4,889 | |||||||||
Accumulated other nonowner changes in equity |
||||||||||||
At beginning of year |
(580 | ) | (368 | ) | (266 | ) | ||||||
Minimum pension liability adjustment (note 6) |
580 | (212 | ) | (102 | ) | |||||||
Post-retirement benefit liability adjustment (note 6) |
(733 | ) | | | ||||||||
At end of year |
(733 | ) | (580 | ) | (368 | ) | ||||||
Shareholders equity at end of year |
7,406 | 6,633 | 6,322 | |||||||||
Nonowner changes in equity for the year |
||||||||||||
Net income for the year |
3,044 | 2,600 | 2,052 | |||||||||
Other nonowner changes in equity
|
||||||||||||
Minimum pension liability adjustment |
580 | (212 | ) | (102 | ) | |||||||
Post-retirement benefit liability adjustment |
(733 | ) | | | ||||||||
Total nonowner changes in equity for the year |
2,891 | 2,388 | 1,950 | |||||||||
The information on pages F-7 through F-20 is an integral part of these consolidated financial
statements.
F-6
Table of Contents
Notes to consolidated financial statements
1. | Summary of significant accounting policies |
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 (GAAP) 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 2006 presentation. All amounts are in Canadian dollars
unless otherwise indicated.
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.
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-
F-7
Table of Contents
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, which are
recovered through surface mining methods. Currently, the companys oil sands production volumes
and reserves include 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
Table of Contents
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 revenue 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 are affected by this
change, with the largest impact in the petroleum products segment.
Share-based compensation
Effective January 1, 2006, the company adopted the Financial Accounting Standards Boards (FASB)
revised Statement of Financial Accounting Standards No. 123 (SFAS 123R), Share-based Payment.
SFAS 123R requires compensation costs related to share-based payments to be recognized in the
income statement over the requisite service period. The amount of the compensation costs is to
be measured based on the grant-date fair value of the instrument issued. In addition, liability
awards are to be remeasured each reporting period through settlement. SFAS 123R is effective for
awards granted or modified after the date of adoption and for awards granted prior to that date
that have not vested. In 2003, the company adopted a policy of expensing all share-based
payments that is consistent with the provisions of SFAS 123R, and all prior years outstanding
stock option awards have vested. SFAS 123R does not materially change the companys existing
accounting practices or the amount of share-based compensation recognized in earnings.
Compensation expense related to share-based programs is recorded as selling and general
expenses in the consolidated statement of income.
The company has recognized restricted stock awards made prior to 2006 in compensation expense
using the nominal vesting period approach. Under this method, the fair value of the awards
has been amortized into compensation expense over the full vesting period of each award. The
fair value is remeasured each reporting period through settlement. For awards granted after the
companys adoption of SFAS 123R, compensation expense is recognized using the non-substantive
vesting period approach. Under this method, the value of the grants is amortized to
compensation expense over the shorter of (a) the vesting period of each award or (b) the
remaining time period until the employee becomes retiree eligible. Under both methods, the full
unamortized value of awards for employees who retire before the end of the applicable
amortization period is expensed. The impact of switching to the non-substantive vesting period
approach is not material for the company.
As permitted by Statement of Financial Accounting Standard (SFAS) No. 123, the company continues
to apply the intrinsic-value-based method of accounting for the incentive stock options granted
in April 2002. Under this method, compensation expense is not recognized on the issuance of
stock options, as the exercise price is equal to the market value at the date of grant. If the
provisions of SFAS 123 had been adopted for all prior years, net income for 2004 would have been
reduced by $2 million. The impact on net income per share on both a basic and diluted basis for
2004 was negligible. All incentive stock options have vested as of January 1, 2005.
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 defined benefit post-retirement plans |
In September 2006, the FASB issued Statement of Financial Accounting Standards No. 158 (SFAS
158), Employers Accounting for Defined Benefit Pension and Other Post-retirement Plans, an
amendment to FASB Statements No. 87, 88, 106 and 132(R). SFAS 158 requires an employer to
recognize the overfunded or underfunded status of a defined benefit post-retirement plan as an
asset or liability in its balance sheet and to recognize changes in that funded status in the
year in which the changes occur through other nonowner changes in equity. The standard also
requires disclosure in the notes to the financial statements of additional information,
including certain effects on net periodic benefit costs of the next fiscal year that arise from
delayed recognition of gains or losses and prior service costs. SFAS 158 was adopted by the
company in the financial statements for the year ending December 31, 2006. See note 6, Employee
retirement benefits, for further details.
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 benefit 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 this summary of significant
accounting policies. Natural resources, petroleum products and chemicals expenses include
amounts allocated from the corporate and other segment. The allocation is based on a
combination of fee for service, proportional segment expenses and a three-year average of
capital expenditures. Transfers of assets between segments are recorded at book amounts.
Intersegment sales are made essentially at prevailing market prices. Assets and liabilities that
are not identifiable by segment are allocated.
F-9
Table of Contents
Natural resources(a) | Petroleum products | Chemicals | ||||||||||||||||||||||||||||||||||
millions of dollars | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 | |||||||||||||||||||||||||||
Revenues and other income |
||||||||||||||||||||||||||||||||||||
External sales (b) |
4,619 | 4,702 | 3,689 | 18,527 | 21,793 | 17,503 | 1,359 | 1,302 | 1,216 | |||||||||||||||||||||||||||
Intersegment sales |
3,837 | 3,487 | 2,891 | 2,256 | 2,224 | 1,666 | 345 | 363 | 293 | |||||||||||||||||||||||||||
Investment and other income |
111 | 331 | 45 | 105 | 60 | 42 | | | | |||||||||||||||||||||||||||
8,567 | 8,520 | 6,625 | 20,888 | 24,077 | 19,211 | 1,704 | 1,665 | 1,509 | ||||||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Exploration |
32 | 43 | 59 | | | | | | | |||||||||||||||||||||||||||
Purchases of crude oil and products |
2,841 | 2,837 | 2,110 | 16,178 | 19,212 | 14,769 | 1,209 | 1,191 | 1,064 | |||||||||||||||||||||||||||
Production and manufacturing |
1,994 | 1,931 | 1,581 | 1,266 | 1,203 | 1,064 | 189 | 195 | 176 | |||||||||||||||||||||||||||
Selling and general (c) |
13 | 36 | 9 | 1,018 | 1,096 | 1,043 | 76 | 81 | 88 | |||||||||||||||||||||||||||
Federal excise tax |
| | | 1,274 | 1,278 | 1,264 | | | | |||||||||||||||||||||||||||
Depreciation and depletion |
584 | 651 | 633 | 233 | 230 | 257 | 11 | 12 | 13 | |||||||||||||||||||||||||||
Financing costs (note 14) |
2 | | 1 | 6 | 2 | 2 | | | | |||||||||||||||||||||||||||
Total expenses |
5,466 | 5,498 | 4,393 | 19,975 | 23,021 | 18,399 | 1,485 | 1,479 | 1,341 | |||||||||||||||||||||||||||
Income before income taxes |
3,101 | 3,022 | 2,232 | 913 | 1,056 | 812 | 219 | 186 | 168 | |||||||||||||||||||||||||||
Income taxes (note 5) |
||||||||||||||||||||||||||||||||||||
Current |
602 | 955 | 771 | 174 | 409 | 314 | 60 | 69 | 61 | |||||||||||||||||||||||||||
Deferred |
123 | 59 | (56 | ) | 115 | (47 | ) | (58 | ) | 16 | (4 | ) | (2 | ) | ||||||||||||||||||||||
Total income tax expense |
725 | 1,014 | 715 | 289 | 362 | 256 | 76 | 65 | 59 | |||||||||||||||||||||||||||
Net income |
2,376 | 2,008 | 1,517 | 624 | 694 | 556 | 143 | 121 | 109 | |||||||||||||||||||||||||||
Cash flow from (used in) operating activities |
3,024 | 2,440 | 2,331 | 507 | 799 | 908 | 161 | 94 | 126 | |||||||||||||||||||||||||||
Capital and exploration expenditures |
787 | 937 | 1,113 | 361 | 478 | 283 | 13 | 19 | 15 | |||||||||||||||||||||||||||
Property, plant and equipment |
||||||||||||||||||||||||||||||||||||
Cost |
14,926 | 14,229 | 13,538 | 6,581 | 6,350 | 6,078 | 702 | 701 | 682 | |||||||||||||||||||||||||||
Accumulated depreciation and depletion |
(8,255 | ) | (7,780 | ) | (7,337 | ) | (3,178 | ) | (3,037 | ) | (2,959 | ) | (484 | ) | (474 | ) | (459 | ) | ||||||||||||||||||
Net property, plant and equipment (d)(e) |
6,671 | 6,449 | 6,201 | 3,403 | 3,313 | 3,119 | 218 | 227 | 223 | |||||||||||||||||||||||||||
Total assets |
7,513 | 7,289 | 6,822 | 6,450 | 6,257 | 5,509 | 504 | 500 | 490 | |||||||||||||||||||||||||||
Corporate and other | Eliminations | Consolidated | ||||||||||||||||||||||||||||||||||
millions of dollars | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 | |||||||||||||||||||||||||||
Revenues and other income |
||||||||||||||||||||||||||||||||||||
External sales (b) |
| | | 24,505 | 27,797 | 22,408 | ||||||||||||||||||||||||||||||
Intersegment sales |
| | | (6,438 | ) | (6,074 | ) | (4,850 | ) | | | | ||||||||||||||||||||||||
Investment and other income |
67 | 26 | (35 | ) | 283 | 417 | 52 | |||||||||||||||||||||||||||||
67 | 26 | (35 | ) | (6,438 | ) | (6,074 | ) | (4,850 | ) | 24,788 | 28,214 | 22,460 | ||||||||||||||||||||||||
Expenses |
||||||||||||||||||||||||||||||||||||
Exploration |
| | | 32 | 43 | 59 | ||||||||||||||||||||||||||||||
Purchases of crude oil and products |
| | | (6,435 | ) | (6,072 | ) | (4,849 | ) | 13,793 | 17,168 | 13,094 | ||||||||||||||||||||||||
Production and manufacturing |
| | | (3 | ) | (2 | ) | (1 | ) | 3,446 | 3,327 | 2,820 | ||||||||||||||||||||||||
Selling and general (c) |
177 | 364 | 141 | 1,284 | 1,577 | 1,281 | ||||||||||||||||||||||||||||||
Federal excise tax |
| | | 1,274 | 1,278 | 1,264 | ||||||||||||||||||||||||||||||
Depreciation and depletion |
3 | 2 | 5 | 831 | 895 | 908 | ||||||||||||||||||||||||||||||
Financing costs (note 14) |
20 | 6 | 4 | 28 | 8 | 7 | ||||||||||||||||||||||||||||||
Total expenses |
200 | 372 | 150 | (6,438 | ) | (6,074 | ) | (4,850 | ) | 20,688 | 24,296 | 19,433 | ||||||||||||||||||||||||
Income before income taxes |
(133 | ) | (346 | ) | (185 | ) | 4,100 | 3,918 | 3,027 | |||||||||||||||||||||||||||
Income taxes (note 5) |
||||||||||||||||||||||||||||||||||||
Current |
(60 | ) | (72 | ) | (43 | ) | 776 | 1,361 | 1,103 | |||||||||||||||||||||||||||
Deferred |
26 | (51 | ) | (12 | ) | 280 | (43 | ) | (128 | ) | ||||||||||||||||||||||||||
Total income tax expense |
(34 | ) | (123 | ) | (55 | ) | 1,056 | 1,318 | 975 | |||||||||||||||||||||||||||
Net income |
(99 | ) | (223 | ) | (130 | ) | | | | 3,044 | 2,600 | 2,052 | ||||||||||||||||||||||||
Cash flow from (used in) operating activities |
(105 | ) | 118 | (53 | ) | 3,587 | 3,451 | 3,312 | ||||||||||||||||||||||||||||
Capital and exploration expenditures |
48 | 41 | 34 | 1,209 | 1,475 | 1,445 | ||||||||||||||||||||||||||||||
Property, plant and equipment |
||||||||||||||||||||||||||||||||||||
Cost |
269 | 246 | 205 | 22,478 | 21,526 | 20,503 | ||||||||||||||||||||||||||||||
Accumulated depreciation and depletion |
(104 | ) | (103 | ) | (101 | ) | (12,021 | ) | (11,394 | ) | (10,856 | ) | ||||||||||||||||||||||||
Net property, plant and equipment (d)(e) |
165 | 143 | 104 | 10,457 | 10,132 | 9,647 | ||||||||||||||||||||||||||||||
Total assets |
2,145 | 1,959 | 1,504 | (471 | ) | (423 | ) | (298 | ) | 16,141 | 15,582 | 14,027 | ||||||||||||||||||||||||
F-10
Table of Contents
Notes to consolidated financial statements (continued)
(a) | A significant portion of activities in the natural resources segment is conducted jointly with other companies. The segment includes the companys share of undivided interest in such activities as follows: |
millions of dollars | 2006 | 2005 | 2004 | |||||||||
Total external and intersegment sales |
3,303 | 3,687 | 2,744 | |||||||||
Total expenses |
1,966 | 1,805 | 1,598 | |||||||||
Net income, after income tax |
1,148 | 1,249 | 780 | |||||||||
Total current assets |
516 | 245 | 367 | |||||||||
Long-term assets |
4,833 | 4,742 | 4,140 | |||||||||
Total current liabilities |
810 | 967 | 948 | |||||||||
Other long-term obligations |
344 | 382 | 243 | |||||||||
Cash flow from operating activities |
1,229 | 1,223 | 1,211 | |||||||||
Cash (used in) investing activities |
(403 | ) | (403 | ) | (858 | ) | ||||||
(b) | Includes export sales to the United States, as follows: |
millions of dollars | 2006 | 2005 | 2004 | |||||||||
Natural resources |
1,936 | 1,633 | 1,360 | |||||||||
Petroleum products |
869 | 856 | 1,074 | |||||||||
Chemicals |
793 | 750 | 678 | |||||||||
Total export sales |
3,598 | 3,239 | 3,112 | |||||||||
(c) | Consolidated selling and general expenses include delivery costs from final storage areas to customers of $316 million in 2006 (2005 $310 million, 2004 $307 million). |
(d) | Includes property, plant and equipment under construction of $782 million (2005 - $954 million). |
(e) | All goodwill has been assigned to the petroleum products segment. There have been no goodwill acquisitions, impairment losses or write-offs due to sales in the past three years. |
4. | Long-term debt |
2006 | 2005 | ||||||||||||||
Issued |
Maturity date | Interest rate | Millions of dollars | ||||||||||||
2003 |
$250 million due May 26, 2007 and | ||||||||||||||
$250 million due August 26, 2007 (a) | Variable | | 500 | ||||||||||||
2003 |
January 19, 2008 (a) | Variable | 318 | 318 | |||||||||||
Long-term debt (b) | 318 | 818 | |||||||||||||
Capital leases (c) | 41 | 45 | |||||||||||||
Total long-term debt (d) (e) | 359 | 863 | |||||||||||||
(a) | These are long-term variable-rate loans from an affiliated company of Exxon Mobil Corporation at interest equivalent to Canadian market rates. | |
(b) | The average effective rate for the loans was 4.2 percent for 2006 (2005 2.8 percent). | |
(c) | These obligations primarily relate to the capital lease for marine services, which are provided by the lessor commencing in 2004 for a period of 10 years, extendable for an additional five years. The average imputed rate was 10.7 percent in 2006 (2005 -10.5 percent). | |
(d) | Principal payments on long-term loans of $500 million are due in 2007 and $318 million are due in 2008. Principal payments on capital leases of approximately $3.6 million a year are due in each of the next five years. | |
(e) | These amounts exclude that portion of long-term debt, totalling $907 million (2005 $477 million), which matures within one year and is included in current liabilities. |
5. | Income taxes |
millions of dollars | 2006 | 2005 | 2004 | |||||||||
Current income tax expense |
776 | 1,361 | 1,103 | |||||||||
Deferred income tax expense (a) |
280 | (43 | ) | (128 | ) | |||||||
Total income tax expense (b) |
1,056 | 1,318 | 975 | |||||||||
Statutory corporate tax rate (percent) |
32.8 | 35.6 | 37.0 | |||||||||
Increase/(decrease) resulting from: |
||||||||||||
Non-deductible royalty payments to governments |
| 3.8 | 3.9 | |||||||||
Resource allowance in lieu of royalty deduction |
| (5.2 | ) | (7.0 | ) | |||||||
Manufacturing and processing credit |
| | | |||||||||
Enacted tax rate change |
(2.7 | ) | | (1.8 | ) | |||||||
Other |
(4.3 | ) | (0.6 | ) | 0.1 | |||||||
Effective income tax rate |
25.8 | 33.6 | 32.2 | |||||||||
(a) | The deferred income tax expense for the year is the difference in net deferred income tax liabilities at the beginning and end of the year. The provisions for deferred income taxes in 2006 include net (charges)/credits for the effect of changes in tax laws and rates of $81 million (2005 nil; 2004 $25 million). | |
(b) | Cash outflow from income taxes, plus investment credits earned, was $1,000 million in 2006 (2005 $1,024 million; 2004 $641 million). |
F-11
Table of Contents
Deferred income taxes are based on differences between the accounting and tax values of
assets and liabilities. These differences in value are remeasured at each year-end using the
tax rates and tax laws expected to apply when those differences are realized or settled in the
future. Components of deferred income tax liabilities and assets as at December 31 were:
millions of dollars | 2006 | 2005 | ||||||
Depreciation and amortization |
1,588 | 1,470 | ||||||
Successful drilling and land acquisitions |
263 | 319 | ||||||
Pension and benefits (a) |
(311 | ) | (354 | ) | ||||
Site restoration |
(161 | ) | (171 | ) | ||||
Net tax loss carryforwards (b) |
(42 | ) | (49 | ) | ||||
Capitalized interest |
50 | 26 | ||||||
Other |
(42 | ) | (28 | ) | ||||
Deferred income tax liabilities |
1,345 | 1,213 | ||||||
LIFO inventory valuation |
(448 | ) | (487 | ) | ||||
Other |
(125 | ) | (167 | ) | ||||
Deferred income tax assets |
(573 | ) | (654 | ) | ||||
Valuation allowance |
| | ||||||
Net deferred income tax liabilities |
772 | 559 | ||||||
(a) | Income taxes charged directly to shareholders equity related to post-retirement benefit liability adjustment were $66 million benefit in 2006 and those related to minimum pension liability adjustment were $105 million benefit and $41 million benefit in 2005 and 2004, respectively. | |
(b) | Tax losses can be carried forward indefinitely. |
The operations of the company are complex, and related tax interpretations,
regulations and legislation are continually changing. As a result, there are usually
some tax matters in question. The company believes the provision made for income taxes
is adequate.
6. | Employee retirement benefits |
Retirement benefits, which cover almost all retired employees and their surviving spouses,
include pension-income and certain health-care and life-insurance benefits. They are met
through funded registered retirement plans and through unfunded supplementary benefits that are
paid directly to recipients. Funding of registered retirement plans complies with federal and
provincial pension regulations, and the company makes contributions to the plans based on an
independent actuarial valuation.
Pension-income benefits consist mainly of company-paid defined benefit plans that are based on
years of service and final average earnings. The company shares in the cost of health-care and
life-insurance benefits. The companys benefit obligations are based on the projected benefit
method of valuation that includes employee service to date and present compensation levels, as
well as a projection of salaries and service to retirement.
The expense and obligations for both funded and unfunded benefits are determined in accordance
with United States generally accepted accounting principles and actuarial procedures. The
process for determining retirement-income expense and related obligations includes making
certain long-term assumptions regarding the discount rate, rate of return on plan assets and
rate of compensation increases. The obligation and pension expense can vary significantly with
changes in the assumptions used to estimate the obligation and the expected return on plan
assets.
The benefit obligations and plan assets associated with the companys defined benefit plans
are measured on December 31.
Other post-retirement | ||||||||||||||||
Pension Benefits | benefits | |||||||||||||||
2006 | 2005 | 2006 | 2005 | |||||||||||||
Assumptions used to determine benefit obligations
at December 31 (percent) |
||||||||||||||||
Discount rate |
5.25 | 5.00 | 5.25 | 5.00 | ||||||||||||
Long-term rate of compensation increase |
3.50 | 3.50 | 3.50 | 3.50 | ||||||||||||
millions of dollars |
||||||||||||||||
Change in projected benefit obligation |
||||||||||||||||
Projected benefit obligation at January 1 |
4,784 | 4,260 | 458 | 436 | ||||||||||||
Current service cost |
100 | 86 | 8 | 7 | ||||||||||||
Interest cost |
238 | 239 | 23 | 24 | ||||||||||||
Amendments |
| 20 | (2 | ) | | |||||||||||
Actuarial loss/(gain) |
(122 | ) | 549 | (19 | ) | 26 | ||||||||||
Other |
| (88 | ) | | (13 | ) | ||||||||||
Benefits paid (a) |
(284 | ) | (282 | ) | (27 | ) | (22 | ) | ||||||||
Projected benefit obligation at December 31 |
4,716 | 4,784 | 441 | 458 | ||||||||||||
F-12
Table of Contents
Notes to consolidated financial statements (continued)
Other post-retirement | ||||||||||||||||
Pension Benefits | benefits | |||||||||||||||
millions of dollars | 2006 | 2005 | 2006 | 2005 | ||||||||||||
Accumulated benefit obligation at December 31 |
4,207 | 4,261 | ||||||||||||||
Change in plan assets |
||||||||||||||||
Fair value at January 1 |
3,419 | 2,984 | ||||||||||||||
Actual return on plan assets |
514 | 370 | ||||||||||||||
Company contributions |
395 | 350 | ||||||||||||||
Other |
| (59 | ) | |||||||||||||
Benefits paid (b) |
(239 | ) | (226 | ) | ||||||||||||
Fair value at December 31 |
4,089 | 3,419 | ||||||||||||||
Plan assets in excess of/(less than) projected benefit obligation
at December 31 |
||||||||||||||||
Funded plans |
(294 | ) | (984 | ) | | | ||||||||||
Unfunded plans |
(333 | ) | (381 | ) | (441 | ) | (458 | ) | ||||||||
Total (c) |
(627 | ) | (1,365 | ) | (441 | ) | (458 | ) | ||||||||
(a) | Benefit payments for funded and unfunded plans. | |
(b) | Benefit payments for funded plan only. | |
(c) | Fair value of assets less projected benefit obligation shown above. |
Effective December 31, 2006, the company adopted SFAS 158, which requires an employer to
recognize the overfunded or underfunded status of a defined benefit post-retirement plan as an
asset or liability in its balance sheet and to recognize changes in that funded status in the
year in which the changes occur through other nonowner changes in equity. In 2006, the amounts
recorded in other nonowner changes in equity for net actuarial losses and prior service cost
are required by SFAS 158. For 2005, SFAS 87 required an employer to recognize a liability in
its balance sheet that was at least equal to the unfunded accumulated benefit obligation for
defined benefit pension plans.
Pension Benefits | Other post-retirement benefits | |||||||||||||||||||||||
millions of dollars | 2006 | 2005 | 2004 | 2006 | 2005 | 2004 | ||||||||||||||||||
Amounts recorded in the consolidated balance sheet consist of: |
||||||||||||||||||||||||
Other intangible assets, net |
| 93 | | | ||||||||||||||||||||
Current liabilities |
(28 | ) | (24 | ) | (23 | ) | (23 | ) | ||||||||||||||||
Other long-term obligations |
(599 | ) | (818 | ) | (418 | ) | (334 | ) | ||||||||||||||||
Total |
(627 | ) | (749 | ) | (441 | ) | (357 | ) | ||||||||||||||||
Cumulative amounts recorded in other nonowner
changes in equity consist of: |
||||||||||||||||||||||||
Net actuarial loss/(gain) |
947 | 875 | 73 | | ||||||||||||||||||||
Prior service cost |
74 | | | | ||||||||||||||||||||
Total |
1,021 | 875 | 73 | | ||||||||||||||||||||
Assumptions used to determine net periodic benefit
cost for years ended December 31 (percent) |
||||||||||||||||||||||||
Discount rate |
5.00 | 5.75 | 6.25 | 5.00 | 5.75 | 6.25 | ||||||||||||||||||
Long-term rate of compensation increase |
3.50 | 3.50 | 3.50 | 3.50 | 3.50 | 3.50 | ||||||||||||||||||
Long-term rate of return on funded assets |
8.25 | 8.25 | 8.25 | | | | ||||||||||||||||||
millions of dollars |
||||||||||||||||||||||||
Components of net periodic benefit cost |
||||||||||||||||||||||||
Current service cost |
100 | 86 | 76 | 8 | 7 | 6 | ||||||||||||||||||
Interest cost |
238 | 239 | 237 | 23 | 24 | 24 | ||||||||||||||||||
Expected return on plan assets |
(299 | ) | (257 | ) | (223 | ) | | | | |||||||||||||||
Amortization of prior service cost |
20 | 25 | 27 | | | | ||||||||||||||||||
Recognized actuarial loss/(gain) |
114 | 83 | 68 | 8 | 7 | 4 | ||||||||||||||||||
Net periodic benefit cost |
173 | 176 | 185 | 39 | 38 | 34 | ||||||||||||||||||
Changes in amounts recorded in other
nonowner changes in equity |
||||||||||||||||||||||||
Net actuarial loss/(gain) |
72 | 317 | 143 | 73 | | | ||||||||||||||||||
Prior service cost |
74 | | | | | | ||||||||||||||||||
Total recorded in other nonowner changes in equity |
146 | 317 | 143 | 73 | | | ||||||||||||||||||
Total recorded in net periodic benefit cost and other
nonowner changes in equity, before tax |
319 | 493 | 328 | 112 | 38 | 34 | ||||||||||||||||||
Costs for defined contribution plans, primarily the employee savings plan, were $30 million in
2006 (2005 $30 million; 2004 $32 million).
F-13
Table of Contents
A summary of the change in other nonowner changes in equity is shown in the table below:
Total pension and other | ||||||||||||
post-retirement benefits | ||||||||||||
millions of dollars | 2006 | 2005 | 2004 | |||||||||
(Charge)/credit to accumulated other nonowner
changes in equity, before tax |
(219 | ) | (317 | ) | (143 | ) | ||||||
Deferred income tax (charge)/credit (note 5) |
66 | 105 | 41 | |||||||||
(Charge)/credit to accumulated other nonowner
changes in equity, after tax |
(153 | ) | (212 | ) | (102 | ) | ||||||
The impact of adopting SFAS 158 is shown in the table below:
Pre - SFAS 158 with | ||||||||||||
minimum pension | ||||||||||||
liability | SFAS 158 adoption | |||||||||||
millions of dollars | adjustment | adjustments | Post - SFAS 158 | |||||||||
Other intangible assets, net |
73 | (6 | ) | 67 | ||||||||
Total assets |
16,147 | (6 | ) | 16,141 | ||||||||
Other long-term obligations |
990 | 693 | 1,683 | |||||||||
Deferred income tax liabilities |
1,557 | (212 | ) | 1,345 | ||||||||
Accumulated other nonowner changes in equity |
(246 | ) | (487 | ) | (733 | ) | ||||||
Total liabilities and shareholders equity |
16,147 | (6 | ) | 16,141 | ||||||||
Preceding data on this note conform with current accounting standards that specify use of a
discount rate at which post-retirement liabilities could be effectively settled. The discount
rate for calculating year-end post-retirement liabilities is based on the yield for high
quality, long-term Canadian corporate bonds at year-end with an average maturity (or duration)
approximately that of the liabilities. The measurement of the accumulated post-retirement
benefit obligation assumes a health-care cost trend rate of 8.50 percent in 2007 that declines
to 4.50 percent by 2012.
The company establishes the long-term expected rate of return on plan assets by developing a
forward-looking long-term return assumption for each asset class, taking into account factors
such as the expected real return for the specific asset class and inflation. A single long-term
rate of return is then calculated as the weighted average of the target asset allocation and
the long-term return assumption for each asset class. The 2006 long-term expected return of
8.25 percent used in the calculations of pension expense compares to an actual rate of return
over the past decade of 9.82 percent.
The companys pension plan asset allocation at December 31, 2005 and 2006, and target
allocation for 2007 are as follows:
Target | Percentage of plan assets at | ||||||||||||
allocation | December 31 | ||||||||||||
Asset category (percent) | 2007 | 2006 | 2005 | ||||||||||
Equity securities
|
50 - 75 | 64 | 62 | ||||||||||
Debt securities
|
25 - 50 | 36 | 38 | ||||||||||
Other
|
0 - 10 | | | ||||||||||
The companys investment strategy for benefit plan assets reflects a long-term view, a careful
assessment of the risks inherent in various asset classes and broad diversification to reduce
the risk of the total portfolio. The company primarily invests in funds that follow an
index-based strategy to achieve its objectives of diversifying risk while minimizing costs. The
fund holds Imperial Oil Limited common shares primarily only to the extent necessary to
replicate the relevant equity index. Asset-liability studies, or simulations of the interaction
of cash flows associated with both assets and liabilities, are periodically used to establish
the preferred target asset allocation. The target asset allocation for equity securities
reflects the long-term nature of the liability. The balance of the fund is targeted to debt
securities.
A summary of pension plans with accumulated benefit obligations in excess of plan assets is
shown in the table below:
Pension benefits | ||||||||
millions of dollars | 2006 | 2005 | ||||||
For funded pension plans with accumulated benefit
obligations in excess of plan assets: |
||||||||
Projected benefit obligation |
375 | 4,403 | ||||||
Accumulated benefit obligation |
308 | 3,908 | ||||||
Fair value of plan assets |
239 | 3,419 | ||||||
Accumulated benefit obligation less fair value of plan assets |
69 | 489 | ||||||
For unfunded plans covered by book reserves: |
||||||||
Projected benefit obligation |
333 | 381 | ||||||
Accumulated benefit obligation |
314 | 353 | ||||||
F-14
Table of Contents
Notes to consolidated financial statements (continued)
Estimated 2007 amortization from accumulated | Other | |||||||
other nonowner changes in equity | post-retirement | |||||||
millions of dollars | Pension benefits | benefits | ||||||
Net actuarial loss/(gain) (a) |
76 | 6 | ||||||
Prior service cost (b) |
19 | | ||||||
(a) | The company amortizes the net balance of actuarial loss/(gain) over the average remaining service period of active plan participants. | |
(b) | The company amortizes prior service cost on a straight-line basis as permitted under SFAS 87. |
Cash flows
Benefit payments expected in:
Benefit payments expected in:
Other post-retirement |
||||||||
millions of dollars | Pension benefits | benefits | ||||||
2007 |
245 | 23 | ||||||
2008 |
248 | 24 | ||||||
2009 |
252 | 24 | ||||||
2010 |
257 | 24 | ||||||
2011 |
264 | 24 | ||||||
2012 - 2016 |
1,465 | 123 | ||||||
In 2007, the company expects to make cash contributions of about $183 million to its
pension plan.
Sensitivities
A one percent change in the assumptions at which retirement liabilities could be effectively
settled is as follows:
Increase/(decrease) | One percent | One percent | ||||||
millions of dollars | increase | decrease | ||||||
Rate of return on plan assets: |
||||||||
Effect on net benefit cost |
(40 | ) | 40 | |||||
Discount rate: |
||||||||
Effect on net benefit cost |
(60 | ) | 70 | |||||
Effect on benefit obligation |
(590 | ) | 730 | |||||
Rate of pay increases: |
||||||||
Effect on net benefit cost |
40 | (35 | ) | |||||
Effect on benefit obligation |
185 | (150 | ) | |||||
A one percent change in the assumed health-care cost trend rate would have the following
effects:
Increase/(decrease) | One percent | One percent | ||||||
millions of dollars | increase | decrease | ||||||
Effect on service and interest cost components |
4 | (3 | ) | |||||
Effect on benefit obligation |
45 | (35 | ) | |||||
7. | Other long-term obligations |
millions of dollars | 2006 | 2005 | ||||||
Employee retirement benefits (note 6)(a) |
1,017 | 1,152 | ||||||
Asset retirement obligations and other environmental liabilities (b) |
438 | 423 | ||||||
Other obligations |
228 | 153 | ||||||
Total other long-term obligations |
1,683 | 1,728 | ||||||
(a) | Total recorded employee retirement benefit obligations also include $51 million in current liabilities (2005 $47 million). | |
(b) | Total asset retirement obligations and other environmental liabilities also include $97 million in current liabilities (2005 $76 million). |
The change in asset retirement obligations liability is as follows:
millions of dollars | 2006 | 2005 | ||||||
Asset retirement obligations liability at January 1 |
367 | 328 | ||||||
Additions |
61 | 53 | ||||||
Accretion |
22 | 20 | ||||||
Settlement |
(28 | ) | (34 | ) | ||||
Asset retirement obligations liability at December 31 |
422 | 367 | ||||||
F-15
Table of Contents
8. | Derivatives and financial instruments |
No energy derivatives, foreign-exchange forward contracts or currency and interest-rate swaps
were transacted in the past three years. The company maintains a system of controls that
includes a policy covering the authorization, reporting and monitoring of derivative activity.
The fair value of the companys financial instruments is determined by reference to various
market data and other appropriate valuation techniques. There are no material differences
between the fair values of the companys financial instruments from the recorded book value.
9. | Share-based incentive compensation programs |
Share-based incentive compensation programs are designed to retain selected employees, reward
them for high performance and promote individual contribution to sustained improvement in the
companys future business performance and shareholder value.
Incentive share units, deferred share units and restricted stock units
Incentive share units have value if the market price of the companys common shares when the unit is exercised exceeds the market value when the unit was issued, as adjusted for any share splits. The issue price of incentive share units is the closing price of the companys shares on the Toronto Stock Exchange on the grant date. Up to 50 percent of the units may be exercised after one year from issuance; an additional 25 percent may be exercised after two years; and the remaining 25 percent may be exercised after three years. Incentive share units are eligible for exercise up to 10 years from issuance. The units may expire earlier if employment is terminated other than by retirement, death or disability.
Incentive share units have value if the market price of the companys common shares when the unit is exercised exceeds the market value when the unit was issued, as adjusted for any share splits. The issue price of incentive share units is the closing price of the companys shares on the Toronto Stock Exchange on the grant date. Up to 50 percent of the units may be exercised after one year from issuance; an additional 25 percent may be exercised after two years; and the remaining 25 percent may be exercised after three years. Incentive share units are eligible for exercise up to 10 years from issuance. The units may expire earlier if employment is terminated other than by retirement, death or disability.
The deferred share unit plan is made available to selected executives and nonemployee
directors. The selected executives can elect to receive all or part of their performance bonus
compensation in units and the nonemployee directors can elect to receive all or part of their
directors fees in units. The number of units granted to executives is determined by dividing
the amount of the bonus elected to be received as deferred share units by the average of the
closing prices of the companys shares on the Toronto Stock Exchange for the five consecutive
trading days immediately prior to the date that the bonus would have been paid. The number of
units granted to a nonemployee director is determined at the end of each calendar quarter by
dividing the amount of directors fees for the calendar quarter that the nonemployee director
elected to receive as deferred share units by the average closing price of the companys shares
for the five consecutive trading days immediately prior to the last day of the calendar
quarter. Additional units are granted based on the cash dividend
payable on the companys shares divided by the average closing price immediately prior to the payment date for that
dividend and multiplying the resulting number by the number of deferred share units held by the
recipient, as adjusted for any share splits.
Deferred share units cannot be exercised until after termination of employment with the company
or resignation as a director and must be exercised no later than December 31 of the year
following termination or resignation. On the exercise date, the cash value to be received for
the units is determined based on the average closing price of the companys shares for the five
consecutive trading days immediately prior to the date of exercise, as adjusted for any share
splits.
Under the restricted stock unit plan, each unit entitles the recipient to the conditional right
to receive from the company, upon exercise, an amount equal to the five-day average of the
closing price of the companys common shares on the Toronto Stock Exchange on and immediately
prior to the exercise dates. Fifty percent of the units are exercised three years following the
grant date, and the remainder are exercised seven years following the grant date. For units
granted in 2002 to 2005, the exercise date has been changed from December 31 to December 4 for
units exercised in 2006 and subsequent years. For units granted in 2002, 2003, 2004 and 2005 to
be exercised subsequent to the companys May 2006 three-for-one share split, the company has
indicated that it will increase the cash payment or number of shares issued per unit, as the
case may be, by the factor of three.
All units require settlement by cash payments with one exception. The restricted stock unit
program 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 in the seventh year following the grant date.
In accordance with SFAS 123R, the company accounts for these units by using the
fair-value-based method. The fair value of awards in the form of incentive share, deferred
share and restricted stock units is the market price of the companys stock, which is the same
method of accounting as under SFAS 123. Under this method, compensation expense related to the
units of these programs is measured each reporting period based on the companys current stock
price and is recorded in the consolidated statement of income over the vesting period.
The following table summarizes information about these units for the year ended December 31,
2006:
Incentive share | Deferred share | Restricted | ||||||||||
units | units | stock units | ||||||||||
(a) | (a) | (a) | ||||||||||
Outstanding at January 1, 2006 |
10,884,891 | 138,567 | 10,556,730 | |||||||||
Granted |
| 6,662 | 1,935,658 | |||||||||
Exercised |
(1,797,141 | ) | (60,781 | ) | (2,488,047 | ) | ||||||
Cancelled or adjusted |
(16,500 | ) | | (7,951 | ) | |||||||
Outstanding at December 31, 2006 |
9,071,250 | 84,448 | 9,996,390 | |||||||||
(a) | Reflects number of units granted after the share split in 2006, plus the number of units granted prior to the share split in 2006 as adjusted for the share splits that occurred in 1998 and 2006. |
The compensation expense charged against income for these programs was $133 million, $238
million and $95 million in 2006, 2005, and 2004, respectively. Total income tax benefit
recognized in income related to this compensation expense was $45 million, $127 million and $46
million in 2006, 2005 and 2004, respectively. Cash payments of $162 million, $169 million and
$64 million for these programs were made in 2006, 2005 and 2004, respectively.
As of December 31, 2006, there was $265 million of total before-tax unrecognized compensation
expenses related to nonvested restricted stock units based on the companys share price at the
end of the current reporting period. The weighted average vesting period of nonvested
restricted stock units is 3.9 years. All units under the incentive share and deferred share
programs have vested as of December 31, 2006.
F-16
Table of Contents
Notes to consolidated financial statements (continued)
Incentive stock options
In April 2002, incentive stock options were granted for the purchase of the companys
common shares at an exercise price of $15.50 per share (adjusted to reflect the three-for-one
share split). Up to 50 percent of the options may be exercised on or after January 1, 2003; a
further 25 percent may be exercised on or after January 1, 2004; and the remaining 25 percent
may be exercised on or after January 1, 2005. Any unexercised options expire after April 29,
2012. The company has not issued incentive stock options since 2002 and has no plans to issue
incentive stock options in the future.
As permitted by SFAS 123, the company continues to apply the intrinsic-value-based method of
accounting for the incentive stock options granted in April 2002. Under this method,
compensation expense is not recognized on the issuance of stock options, as the exercise price
is equal to the market value at the date of grant. All incentive stock options have vested as
of January 1, 2005.
No compensation expense and no income tax benefit related to stock options were recognized for
stock options in 2006, 2005 and 2004. Cash received from stock option exercised in 2006 was $10
million. The aggregate intrinsic value of stock options exercised was $18 million, $43 million
and $5 million in 2006, 2005 and 2004, respectively, and for the balance of outstanding stock
options is $152 million.
The average fair value of each option granted during 2002 was $4.23 (adjusted to reflect the
three-for-one share split). The fair value was estimated at the grant date using an
option-pricing model with the following weighted average assumptions: risk-free interest rate
of 5.7 percent, expected life of five years, volatility of 25 percent and a dividend yield of
1.9 percent.
The company has purchased shares on the market to fully offset the dilutive effects from the
exercise of stock options. The practice is expected to continue.
The following table summarizes information about stock options for the year ended December 31,
2006 :
Exercise | Remaining | |||||||||||
price | contractual term | |||||||||||
Units (a) | (dollars) (b) | (years) | ||||||||||
Incentive stock options |
||||||||||||
Outstanding at January 1, 2006 |
6,135,000 | 15.50 | ||||||||||
Granted |
| |||||||||||
Exercised |
(628,335 | ) | 15.50 | |||||||||
Cancelled or adjusted |
21,000 | |||||||||||
Outstanding at December 31, 2006 |
5,527,665 | 15.50 | 5.3 | |||||||||
(a) | Reflects number of units granted, as adjusted for any share splits. | |
(b) | Adjusted to reflect the three-for-one share split. |
10. | Investment and other income |
Investment and other income includes gains and losses on asset sales as follows:
millions of dollars | 2006 | 2005 | 2004 | |||||||||
Proceeds from asset sales |
212 | 440 | 102 | |||||||||
Book value of assets sold |
78 | 96 | 59 | |||||||||
Gain/(loss) on asset sales, before tax (a) |
134 | 344 | 43 | |||||||||
Gain/(loss) on asset sales, after tax (a) |
96 | 233 | 32 | |||||||||
(a) | 2005 included a gain of $251 million ($163 million, after tax) from the sale of the wholly owned Redwater and interests in the North Pembina fields. |
11. | Commitments and contingent liabilities |
At December 31, 2006, the company had commitments for non-cancellable operating leases and
other long-term agreements that require the following minimum future payments:
After | ||||||||||||||||||||||||
millions of dollars | 2007 | 2008 | 2009 | 2010 | 2011 | 2011 | ||||||||||||||||||
Operating leases (a) |
53 | 51 | 46 | 40 | 35 | 48 | ||||||||||||||||||
Unconditional purchase obligations (b) |
58 | 58 | 57 | 26 | 26 | 40 | ||||||||||||||||||
Firm capital commitments (c) |
149 | 11 | 17 | 1 | | | ||||||||||||||||||
Other long-term agreements (d) |
271 | 238 | 164 | 147 | 128 | 240 | ||||||||||||||||||
(a) | Total rental expense incurred for operating leases in 2006 was $79 million (2005 $83 million; 2004 $104 million) which included minimum rental expenditures of $66 million (2005 $63 million; 2004 $77 million). Related rental income was not material. | |
(b) | Unconditional purchase obligations are those long-term commitments that are non-cancellable or cancellable only under certain conditions. These mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $100 million in 2006 (2005 $104 million; 2004 $117 million). | |
(c) | Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled approximately $178 million at the end of 2006 (2005 $232 million). Commitments of $136 million were associated with the companys share of upstream capital projects; the largest commitment of $41 million related to Syncrude. | |
(d) | Other long-term agreements include primarily raw material supply and transportation services agreements. Total payments under other long-term agreements were $441 million in 2006 (2005 $448 million; 2004 $355 million). Payments under other long-term agreements related to the companys share of undivided interest in activities conducted jointly with other companies are approximately $103 million per year. |
Other commitments arising in the normal course of business for operating and capital needs
do not materially affect the companys consolidated financial position.
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The company was contingently liable at December 31, 2006, for a maximum of $87 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 payment under the guarantees.
Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. The company
accrues an undiscounted liability for those contingencies where the incurrence of a loss is
determined to be probable and the amount can be reasonably estimated. 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. There are no events or uncertainties known to
management beyond those already included in reported financial information that would indicate
a material change in future operating results or financial condition.
12. | Common shares |
As at | As at | ||||||||
thousands of shares | Dec. 31 2006 | Dec. 31 2005 | |||||||
Authorized (prior period data have not been restated) |
1,100,000 | 450,000 | |||||||
Effective May 23, 2006, the issued common shares of the company were split on a three-for-one
basis and the number of authorized shares was increased from 450 million to 1,100 million. The
prior period number of shares outstanding and shares purchased, as well as net income and
dividends per share, have been adjusted to reflect the three-for one split.
From 1995 to 2005, the company purchased shares under eleven 12-month normal course share
purchase programs, as well as an auction tender. On June 23, 2006, another 12-month normal
course share purchase program was implemented with an allowable purchase of 48.8 million shares
(five percent of the total at June 21, 2006), less any shares purchased by the employee savings
plan and company pension fund. The results of these activities are shown below.
Purchased shares | Millions of | |||||||
Year | (thousands) | dollars | ||||||
1995 to 2004 |
697,582 | 6,840 | ||||||
2005 |
52,527 | 1,795 | ||||||
2006 |
45,514 | 1,818 | ||||||
Cumulative purchases to date |
795,623 | 10,453 | ||||||
Exxon Mobil Corporations participation in the above maintained its ownership interest in
Imperial at 69.6 percent.
The excess of the purchase cost over the stated value of shares purchased has been recorded as
a distribution of retained earnings.
The companys common share activities are summarized below:
Thousands of shares | Millions of dollars | |||||||
Balance as at January 1, 2004 |
1,087,959 | 1,859 | ||||||
Issued for cash under the stock option plan |
822 | 13 | ||||||
Purchases |
(40,821 | ) | (71 | ) | ||||
Balance as at December 31, 2004 |
1,047,960 | 1,801 | ||||||
Issued for cash under the stock option plan |
2,442 | 38 | ||||||
Purchases |
(52,527 | ) | (92 | ) | ||||
Balance as at December 31, 2005 |
997,875 | 1,747 | ||||||
Issued for cash under the stock option plan |
627 | 10 | ||||||
Purchases |
(45,514 | ) | (80 | ) | ||||
Balance as at December 31, 2006 |
952,988 | 1,677 | ||||||
The following table provides the calculation of basic and diluted earnings per share:
2006 | 2005 | 2004 | ||||||||||
Net income per common share basic |
||||||||||||
Net income (millions of dollars) |
3,044 | 2,600 | 2,052 | |||||||||
Weighted average number of common shares outstanding (thousands of shares) |
975,128 | 1,024,119 | 1,070,502 | |||||||||
Net income per common share (dollars) |
3.12 | 2.54 | 1.92 | |||||||||
Net income per common share diluted |
||||||||||||
Net income (millions of dollars) |
3,044 | 2,600 | 2,052 | |||||||||
Weighted average number of common shares outstanding (thousands of shares) |
975,128 | 1,024,119 | 1,070,502 | |||||||||
Effect of employee stock-based awards (thousands of shares) |
4,460 | 4,179 | 2,454 | |||||||||
Weighted average number of common shares outstanding,
assuming dilution (thousands of shares) |
979,588 | 1,028,298 | 1,072,956 | |||||||||
Net income per common share (dollars) |
3.11 | 2.53 | 1.91 | |||||||||
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Notes to consolidated financial statements (continued)
13. | Miscellaneous financial information |
In 2006, net income included an after-tax gain of $14 million (2005 $5 million gain; 2004
$23 million gain) attributable to the effect of changes in last-in, first-out (LIFO)
inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying
values at December 31, 2006 by $1,509 million (2005 $1,429 million). Inventories of crude oil
and products at year-end consisted of the following:
million of dollars | 2006 | 2005 | ||||||
Crude oil |
211 | 174 | ||||||
Petroleum products |
277 | 234 | ||||||
Chemical products |
54 | 63 | ||||||
Natural gas and other |
14 | 10 | ||||||
Total inventories of crude oil and products |
556 | 481 | ||||||
Research and development costs in 2006 were $73 million (2005 $68 million; 2004 $70
million) before investment tax credits earned on these expenditures of $7 million (2005 $10
million; 2004 $7 million). Research and development costs are included in expenses due to the
uncertainty of future benefits.
Cash flow from operating activities included dividends of $18 million received from equity
investments in 2006 (2005 $21 million; 2004 $18 million).
14. | Financing costs |
millions of dollars | 2006 | 2005 | 2004 | |||||||||
Debt-related interest |
63 | 45 | 37 | |||||||||
Capitalized interest |
(48 | ) | (41 | ) | (34 | ) | ||||||
Net interest expense |
15 | 4 | 3 | |||||||||
Other interest |
13 | 4 | 4 | |||||||||
Total financing costs (a) |
28 | 8 | 7 | |||||||||
(a) | Cash interest payments in 2006 were $71 million (2005 $45 million; 2004 $41 million). The weighted average interest rate on short-term borrowings in 2006 was 4.1 percent (2005 2.7 percent). |
15. | Transactions with related parties |
Revenues and expenses of the company also include the results of transactions with Exxon Mobil
Corporation and affiliated companies (ExxonMobil) in the normal course of operations. These
were conducted on terms as favourable as they would have been with unrelated parties and
primarily consisted of the purchase and sale of crude oil and petroleum and chemical products,
as well as transportation, technical and engineering services. Transactions with ExxonMobil
also included amounts paid and received in connection with the companys participation in a
number of natural resources activities conducted jointly in Canada. The company has existing
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 that
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. This contractual agreement is designed to provide
organizational efficiencies and to reduce costs. No separate legal entities were created from
this arrangement. Separate books of account continue to be maintained for Imperial and
ExxonMobil. Imperial and ExxonMobil retain ownership of their respective assets and there is no
impact on operations or reserves.
Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.
The company borrowed $818 million (Cdn) from an affiliated company of Exxon Mobil Corporation
under two long-term loan agreements as presented in note 4.
As at December 31, 2006, the company had outstanding loans of $33 million (2005 $32 million)
to Montreal Pipe Line Limited, in which the company has an equity interest, for financing of
the equity companys capital expenditure programs and working capital requirements.
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16. Net payments/payables to governments
millions of dollars | 2006 | 2005 | 2004 | |||||||||
Current income tax expense (note 5) |
776 | 1,361 | 1,103 | |||||||||
Federal excise tax |
1,274 | 1,278 | 1,264 | |||||||||
Property taxes included in expenses |
100 | 99 | 85 | |||||||||
Payroll and other taxes included in expenses |
46 | 52 | 50 | |||||||||
GST/QST/HST collected (a) |
2,715 | 2,703 | 2,297 | |||||||||
GST/QST/HST input tax credits (a) |
(2,293 | ) | (2,344 | ) | (1,948 | ) | ||||||
Other consumer taxes collected for governments |
1,667 | 1,613 | 1,670 | |||||||||
Crown royalties |
904 | 620 | 472 | |||||||||
Total paid or payable to governments |
5,189 | 5,382 | 4,993 | |||||||||
Less investment tax credits and other receipts |
11 | 9 | 14 | |||||||||
Net paid or payable to governments |
5,178 | 5,373 | 4,979 | |||||||||
Net paid or payable to: |
||||||||||||
Federal government |
2,352 | 2,736 | 2,472 | |||||||||
Provincial governments |
2,726 | 2,538 | 2,422 | |||||||||
Local governments |
100 | 99 | 85 | |||||||||
Net paid or payable to governments |
5,178 | 5,373 | 4,979 | |||||||||
(a) | The abbreviations refer to the federal goods and services tax, the Quebec sales tax and the federal/provincial harmonized sales tax, respectively. The HST is applicable in the provinces of Nova Scotia, New Brunswick and Newfoundland and Labrador. |
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