WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, | Commission file number: 0-12014 |
IMPERIAL OIL LIMITED
(Exact name of registrant as specified in its charter)
CANADA (State or other jurisdiction of incorporation or organization) | 98-0017682 (I.R.S. Employer Identification No.) |
237 FOURTH AVENUE S.W., CALGARY, AB, CANADA (Address of principal executive offices) | T2P 3M9 (Postal Code) |
Registrant’s telephone number, including area code:
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)
(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).
Yesü No......
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
Yes ...... Noü
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.
Yesü No......
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s 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.
Yesü No......
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (see definitionthe definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934).
Large accelerated filerü Accelerated filer......filer Non-accelerated filer......filer Smaller reporting company......
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12 b-2 of the Securities Exchange Act of 1934).
Yes ...... Noü
As of the last business day of the 20072008 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $13,974,075,595$15,059,343,761 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date.
The number of common shares outstanding, as of February 14, 2008,13, 2009, was 900,825,903.
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Item 1A. | 14 | |||||
Item 1B. | 16 | |||||
Item 2. | 16 | |||||
Item 3. | 16 | |||||
Item 4. | 16 | |||||
PART II | ||||||
Item 5. | ||||||
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Item 6. | 18 | |||||
Item 7. | 18 | |||||
Item 7A. | 28 | |||||
Item 8. | 29 | |||||
Item 9. | 33 | |||||
Item 9A. | 33 | |||||
Item 9B. | 33 | |||||
PART III | ||||||
Item 10. | ||||||
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Item 11. | 37 | |||||
Item 12. | 53 | |||||
Item 13. | 54 | |||||
Item 14. | 55 | |||||
PART IV | ||||||
Item 15. | ||||||
56 | ||||||
Index to Financial Statements | F-1 | |||||
Management’s Report on Internal Control over Financial Reporting | F-2 | |||||
Auditors’ Report | 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.
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(dollars) | ||||||||||||||||||||
Rate at end of period | 1.0120 | 0.8582 | 0.8579 | 0.8310 | 0.7738 | |||||||||||||||
Average rate during period | 0.9376 | 0.8844 | 0.8276 | 0.7702 | 0.7186 | |||||||||||||||
High | 1.0908 | 0.9100 | 0.8690 | 0.8493 | 0.7738 | |||||||||||||||
Low | 0.8437 | 0.8528 | 0.7872 | 0.7158 | 0.6349 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(dollars) | ||||||||||
Rate at end of period | 0.8170 | 1.0120 | 0.8582 | 0.8579 | 0.8310 | |||||
Average rate during period | 0.9335 | 0.9376 | 0.8844 | 0.8276 | 0.7702 | |||||
High | 1.0291 | 1.0908 | 0.9100 | 0.8690 | 0.8493 | |||||
Low | 0.7710 | 0.8437 | 0.8528 | 0.7872 | 0.7158 |
On February 14, 2008,13, 2009, the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $1.0033$0.8042 U.S. = $1.00 Canadian.
2
Forward-Looking Statements
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.company. 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 Canada’s 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, natural gas 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.
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
External sales (1): | (millions of dollars) | |||||||||||||||||||
Natural resources | 4,539 | 4,619 | 4,702 | 3,689 | 3,390 | |||||||||||||||
Petroleum products | 19,230 | 18,527 | 21,793 | 17,503 | 14,710 | |||||||||||||||
Chemicals | 1,300 | 1,359 | 1,302 | 1,216 | 994 | |||||||||||||||
Corporate and other | – | – | – | – | – | |||||||||||||||
25,069 | 24,505 | 27,797 | 22,408 | 19,094 | ||||||||||||||||
Intersegment sales: | ||||||||||||||||||||
Natural resources | 4,146 | 3,837 | 3,487 | 2,891 | 2,224 | |||||||||||||||
Petroleum products | 2,305 | 2,256 | 2,224 | 1,666 | 1,294 | |||||||||||||||
Chemicals | 335 | 345 | 363 | 293 | 238 | |||||||||||||||
Net income (2): | ||||||||||||||||||||
Natural resources | 2,369 | 2,376 | 2,008 | 1,517 | 1,174 | |||||||||||||||
Petroleum products | 921 | 624 | 694 | 556 | 462 | |||||||||||||||
Chemicals | 97 | 143 | 121 | 109 | 44 | |||||||||||||||
Corporate and other (3)/eliminations | (199) | (99) | (223) | (130) | 25 | |||||||||||||||
3,188 | 3,044 | 2,600 | 2,052 | 1,705 | ||||||||||||||||
Identifiable assets at December 31 (4): | ||||||||||||||||||||
Natural resources | 8,171 | 7,513 | 7,289 | 6,822 | 6,397 | |||||||||||||||
Petroleum products | 6,727 | 6,450 | 6,257 | 5,509 | 5,225 | |||||||||||||||
Chemicals | 476 | 504 | 500 | 490 | 433 | |||||||||||||||
Corporate and other/eliminations | 1,251 | 1,674 | 1,536 | 1,206 | 282 | |||||||||||||||
16,287 | 16,141 | 15,582 | 14,027 | 12,337 | ||||||||||||||||
Capital and exploration expenditures: | ||||||||||||||||||||
Natural resources | 744 | 787 | 937 | 1,113 | 1,007 | |||||||||||||||
Petroleum products | 187 | 361 | 478 | 283 | 478 | |||||||||||||||
Chemicals | 11 | 13 | 19 | 15 | 41 | |||||||||||||||
Corporate and other | 36 | 48 | 41 | 34 | 33 | |||||||||||||||
978 | 1,209 | 1,475 | 1,445 | 1,559 | ||||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
External sales(1): | (millions of dollars) | |||||||||
Upstream | 5,819 | 4,539 | 4,619 | 4,702 | 3,689 | |||||
Downstream | 24,049 | 19,230 | 18,527 | 21,793 | 17,503 | |||||
Chemical | 1,372 | 1,300 | 1,359 | 1,302 | 1,216 | |||||
31,240 | 25,069 | 24,505 | 27,797 | 22,408 | ||||||
Intersegment sales: | ||||||||||
Upstream | 5,403 | 4,146 | 3,837 | 3,487 | 2,891 | |||||
Downstream | 2,892 | 2,305 | 2,256 | 2,224 | 1,666 | |||||
Chemical | 460 | 335 | 345 | 363 | 293 | |||||
Net income(2): | ||||||||||
Upstream | 2,923 | 2,369 | 2,376 | 2,008 | 1,517 | |||||
Downstream | 796 | 921 | 624 | 694 | 556 | |||||
Chemical | 100 | 97 | 143 | 121 | 109 | |||||
Corporate and other(3)/eliminations | 59 | (199) | (99) | (223) | (130) | |||||
3,878 | 3,188 | 3,044 | 2,600 | 2,052 | ||||||
Identifiable assets at December 31(4): | ||||||||||
Upstream | 8,758 | 8,171 | 7,513 | 7,289 | 6,822 | |||||
Downstream | 6,038 | 6,727 | 6,450 | 6,257 | 5,509 | |||||
Chemical | 431 | 476 | 504 | 500 | 490 | |||||
Corporate and other/eliminations | 1,808 | 913 | 1,674 | 1,536 | 1,206 | |||||
17,035 | 16,287 | 16,141 | 15,582 | 14,027 | ||||||
Capital and exploration expenditures: | ||||||||||
Upstream | 1,110 | 744 | 787 | 937 | 1,113 | |||||
Downstream | 232 | 187 | 361 | 478 | 283 | |||||
Chemical | 13 | 11 | 13 | 19 | 15 | |||||
Corporate and other | 8 | 36 | 48 | 41 | 34 | |||||
1,363 | 978 | 1,209 | 1,475 | 1,445 |
(1) | Export sales are reported in note 3 to the consolidated financial statements on page |
(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 and incentive compensation |
(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 |
3
Natural Resources
The company’s average daily production of crude oil and natural gas liquids during the five years ended December 31, 2007,2008, was as follows:
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||||
Conventional (including natural gas liquids): | (thousands a day) | |||||||||||||||||||||
Barrels | – Gross (1) | 45 | 55 | 69 | 76 | 74 | ||||||||||||||||
– Net (2) | 33 | 42 | 54 | 59 | 57 | |||||||||||||||||
Heavy Oil (3): | ||||||||||||||||||||||
Barrels | – Gross (1) | 154 | 152 | 139 | 126 | 129 | ||||||||||||||||
– Net (2) | 130 | 127 | 124 | 112 | 116 | |||||||||||||||||
Oil Sands (4): | ||||||||||||||||||||||
Barrels | – Gross (1) | 76 | 65 | 53 | 60 | 53 | ||||||||||||||||
– Net (2) | 65 | 58 | 53 | 59 | 52 | |||||||||||||||||
Total: | ||||||||||||||||||||||
Barrels | – Gross (1) | 275 | 272 | 261 | 262 | 256 | ||||||||||||||||
– Net (2) | 228 | 227 | 231 | 230 | 225 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
Conventional (including natural gas liquids): | (thousands a day) | |||||||||
Barrels – Gross (1) | 37 | 45 | 55 | 69 | 76 | |||||
– Net(2) | 27 | 33 | 42 | 54 | 59 | |||||
Heavy Oil(3): | ||||||||||
Barrels – Gross(1) | 147 | 154 | 152 | 139 | 126 | |||||
– Net(2) | 124 | 130 | 127 | 124 | 112 | |||||
Oil Sands(4): | ||||||||||
Barrels – Gross (1) | 72 | 76 | 65 | 53 | 60 | |||||
– Net(2) | 62 | 65 | 58 | 53 | 59 | |||||
Total: | ||||||||||
Barrels – Gross(1) | 256 | 275 | 272 | 261 | 262 | |||||
– Net(2) | 213 | 228 | 227 | 231 | 230 |
(1) | Gross production of crude oil is the company’s 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 company’s 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 company’s heavy oil production volumes are from |
(4) | Oil sands are a semi-solid material composed of bitumen, sand, water and clays and are recovered through surface mining methods. Imperial’s oil sands production volumes are the company’s share of production volumes in the Syncrude joint venture. |
In 2005 and 2006 conventional production fell mainly due to the natural decline of the company’s conventional fields. In 2007, the lower conventional production volume was primarily due to decline in the Wizard Lake field. In 2004, Cold Lake2008, the conventional production declinedvolume was lower primarily due to the timingcompletion of steaming cycles and higher royalty, and Syncrude production increased due to improved reliability in upgrading operations than in 2003. In 2005, the Wizard Lake blowdown.
Cold Lake production increased from 2004 to 2007 due to the timing of steaming cycles and increased volumes from the ongoing development drilling program,program. In 2008, Cold Lake production declined due to steam cycle timing and higher royalties.
In 2005 Syncrude production declined primarily due to increased maintenance for upgrading facilities. In 2006, Cold Lake production increased due to timing of steam cycles and production from the ongoing development drilling program and Syncrude production increased due to lower maintenance activities and the start-up of expanded upgrading facilities. In 2007, Cold Lake production increased due to timing of steam cycles and production from the ongoing development drilling program and Syncrude production increased with full year operation of the expanded upgrading facilities.
The company’s average daily production and sales of natural gas during the five years ended December 31, 20072008 are set forth below. All gas volumes in this report are calculated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit.
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(millions a day) | ||||||||||||||||||||
Sales (1): | ||||||||||||||||||||
Cubic feet | 407 | 513 | 536 | 520 | 460 | |||||||||||||||
Gross Production (2): | ||||||||||||||||||||
Cubic feet | 458 | 556 | 580 | 569 | 513 | |||||||||||||||
Net Production (2): | ||||||||||||||||||||
Cubic feet | 404 | 496 | 514 | 518 | 457 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(millions a day) | ||||||||||
Sales(1): | ||||||||||
Cubic feet | 288 | 407 | 513 | 536 | 520 | |||||
Gross Production(2): | ||||||||||
Cubic feet | 310 | 458 | 556 | 580 | 569 | |||||
Net Production(2): | ||||||||||
Cubic feet | 249 | 404 | 496 | 514 | 518 |
(1) | Sales are sales of the company’s 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 company’s share of production (excluding purchases) before deducting the shares of mineral owners or governments or both. Net production excludes those shares. Production data include amounts used for internal consumption with the exception of amounts reinjected. |
4
Most of the company’s natural gas sales are made under short term contracts.
The company’s average sales price and production costs for conventional crude oil, Cold Lake heavy oil and natural gas liquids and natural gas for the five years ended December 31, 2007,2008, were as follows:
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
Average Sales Price: | ||||||||||||||||||||
Crude oil and natural gas liquids: | ||||||||||||||||||||
Dollars per barrel | 45.16 | 45.13 | 37.21 | 32.95 | 28.92 | |||||||||||||||
Natural gas: | ||||||||||||||||||||
Dollars per thousand cubic feet | 6.95 | 7.24 | 9.00 | 6.78 | 6.60 | |||||||||||||||
Average Production Costs Per | ||||||||||||||||||||
Unit of Net Production (1)(2): | ||||||||||||||||||||
Dollars per barrel | 12.75 | 11.08 | 10.78 | 9.25 | 9.66 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
Average Sales Price: | ||||||||||
Crude oil and natural gas liquids: | ||||||||||
Dollars per barrel | 72.29 | 45.16 | 45.13 | 37.21 | 32.95 | |||||
Natural gas: | ||||||||||
Dollars per thousand cubic feet | 8.69 | 6.95 | 7.24 | 9.00 | 6.78 | |||||
Average Production Costs Per | ||||||||||
Unit of Net Production(1)(2): | ||||||||||
Dollars per barrel | 18.91 | 12.75 | 11.08 | 10.78 | 9.25 |
(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, and the impact of foreign exchange rates.
Canadian natural gas prices are determined by North American gas markets, which are also volatile, and the impact of foreign exchange rates. Natural gas prices throughout North America increased in the second half of 2005 due to supply disruptions from hurricane damage to facilities in the U.S. Gulf Coast.
In 2005, average unit production costs increased mainly due to higher costs of purchased natural gas at Cold Lake. In 2006, average production costs increased due to lower gas production and higher liquids royalties resulting in lower net liquids production. Liquids royalties were higher in the year due to increased realizations for Cold Lake production. In 2007, unit production costs were higher primarily as a result of lower gas and liquids volumes due to decline in production fromat Wizard Lake.
The company has interests in a large number of facilities related to the production of crude oil and natural gas. Among these facilities are 2119 plants that process natural gas to produce marketable gas and recover natural gas liquids or sulphur. TheIn 2008, the number of plants for which the company is the principal owner and operator ofdropped from 10 to eight, with the shutdown of the plants.
The company’s production of conventional crude oil, Cold Lake heavy oil and natural gas is derived from wells located exclusively in Canada. The total number of producing wells in which the company had interests at December 31, 2007,2008, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.
Crude Oil | Natural Gas | Total | ||||||||||||||||||||||
Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||||||||||||||
Conventional wells | 1,139 | 756 | 5,090 | 2,773 | 6,229 | 3,529 | ||||||||||||||||||
Heavy Oil wells | 4,143 | 4,143 | – | – | 4,143 | 4,143 |
Crude Oil | Natural Gas | Total | ||||||||||
Gross (1) | Net (2) | Gross (1) | Net (2) | Gross (1) | Net (2) | |||||||
Conventional wells | 906 | 601 | 5,186 | 2,768 | 6,092 | 3,369 | ||||||
Heavy Oil wells | 4,243 | 4,243 | - | - | 4,243 | 4,243 |
(1) | Gross wells are wells in which the company owns a working interest. |
(2) | Net wells are the sum of the fractional working interests owned by the company in gross wells, rounded to the nearest whole number. |
Conventional Oil and Gas
The company’s largest conventional oil producing asset is the Norman Wells oil field in the Northwest Territories which currently accounts for approximately 5758 percent of the company’s net production of conventional crude oil (approximately 63 percent of gross production). In 2007,2008, net production of crude oil and natural gas liquids was about 12,40011,300 barrels per day and gross production was about 18,20017,000 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 Canada’s carried interest entitles it to receive payment of a one-third share of an amount based on revenues from the sale of Norman Wells production, net of operating and capital costs. Under a shipping agreement, the company pays for the construction, operating and other costs of the 540 mile pipeline which transports the crude oil and natural gas liquids from the project. In 2007,2008, those costs were about $33$36 million.
Most of the larger oil fields in the Western Provinces have been in production for several decades, and the amount of oil that is produced from conventional fields is declining. In some cases, however, additional oil can be
5
Cold Lake
The company holds about 192,000194,000 net acres of heavy oil leases near Cold Lake, Alberta. To develop the technology necessary to produce this oil commercially, the company has conductedconducts experimental pilot operations since 1964 to recover theimprove recovery of heavy oil from wells by means of new drilling and production techniques including steam injection. Research at, and operation of, the Cold Lake pilots is continuing.
In late 1983, the company commenced the development, in phases, of its heavy oil resources at Cold Lake. During 2007,2008, average net production at Cold Lake was about 130,000123,800 barrels per day and gross production was about 153,500146,700 barrels per day.
To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities will be required periodically. In 2007,2008, the company spent $307$305 million and executed a development drilling program of 18870 wells on existing phases. In 2008,2009, a development drilling program of more than 100 wells is planned within the approved development area to add productive capacity from undeveloped areas of existing Cold Lake phases. In addition, opportunities are being evaluated to improve utilizationplanning and design work is progressing on the Nabiye project, the next phase of the existing infrastructure.
Most of the production from Cold Lake is sold to refineries in the northern United States. The majority of the remainder of the Cold Lake production is shipped to certain of the company’s refineries and to a third-party heavy oil upgrader in Lloydminster, Saskatchewan.
The Province of Alberta, in its capacity as lessor of the Cold Lake heavy oil leases, is entitled to a royalty on production from theat Cold Lake production project.Lake. The original royalty agreement, which applied through the end of 1999, provided for a royalty calculated at the greater of five percent of gross revenue or 30 percent of an amount based on revenue net of operating and capital costs. It also provided for a royalty waiver on equity natural gas produced in Alberta and deemed to be consumed in generating steam at the company’s Cold Lake operations. Effective January 1, 2000, the company entered into an agreement with the Province of Alberta on a transitional royalty arrangement that applied to all of the company’s operations at Cold Lake until the end of 2007, at which time the generic Alberta regulations for heavy oil royalties applied. The transition agreement made provision for the differences between the two royalty regimes (higher bitumen royalties with gas royalty waiver vs. lower bitumen royalties and no gas royalty waiver). The generic regulations, which applywere effective January 1, 2008, provideprovided for a royalty calculated at the greater of one percent of gross revenue or 25 percent of an amount based on revenue net of operating and capital costs, and with no gas royalty waiver. The transition did not materially change the amount of royalties that the company would have otherwise paid under the pre-existing royalty arrangements. In 2007,Cold Lake will be subject to the Alberta government proposed increases to thegeneric oil sand royalty rates beginningregime, which was modified in 2007 and took effect in 2009. The company believes that this proposal could have an adverse effect on future company investments in Alberta andRoyalty rates will be based upon a sliding scale, determined by the company’s future financial results. The magnitudeprice of the potential impact will depend on the final form of enacted legislation and the future prices of oil and gas and cannot be reasonably estimated at this time.crude oil. The effective royalty on gross production was 16 percent in 2008, 15 percent in 2007, 17 percent in 2006, and 11 percent in 2005 and 2004 and 10 percent in 2003.
Other Heavy Oil Activity
The company has interests in other heavy oil leases in the Athabasca and Peace River areas of northern Alberta.Alberta, totaling about 170,000 net acres. 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.
Syncrude and several joint ventures, has been involved in recovery research and pilot studies and in evaluating the quality and extent of the heavy oil deposit.
Syncrude Mining Operations
The company holds a 25 percent participating interest in Syncrude, a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, and to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The Syncrude operation, located near Fort McMurray, Alberta (see map), mines a portion of the Athabasca oil sands deposit. The location is readily accessible by public road. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. Since startup in 1978, Syncrude has produced about 1.81.9 billion barrels of synthetic crude oil.
6
In November 2008, Imperial, along with the other Syncrude joint-venture owners, signed an agreement with the Government of Alberta to amend the existing Syncrude Crown Agreement. Under the amended agreement, beginning January 1, 2002, the greater of 25 percent deemed net profit royalty or one percent gross royalty applies to all2010, 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 (located on lease 17) was depleted and ceased operation in 2007. In the North mine (leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), truck, shovel and hydrotransport systems are used. The extraction facilities, which separate crude bitumen from sand, are capable of processing approximately 830,000 tons of oil sands a day, producing about 150 million barrels of crude bitumen a year. This represents recovery capability of about 93 percent of the crude bitumen contained in the mined oil sands.
Crude bitumen extracted from oil sands is refined to a marketable hydrocarbon product through a combination of carbon removal in three large, high temperature, fluid coking vessels and by hydrogen addition in high temperature, high pressure, hydrocracking vessels. These processes remove carbon and sulphur and reformulate the crude into a low viscosity, low sulphur, high quality synthetic crude oil product. In 2007,2008, the upgrading process yielded 0.8430.859 barrels of synthetic crude oil per barrel of crude bitumen. In 2007,2008, about 3839 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 6261 percent was pipelined to refineries in
7
In 20072008 Syncrude’s net production of synthetic crude oil was about 259,300246,800 barrels per day and gross production was about 305,000288,900 barrels per day. The company’s share of net production in 20072008 was about 64,80061,700 barrels per day.
In 2000, Syncrude completed development of the first stage of the Aurora mine. The Aurora investment involved extending mining operations to a new location about 22 miles from the main Syncrude site and expanding upgrading capacity. In 2001, the Syncrude owners approved another major expansion of upgrading capacity and further development of the Aurora mine. The second Aurora mining and extraction development became fully operational in 2004. The increased upgrading capacity came on stream in 2006. These projects increased total production capacity to about 355,000 barrels of synthetic crude oil a day. The company’s share of total project costs was $2.1 billion. Additional mining trains in the North mine and Aurora mine were also completed in 2005. There are no approved plans for major future expansion projects.
On May 1, 2007, the company implemented a management services agreement under which Syncrude will be provided with operational, technical and business management services from Imperial and Exxon Mobil Corporation. The agreement has an initial term of 10 years and may be terminated by the company or Syncrude with at least two years prior written notice.
The following table sets forth certain operating statistics for the Syncrude operations:
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
Total mined overburden (1) millions of cubic yards | 132.2 | 128.2 | 97.1 | 100.3 | 109.2 | |||||||||||||||
Mined overburden to oil sands ratio (1) | 1.06 | 1.18 | 1.02 | 0.94 | 1.15 | |||||||||||||||
Oil sands mined millions of tons | 221.0 | 195.5 | 168.0 | 188.0 | 168.0 | |||||||||||||||
Average bitumen grade (weight percent) | 11.6 | 11.4 | 11.1 | 11.1 | 11.0 | |||||||||||||||
Crude bitumen in mined oil sands millions of tons | 25.6 | 22.2 | 18.6 | 20.9 | 18.5 | |||||||||||||||
Average extraction recovery (percent) | 91.8 | 90.3 | 89.1 | 87.3 | 88.6 | |||||||||||||||
Crude bitumen production (2) millions of barrels | 132.5 | 111.6 | 94.2 | 103.3 | 92.3 | |||||||||||||||
Average upgrading yield (percent) | 84.3 | 84.9 | 85.3 | 85.5 | 86.0 | |||||||||||||||
Gross synthetic crude oil produced millions of barrels | 113.0 | 95.5 | 79.3 | 88.4 | 78.4 | |||||||||||||||
Company’s net share (3) millions of barrels | 23.7 | 21.3 | 19.3 | 21.6 | 19.1 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
Total mined overburden(1) millions of cubic yards | 165.3 | 132.2 | 128.2 | 97.1 | 100.3 | |||||
Mined overburden to oil sands ratio(1) | 1.35 | 1.06 | 1.18 | 1.02 | 0.94 | |||||
Oil sands mined millions of tons | 216.4 | 221.0 | 195.5 | 168.0 | 188.0 | |||||
Average bitumen grade(weight percent) | 11.1 | 11.6 | 11.4 | 11.1 | 11.1 | |||||
Crude bitumen in mined oil sands millions of tons | 24.0 | 25.6 | 22.2 | 18.6 | 20.9 | |||||
Average extraction recovery(percent) | 90.3 | 91.8 | 90.3 | 89.1 | 87.3 | |||||
Crude bitumen production(2) millions of barrels | 122.5 | 132.5 | 111.6 | 94.2 | 103.3 | |||||
Average upgrading yield(percent) | 85.9 | 84.3 | 84.9 | 85.3 | 85.5 | |||||
Gross synthetic crude oil produced millions of barrels | 107.6 | 113.0 | 95.5 | 79.3 | 88.4 | |||||
Company’s net share(3) millions of barrels | 22.6 | 23.7 | 21.3 | 19.3 | 21.6 |
(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 company’s 25 percent interest in production, less applicable royalties payable to the Province of Alberta. |
Kearl Project
The company holds a 10070.96 percent participating interest in approximately 33,400 acres of surface mineable oil sands which forms part of the Kearl project in the Athabasca region of northern Alberta. The company, as operator, filed a regulatory application in July 2005 with the Alberta Energy and Utilities Board for the development of the Kearl oil sands asproject, a joint projectventure with ExxonMobil Canada.Canada Properties, a subsidiary of Exxon Mobil Corporation, established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen. The Kearl project is located approximately 40
miles north of Fort McMurray, Alberta Energy and Utilities Boardnortheast of Syncrude Lease 31 (see map). The location is currently accessible by an existing road.
Kearl will be developed in three phases. Bitumen will be extracted from oil sands produced from open-pit mining operations, and processed through a bitumen extraction and froth treatment plant. The product, a heavy oil blend of bitumen and diluent, will be shipped via pipelines for distribution to North American markets. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation to market by pipeline.
The Kearl project received approvals from the Province of Alberta in 2007 and the Government of Canada gave conditional regulatory approval in February 20072008. The Province of Alberta issued an operating and construction license in 2008, which permits the project to mine oil sands and produce bitumen from approved development areas on oil sands leases. Kearl is comprised of six oil sands leases covering about 48,000 acres in the Athabasca oil sands deposit. The leases, which are issued by the Province of Alberta, are automatically renewable as long as the oil sands operations are ongoing or the leases are part of an approved development plan. The leases involved in the first phase of the project are 6, 87 and 88A (which contain proven reserves) and 31A, 36, and 88B (which do not currently contain proven reserves). There were no known previous commercial operations on these leases.
Production from the first phase is expected to average approximately 110,000 barrels of bitumen a day, before royalties, of which the company’s share would be about 78,000 barrels a day. About $500 million has been spent on the first phase. Activities in 2008 focused on engineering work to define the project design and execution plan. Other activities in 2008 also included access road construction, site preparation and earthworks. Significant progress has been made in transportation system agreements.
Kearl will be subject to the company’s proposed project, followingAlberta generic oil sands royalty regime, which was modified in 2007 and will take effect in 2009. Royalty rates will be based upon a joint federalsliding scale, determined by the price of crude oil.
Operations at Kearl will involve three main processes: open-pit mining, extraction of crude bitumen and provincial review.diluent blending. The company, with an approximate 70 percent interest, continues to progressopen-pit mining will utilize truck, shovel and hydrotransport systems. The extraction separates crude bitumen from sand through a phased development offroth processing plant. Electricity will be provided initially through the project.
Other Oil Sands Activity
The company is continuing to evaluate about 69,000 net acres of other undeveloped oil sands acreage.
8
At December 31, 20072008 and 2006,2007, the company held the following oil and gas rights, and heavy oil and oil sands leases:
Acres | ||||||||||||||||||||||||
Developed | Undeveloped | Total | ||||||||||||||||||||||
2007 | 2006 | 2007 | 2006 | 2007 | 2006 | |||||||||||||||||||
Western Provinces | (thousands) | |||||||||||||||||||||||
Conventional – | ||||||||||||||||||||||||
Gross (1) | 2,529 | 2,550 | 371 | 382 | 2,900 | 2,932 | ||||||||||||||||||
Net (2) | 995 | 1,006 | 223 | 235 | 1,218 | 1,241 | ||||||||||||||||||
Heavy Oil – | ||||||||||||||||||||||||
Gross (1) | 102 | 102 | 429 | 429 | 531 | 531 | ||||||||||||||||||
Net (2) | 102 | 102 | 258 | 258 | 360 | 360 | ||||||||||||||||||
Oil Sands – | ||||||||||||||||||||||||
Gross (1) | 116 | 116 | 293 | 294 | 409 | 410 | ||||||||||||||||||
Net (2) | 29 | 29 | 134 | 134 | 163 | 163 | ||||||||||||||||||
Canada Lands (3): | ||||||||||||||||||||||||
Conventional – | ||||||||||||||||||||||||
Gross (1) | 78 | 78 | 1,302 | 794 | 1,380 | 872 | ||||||||||||||||||
Net (2) | 8 | 8 | 496 | 242 | 504 | 250 | ||||||||||||||||||
Atlantic Offshore | ||||||||||||||||||||||||
Conventional – | ||||||||||||||||||||||||
Gross (1) | 65 | 42 | 6,343 | 6,425 | 6,408 | 6,467 | ||||||||||||||||||
Net (2) | 6 | 4 | 1,513 | 1,524 | 1,519 | 1,528 | ||||||||||||||||||
Total (4): | ||||||||||||||||||||||||
Gross (1) | 2,890 | 2,888 | 8,738 | 8,324 | 11,628 | 11,212 | ||||||||||||||||||
Net (2) | 1,140 | 1,149 | 2,624 | 2,393 | 3,764 | 3,542 |
Acres (1) | ||||||||||||
Developed | Undeveloped | Total | ||||||||||
2008 | 2007 | 2008 | 2007 | 2008 | 2007 | |||||||
Western Provinces | (thousands) | |||||||||||
Conventional – | ||||||||||||
Gross(2) | 2,566 | 2,529 | 435 | 371 | 3,001 | 2,900 | ||||||
Net(3) | 1,004 | 995 | 251 | 223 | 1,255 | 1,218 | ||||||
Heavy Oil – | ||||||||||||
Gross(2) | 103 | 102 | 434 | 429 | 537 | 531 | ||||||
Net(3) | 103 | 102 | 261 | 258 | 364 | 360 | ||||||
Oil Sands – | ||||||||||||
Gross(2) | 114 | 116 | 315 | 293 | 429 | 409 | ||||||
Net(3) | 29 | 29 | 137 | 134 | 166 | 163 | ||||||
Canada Lands(4): | ||||||||||||
Conventional – | ||||||||||||
Gross(2) | 37 | 78 | 1,343 | 1,302 | 1,380 | 1,380 | ||||||
Net(3) | 5 | 8 | 499 | 496 | 504 | 504 | ||||||
Atlantic Offshore | ||||||||||||
Conventional – | ||||||||||||
Gross(2) | 65 | 65 | 6,012 | 6,343 | 6,077 | 6,408 | ||||||
Net(3) | 6 | 6 | 1,308 | 1,513 | 1,314 | 1,519 | ||||||
Total(5): | ||||||||||||
Gross(2) | 2,885 | 2,890 | 8,539 | 8,738 | 11,424 | 11,628 | ||||||
Net(3) | 1,147 | 1,140 | 2,456 | 2,624 | 3,603 | 3,764 |
(1) | Beginning in 2008, the company adopted the Alberta government standard for converting from hectares to acres for Alberta Crown lands. |
(2) | Gross acres include the interests of others. |
(3) | Net acres exclude the interests of others. |
(4) | Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and other Northwest Territories, Nunavut and Yukon regions. |
(5) | Certain land holdings are subject to modification under agreements whereby others may earn interests in the company’s 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). |
The company has been involved in the exploration for and development of petroleum and natural gas in the Western Provinces, in the Canada Lands and in the Atlantic Offshore.
The 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 endedending December 31, 2007.
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
Western and Atlantic Provinces: | ||||||||||||||||||||
Conventional | ||||||||||||||||||||
Exploratory – | ||||||||||||||||||||
Oil | – | – | – | – | – | |||||||||||||||
Gas | – | 1 | – | 2 | 3 | |||||||||||||||
Dry Holes | – | – | – | 1 | 1 | |||||||||||||||
Development – | ||||||||||||||||||||
Oil | – | – | 2 | 3 | 4 | |||||||||||||||
Gas | 183 | 192 | 155 | 207 | 89 | |||||||||||||||
Dry Holes | – | 1 | 1 | 1 | 3 | |||||||||||||||
Heavy Oil (Cold Lake and other) | ||||||||||||||||||||
Development – | ||||||||||||||||||||
Oil | 188 | 174 | 87 | 218 | 118 | |||||||||||||||
Total | 371 | 368 | 245 | 432 | 218 | |||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
Western and Atlantic Provinces: | ||||||||||
Conventional | ||||||||||
Exploratory – | ||||||||||
Oil | – | – | – | – | – | |||||
Gas | – | – | 1 | – | 2 | |||||
Dry Holes | – | – | – | – | 1 | |||||
Development – | ||||||||||
Oil | 1 | – | – | 2 | 3 | |||||
Gas | 146 | 183 | 192 | 155 | 207 | |||||
Dry Holes | – | – | 1 | 1 | 1 | |||||
Heavy Oil (Cold Lake and other) | ||||||||||
Development – | ||||||||||
Oil | 70 | 188 | 174 | 87 | 218 | |||||
Total | 217 | 371 | 368 | 245 | 432 |
Weather related delays in 2005 resulted in a reduction in the number of wells drilled in the ongoing shallow gas development program. In 2007, 188 heavy oil development wells were drilled to add new productive capacity from undeveloped areas of existing phases at Cold Lake. In addition, 183 gas development wells were drilled in 2007 adding productivity primarily in the shallow gas area. IncreasedIn 2008, 70 heavy oil development wells were drilled to add new productive capacity from undeveloped areas of existing phases at Cold Lake. In addition, 146 gas development wells were drilled in 2008 adding productivity primarily in the shallow gas area. Additionally, one oil development drilling accounted for the increase in gas
9
At December 31, 2007,2008, the company was participating in the drilling of 183295 gross (123(172 net) exploratory and development wells.
Western Provinces
In 2007,2008, the company had a working interest in 489526 gross (371(338 net) development wells.
Beaufort Sea/Mackenzie Delta
Substantial quantities of gas have been found by the company and others in the Beaufort Sea/Mackenzie Delta.
In 1999, the company and three other companies entered into an agreement to study the feasibility of developing Mackenzie Delta gas, anchored by three large onshore natural gas fields. The company retains a 100 percent interest in the largest of these fields.
The commercial viability of these natural gas resources, and the pipeline required to transport this natural gas to markets, is dependent on a number of factors. These factors include natural gas markets, support from northern parties, regulatory approvals, environmental considerations, pipeline participation, fiscal framework, and the cost of constructing, operating and abandoning the field production and pipeline facilities.
In October 2004, the company and its co-venturers filed regulatory applications and environmental impact statements for the project with the National Energy Board (“NEB”) and other boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. All the scheduled public hearings by the Joint Review Panel (“JRP”) and the NEB were concluded in late 2007. The regulatory process continues with a JRP report expected in 2008late 2009 followed by an NEB decision in early 2009.
In 2007, the company acquired a 50 percent interest in an exploration licence for about 507,000 gross acres in the Beaufort Sea. As part of the evaluation, a 3-D seismic program is being planned.
Other land holdings include majority interests in 20, and minority interests in six Significant Discovery Licences granted by the Government of Canada, as the result of previous oil and gas discoveries, all of which are managed by the company, and majority interests in two, and minority interests in 1617, 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.
In 2008, one exploration licence for about 52,000 gross acres acquired in 1999 in the Sable Island area. One exploratory well was completed on this licence without commercial success. In 2007, one exploration licencearea, in which the company had a 20 percent interest, for about 58,00052,000 gross acres in the Sable Island area was allowed to expire.
In early 2004, the company acquired a 25 percent interest in eight deep water exploration licences offshore Newfoundland in the Orphan Basin for about 5,251,000 gross acres. In February 2005, the company reduced its interest to 15 percent through an agreement with another company. The company’s share of proposed exploration spending is about $100 million with a minimum commitment of about $25 million. In 2004 and 2005, the company participated in 3-D seismic surveys in this area. Drilling of an exploration well was concluded in early 2007. In early 2009, one exploration licence in its entirety and most of a second exploration licence, for about 1,069,000 gross acres, expired. The remaining exploration licences were consolidated into two exploration licences, for a total of about 4,200,000 gross acres. The company’s share of proposed exploration spending is about $60 million with a minimum commitment of about $15 million. Additional drilling is planned.
The company retains 100 percent interest in a single exploration licence for about 474,000 gross acres in the Laurentian basin area offshore Newfoundland and Labrador.
10
The company purchases domestic crude oil at freely negotiated prices from a number of sources. Domestic purchases of crude oil are generally made under renewable contracts with 30 to 60 day cancellation terms.
Crude oil from foreign sources is purchased by the company at market prices mainly through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil throughout the world).
The company owns and operates four refineries. Two of these, the Sarnia refinery and the Strathcona refinery, have lubricating oil production facilities. The Strathcona refinery processes Canadian crude oil, and the Dartmouth, Sarnia and Nanticoke refineries process a combination of Canadian and foreign crude oil. In addition to crude oil, the company purchases finished products to supplement its refinery production.
In 2007,2008, capital expenditures of about $110$150 million were made at the company’s refineries. About 5060 percent of those expenditures were on environmental and safety initiatives with the remaining expenditures being primarily on capacity and efficiency improvements.
The approximate average daily volumes of refinery throughput during the five years ended December 31, 2007,2008, and the daily rated capacities of the refineries at December 31, 20022003 and 2007,2008, were as follows:
Average Daily Volumes of | Daily Rated | |||||||||||||||||||||||||||
Refinery Throughput (1) | Capacities at | |||||||||||||||||||||||||||
Year Ended December 31 | December 31 (2) | |||||||||||||||||||||||||||
2007 | 2006 | 2005 | 2004 | 2003 | 2007 | 2002 | ||||||||||||||||||||||
(thousands of barrels) | ||||||||||||||||||||||||||||
Strathcona, Alberta | 170 | 160 | 174 | 170 | 174 | 187 | 184 | |||||||||||||||||||||
Sarnia, Ontario | 103 | 111 | 106 | 108 | 92 | 121 | 121 | |||||||||||||||||||||
Dartmouth, Nova Scotia | 69 | 77 | 79 | 80 | 82 | 82 | 82 | |||||||||||||||||||||
Nanticoke, Ontario | 100 | 94 | 108 | 109 | 102 | 112 | 112 | |||||||||||||||||||||
Total | 442 | 442 | 466 | 467 | 450 | 502 | 499 | |||||||||||||||||||||
Average Daily Volumes of Refinery Throughput (1) Year Ended December 31 | Daily Rated Capacities at December 31 (2) | |||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | 2008 | 2003 | ||||||||||
(thousands of barrels) | ||||||||||||||||
Strathcona, Alberta | 155 | 170 | 160 | 174 | 170 | 187 | 187 | |||||||||
Sarnia, Ontario | 108 | 103 | 111 | 106 | 108 | 121 | 121 | |||||||||
Dartmouth, Nova Scotia | 76 | 69 | 77 | 79 | 80 | 82 | 82 | |||||||||
Nanticoke, Ontario | 107 | 100 | 94 | 108 | 109 | 112 | 112 | |||||||||
Total | 446 | 442 | 442 | 466 | 467 | 502 | 502 |
(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 8889 percent of capacity in 2007, the same as2008, one percent higher than the previous year. Production gains from reliability improvements through the year but lower than 2005 duewere partially offset by the impact of declining economic conditions that did not support running the refineries to planned and unplanned downtime of crude processing facilities.
The company maintains a nation-wide distribution system, including 2725 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 threetwo crude oil pipeline companies.
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 retail service stations. On average during the year, there were about 1,9301,900 sites, of which about 600570 were company owned or leased, but none of which were company operated. The company continues to improve its Esso retail 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 10090 sales facilities. Heating oil is provided through authorized dealers, as well as through twoa company operated Home Comfort facilities infacility serving the Montreal urban markets.market. The company also sells petroleum products to large industrial and commercial accounts as well as to other refiners and marketers.
11
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(thousands of cubic metres a day) | ||||||||||||||||||||
Gasolines | 33.1 | 32.7 | 33.4 | 33.2 | 33.0 | |||||||||||||||
Heating, Diesel and Jet Fuels | 26.0 | 26.4 | 26.9 | 27.3 | 26.2 | |||||||||||||||
Heavy Fuel Oils | 5.2 | 5.1 | 6.0 | 5.9 | 5.4 | |||||||||||||||
Lube Oils and Other Products | 6.9 | 7.7 | 7.6 | 7.0 | 5.8 | |||||||||||||||
Net petroleum product sales | 71.2 | 71.9 | 73.9 | 73.4 | 70.4 | |||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(thousands of barrels a day) | ||||||||||
Gasolines | 204 | 208 | 206 | 210 | 209 | |||||
Heating, Diesel and Jet Fuels | 157 | 164 | 166 | 169 | 172 | |||||
Heavy Fuel Oils | 30 | 33 | 32 | 38 | 37 | |||||
Lube Oils and Other Products | 47 | 43 | 49 | 48 | 44 | |||||
Net petroleum product sales | 438 | 448 | 453 | 465 | 462 |
The total domestic sales of petroleum products, as a percentage of total sales of petroleum products during the five years ended December 31, 2007,2008, were as follows:
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
94.8 | % | 95.1 | % | 95.3 | % | 93.0 | % | 93.3 | % |
2008 | 2007 | 2006 | 2005 | 2004 | |||||||||||
93.0 | % | 94.8 | % | 95.1 | % | 95.3 | % | 93.0 | % |
The company continues to evaluate and adjust its Esso retail service station and distribution system to increase productivity and efficiency. During 2007,2008, the company closed or debranded about 8085 Esso retail service stations, about 3020 of which were company owned, and added about 5045 sites. The company’s average annual throughput in 20072008 per Esso retail service station was 3.824 thousand barrels (3.8 million litres, an increase of about 0.2 million litres from 2006.litres) the same as 2007. Average throughput per company owned or leased Esso retail service station was 6.542 thousand barrels (6.7 million litreslitres) in 2007,2008, an increase of about 0.4one thousand barrels (0.2 million litreslitres) from 2006.
The company’s chemicalsChemical 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 company’s petroleum refinery. There is also a heptene and octene plant located in Dartmouth, Nova Scotia.
The company’s average daily sales of petrochemicals during the five years ended December 31, 2007,2008, were as follows:
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(thousands of tonnes a day) | ||||||||||||||||||||
Petrochemicals | 3.1 | 3.0 | 3.0 | 3.3 | 3.3 |
In 2007,2008, the company’s research expenditures in Canada, before deduction of investment tax credits, were $83$117 million, as compared with $83 million in 2007, and $56 million in 2006, and $50 million in 2005.2006. Those funds were used mainly for developing improved heavy oil and oil sands recovery methods and better lubricants.
A research facility to support the company’s natural resourcesupstream operations is located in Calgary, Alberta. Research in these laboratories is aimed at developing new technology for the production and processing of crude bitumen. About 40 people were involved in this type of research in 2007.2008. 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 and advanced technical support is mainly conducted on the development and improvementsupport of lubricants and fuels. About 115105 people were employed in this type of research and advanced technical support at the end of 2007.2008. Also in Sarnia, there are about 10 people engaged in new product development for the company’s and Exxon Mobil Corporation’s polyethylene injection and rotational molding businesses.
The company has scientific research agreements with affiliates of Exxon Mobil Corporation which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licensing of patents and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties.
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 and other expenditures of about $1.0$2.6 billion on environmental protection and facilities. The environmental expenditures over the past five years primarily reflect spending on two major projects. One project completed in
12
At December 31, 2007,2008, the company employed full-time approximately 4,8004,850 persons, compared with about 4,800, at the end of 2007 and 4,900 at the end of 2006 and 5,100 at the end of 2005.2006. About 10nine percent of the company’s employees are members of unions. The company continues to maintain a broad range of benefits, including health, dental, disability and survivor benefits, vacation, savings plan and pension plan.
The Canadian petroleum, natural gas and chemical industries are highly competitive. Competition exists in the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities and the refining, distribution and marketing of petroleum products and chemicals. The petroleum industry also competes with other industries in supplying energy, fuel and other needs of consumers.
Petroleum and Natural Gas Rights
Most of the company’s 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 holder’s interest in the land and may become entitled to produce petroleum or natural gas from the licenced land.
Crude Oil
Production
The maximum allowable gross production of crude oil from wells in Canada is subject to limitation by various regulatory authorities on the basis of engineering and conservation principles.
Exports
Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including crude bitumen) require the prior approval of the NEB and the Government of Canada.
Natural Gas
Production
The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves, and did not have a significant impact on 20072008 gas production rates. As well, these limitations do not apply to gas fields where there are no associated oil reserves.
Exports
The Government of Canada has the authority to regulate the export price for natural gas and has a gas export pricing policy which accommodates export prices for natural gas negotiated between Canadian exporters and U.S. importers.
Exports of natural gas from Canada require approval by the NEB and the Government of Canada. The Government of Canada allows the export of natural gas by NEB order without volume limitation for terms not exceeding 24 months.
Royalties
The Government of Canada and the provinces in which the company produces crude oil and natural gas impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights.
Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed by the producing provinces on crude oil, vary depending on well production volumes, selling prices, recovery methods and the date of initial production. Royalties imposed by the producing provinces on natural gas
13
Investment Canada Act
The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. The acquisition of natural resource properties may, in certain circumstances, be considered to be a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval.
The Act also requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s 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’s website www.imperialoil.ca contains a variety of corporate and investor information which is available free of charge, including the company’s 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.
Volatility of Oil and Natural Gas Prices
The company’s 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 company’s operations, financial condition, proven reserves and the amount spent to develop oil and natural gas reserves.
A significant portion of the company’s production is heavy oil. The market prices for heavy oil differ from the established market indices for light and medium grades of oil principally due to the higher transportation and refining costs associated with heavy oil and limited refining capacity capable of processing heavy oil. As a result, the price received for heavy oil is generally lower than the price for medium and light oil. Future differentials are uncertain and increases in the heavy oil differentials could have a material adverse effect on the company’s business.
The company does not use derivative marketsinvestments to hedge or sell forward any partspeculate on the future direction 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 company’s competitors include major integrated oil and gas companies and numerous other independent oil and gas companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to customers.
Competitive forces may result in shortages of prospects to drill, services to carry out exploration, development or operating activities and infrastructure to produce and transport production. It may also result in an oversupply of crude oil, natural gas, petroleum products and chemicals. Each of these factors could have a negative impact on costs and prices and, therefore, the company’s financial results.
Environmental Risks
All phases of the upstream, downstreamUpstream, Downstream and chemicalsChemical 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 company’s 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
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Climate Change
In April 2007, the Government of Canada announced its intent to introduce a set of regulations to limit emissions of greenhouse gas and air pollutants from major industrial facilities in Canada, beginning in 2010, although the details of the regulations have not been finalized. Consequently, attempts to assess the impact on the company are premature. The company will continue to monitor the development of legal requirements in this area.
In the Province of Alberta, regulations governing greenhouse gas emissions from large industrial facilities came into effect July 1, 2007. TheCompliance costs were not material in 2007 and 2008, and the company does not expect ongoing compliance costs to have a material adverse effect on the company’s operations or financial condition.
The recently enacted U.S. Energy Independence and Security Act of 2007 precludes agencies of the U.S. federal government from procuring motive fuels from non-conventional petroleum sources that have lifecycle greenhouse gas emissions greater than equivalent conventional fuel. This may have implications for the company’s marketing in the United States of some heavy oil and oil sands production, but the impact cannot be determined at this time.
Further federal or provincial legislation or regulation controlling greenhouse gas emissions could occur and result in increased capital expenditures and operating costs, which could have a material adverse effect on the company’s financial condition or results of operations, but any potential impact cannot be estimated at this time.
Other Regulatory Risk
The company is subject to a wide range of legislation and regulation governing its operations over which it has no control. Changes may affect every aspect of the company’s operations and financial performance.
Need to Replace Reserves
The company’s future conventional oil, heavy oil and natural gas reserves and production, and therefore cash flows, are highly dependent upon the company’s success in exploiting its current reserve base and acquiring or discovering additional reserves. Without additions to the company’s 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 company’s 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 company’s insurance may not provide adequate coverage in certain unforeseen circumstances.
Uncertainty of Reserve Estimates
There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the company’s 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.
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Project Factors
The company’s results depend on its ability to develop and operate major projects and facilities as planned. The company’s 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 company’s 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
During 2008, credit markets tightened, and 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, Kearl project and oil and gas producing activities, reference is made to Item 8 of this report.
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Item 5. | Market for Registrant’s 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 5five percent for certain individuals), which are applicable to dividends paid by U.S. domestic corporations and qualified foreign corporations.
There is no Canadian tax on gains from selling shares or debt instruments owned by nonresidents not carrying on business in Canada.
Quarterly Financial and Stock Trading Data
2007 | 2006 | |||||||||||||||||||||||||||||||
three months ended | three months ended | |||||||||||||||||||||||||||||||
Mar. 31 | Jun. 30 | Sep. 30 | Dec. 31 | Mar. 31 | Jun. 30 | Sep. 30 | Dec. 31 | |||||||||||||||||||||||||
Financial data | (millions of dollars) | (millions of dollars) | ||||||||||||||||||||||||||||||
Total revenues and other income | 5,934 | 6,339 | 6,430 | 6,740 | 5,818 | 6,688 | 6,651 | 5,631 | ||||||||||||||||||||||||
Total expenses | 4,819 | 5,319 | 5,240 | 5,686 | 4,928 | 5,604 | 5,421 | 4,735 | ||||||||||||||||||||||||
Income before income taxes | 1,115 | 1,020 | 1,190 | 1,054 | 890 | 1,084 | 1,230 | 896 | ||||||||||||||||||||||||
Income taxes | (341 | ) | (308 | ) | (374 | ) | (168 | ) | (299) | (247) | (408) | (102) | ||||||||||||||||||||
Net income | 774 | 712 | 816 | 886 | 591 | 837 | 822 | 794 | ||||||||||||||||||||||||
Per-share information(a) | (dollars) | (dollars) | ||||||||||||||||||||||||||||||
Net earnings – basic | 0.82 | 0.76 | 0.88 | 0.97 | 0.60 | 0.85 | 0.84 | 0.83 | ||||||||||||||||||||||||
Net earnings – diluted | 0.81 | 0.76 | 0.88 | 0.96 | 0.59 | 0.85 | 0.84 | 0.83 | ||||||||||||||||||||||||
Dividends (declared quarterly) | 0.08 | 0.09 | 0.09 | 0.09 | 0.08 | 0.08 | 0.08 | 0.08 | ||||||||||||||||||||||||
Share prices(a) | (dollars) | (dollars) | ||||||||||||||||||||||||||||||
Toronto Stock Exchange | ||||||||||||||||||||||||||||||||
High | 43.75 | 54.70 | 51.90 | 56.26 | 42.28 | 43.33 | 45.20 | 44.80 | ||||||||||||||||||||||||
Low | 37.40 | 41.77 | 40.86 | 45.57 | 35.36 | 36.18 | 35.33 | 34.31 | ||||||||||||||||||||||||
Close | 42.80 | 49.59 | 49.29 | 54.26 | 41.91 | 40.78 | 37.47 | 42.93 | ||||||||||||||||||||||||
American Stock Exchange | ($U.S.) | ($U.S.) | ||||||||||||||||||||||||||||||
High | 38.29 | 50.35 | 50.95 | 61.48 | 36.67 | 39.64 | 40.38 | 38.93 | ||||||||||||||||||||||||
Low | 31.87 | 36.90 | 37.99 | 46.43 | 30.54 | 32.50 | 31.64 | 29.99 | ||||||||||||||||||||||||
Close | 37.12 | 46.34 | 49.56 | 54.78 | 35.85 | 36.50 | 33.55 | 36.83 |
2008 Three months ended | 2007 Three months ended | |||||||||||||||
Mar. 31 | Jun. 30 | Sep. 30 | Dec. 31 | Mar. 31 | Jun. 30 | Sep. 30 | Dec. 31 | |||||||||
Financial data | (millions of dollars) | (millions of dollars) | ||||||||||||||
Total revenues and other income | 7,263 | 8,859 | 9,515 | 5,942 | 5,934 | 6,339 | 6,430 | 6,740 | ||||||||
Total expenses | 6,298 | 7,276 | 7,558 | 5,171 | 4,819 | 5,319 | 5,240 | 5,686 | ||||||||
Income before income taxes | 965 | 1,583 | 1,957 | 771 | 1,115 | 1,020 | 1,190 | 1,054 | ||||||||
Income taxes | 284 | 435 | 568 | 111 | (341) | (308) | (374) | (168) | ||||||||
Net income | 681 | 1,148 | 1,389 | 660 | 774 | 712 | 816 | 886 | ||||||||
Per-share information | (dollars) | (dollars) | ||||||||||||||
Net earnings – basic | 0.76 | 1.29 | 1.57 | 0.77 | 0.82 | 0.76 | 0.88 | 0.97 | ||||||||
Net earnings – diluted | 0.75 | 1.28 | 1.57 | 0.76 | 0.81 | 0.76 | 0.88 | 0.96 | ||||||||
Dividends (declared quarterly) | 0.09 | 0.09 | 0.10 | 0.10 | 0.08 | 0.09 | 0.09 | 0.09 | ||||||||
Share prices(1) | (dollars) | (dollars) | ||||||||||||||
Toronto Stock Exchange | ||||||||||||||||
High | 58.09 | 62.54 | 57.80 | 46.43 | 43.75 | 54.70 | 51.90 | 56.26 | ||||||||
Low | 45.80 | 52.41 | 41.60 | 28.79 | 37.40 | 41.77 | 40.86 | 45.57 | ||||||||
Close | 53.80 | 56.16 | 45.58 | 40.99 | 42.80 | 49.59 | 49.29 | 54.62 | ||||||||
NYSE Alternext | ($U.S.) | ($U.S.) | ||||||||||||||
High | 58.91 | 63.08 | 56.89 | 43.66 | 38.29 | 50.35 | 50.95 | 61.48 | ||||||||
Low | 44.30 | 51.24 | 40.00 | 23.84 | 31.87 | 36.90 | 37.99 | 46.43 | ||||||||
Close | 52.26 | 55.07 | 42.60 | 33.72 | 37.12 | 46.34 | 49.56 | 54.78 |
The company’s shares are listed on the |
As of February 14, 200813, 2009 there were 13,17513,242 holders of record of common shares of the company.
During the period October 1, 20072008 to December 31, 2007,2008, the company issued 164,80533,600 common shares to employees or former employees outside the U.S.A. for $15.50 per share (following the three-for-one share split) as a result ofupon 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. whichoptions. These issuances were not registered under theSecurities Act in reliance on Regulation S thereunder.
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Period | (a) Total number | (b) Average price | (c) Total number of | (d) Maximum number | ||||||||||||||||||
of shares | paid per share | shares purchased as | (or approximate dollar value) | |||||||||||||||||||
(or units) | (or unit) | part of publicly | of shares that may yet be | |||||||||||||||||||
purchased | announced plans or | purchased under the plans or | ||||||||||||||||||||
programs | programs | |||||||||||||||||||||
October 2007 (October 1 - October 31) | 1,498,890 | $ | 48.00 | 1,498,890 | 30,445,586 | |||||||||||||||||
November 2007 (November 1 - November 30) | 6,656,699 | $ | 51.45 | 6,656,699 | 23,737,240 | |||||||||||||||||
December 2007 (December 1 - December 31) | 2,971,920 | $ | 51.70 | 2,971,920 | 20,714,852 | |||||||||||||||||
Period | (a) Total number of shares purchased | (b) Average price paid per share ($) | (c) Total number of shares purchased as part of publicly announced plans or programs | (d) Maximum number (or approximate dollar value) of shares that may yet be purchased under the plans or programs | ||||
October 2008 (October 1 - October 31) | 1,365,130 | 40.95 | 1,365,130 | 28,973,635 | ||||
November 2008 (November 1 - November 30) | 5,380,001 | 37.94 | 5,380,001 | 23,511,797 | ||||
December 2008 (December 1 - December 31) | 3,559,812 | 40.13 | 3,559,812 | 19,875,171 |
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Total operating revenues(a) | 25,069 | 24,505 | 27,797 | 22,408 | 19,094 | |||||||||||||||
Net income | 3,188 | 3,044 | 2,600 | 2,052 | 1,705 | |||||||||||||||
Total assets | 16,287 | 16,141 | 15,582 | 14,027 | 12,337 | |||||||||||||||
Long term debt | 38 | 359 | 863 | 367 | 859 | |||||||||||||||
Other long term obligations | 1,914 | 1,683 | 1,728 | 1,525 | 1,314 | |||||||||||||||
(dollars) | ||||||||||||||||||||
Net income/share – basic(b) | 3.43 | 3.12 | 2.54 | 1.92 | 1.53 | |||||||||||||||
Net income/share – diluted(b) | 3.41 | 3.11 | 2.53 | 1.91 | 1.53 | |||||||||||||||
Cash dividends/share(b) | 0.35 | 0.32 | 0.31 | 0.29 | 0.29 |
Item 6. | Selected Financial Data. |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(millions of dollars) | ||||||||||
Operating revenues(1) | 31,240 | 25,069 | 24,505 | 27,797 | 22,408 | |||||
Net income | 3,878 | 3,188 | 3,044 | 2,600 | 2,052 | |||||
Total assets at year end | 17,035 | 16,287 | 16,141 | 15,582 | 14,027 | |||||
Long term debt at year end | 34 | 38 | 359 | 863 | 367 | |||||
Total debt at year end | 143 | 146 | 1,437 | 1,439 | 1,443 | |||||
Other long term obligations at year end | 2,298 | 1,914 | 1,683 | 1,728 | 1,525 | |||||
(dollars) | ||||||||||
Net income/share – basic(2) | 4.39 | 3.43 | 3.12 | 2.54 | 1.92 | |||||
Net income/share – diluted(2) | 4.36 | 3.41 | 3.11 | 2.53 | 1.91 | |||||
Cash dividends/share(2) | 0.38 | 0.35 | 0.32 | 0.31 | 0.29 |
Operating revenues include $4,894 million for 2005 and $3,584 million for 2004 |
(2) | Adjusted to reflect the May 2006 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. | Management’s Discussion and Analysis of Financial Condition and Results of Operations. |
Overview
The following discussion and analysis of Imperial’s 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 company’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The company’s 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, Imperial’s investment decisions are based on its long-term business outlook, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives, in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.
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Long-term business outlook
Economic and population growth are expected to remain the primary drivers of energy demand, globally and in North America. The company expects the global economy to grow at an average rate of about three percent per year through 2030. The combination of population and economic growth should lead to an increase in demand for
primary energy at an average rate of 1.31.2 percent annually. The vast majority of this increase is expected to occur in developing countries.
Oil, gas and coal are expected to remain the predominant energy sources with approximately an 80 percent share of total energy. Oil and gas alone are expected to maintain close to a 60 percent share.
Over the same period, the Canadian economy is expected to grow at an average rate of about two percent per year, and Canadian demand for energy at less thanabout half of one percent per year. Oil and gas are expected to continue to supply about two-thirds of Canadian energy demand. It is expected that Canada will also be a growing supplier of energy to U.S. markets through this period.
Oil products are the transportation fuel of choice for the world’s fleet of cars, trucks, trains, ships and airplanes. Primarily because of increased demand in developing countries, oil consumption willis expected to increase by about 3525 percent or about 30over 20 million barrels a day by 2030. Canada’s oil resources, of heavy oil and oil sandssecond only to Saudi Arabia, represent an important potential additional source of supply.
Natural gas is expected to be a major primary energy source globally, capturing about 3035 percent of all incremental energy growth and approaching one-quarter of global energy supplies. Natural gas production from conventional sources in 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 Canada’s frontier areas.
Upstream
Imperial produces crude oil and natural gas for sale into large North American markets. Crude oil and natural gas prices are determined by global and North American markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors, including economic conditions, international political developments and weather. In the past, crude oil and natural gas prices have been volatile, and the company expects that volatility to continue.
Imperial’s fundamental Upstream business strategies guide our exploration, development, production and gas marketing activities. These strategies include identifying and pursuing all attractive exploration opportunities, investing in projects that deliver superior returns and maximizing profitability of existing oil and gas production. These strategies are underpinned by a relentless focus on operational excellence, commitment to innovative technologies, development of our employees and investment in the communities in which we operate.
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, Imperial’s production is expected to come increasingly from frontier and unconventional sources, particularly heavy oil, oil sands and unconventional natural gas and from Canada’s North, where Imperial has large undeveloped resource opportunities.
Downstream
The downstream industry environment remains very competitive. Refining margins are the difference between what a refinery pays for its raw materials (primarily crude oil) and the wholesale market prices for the range of products produced (primarily gasoline, diesel fuel, heating oil, jet fuel and heavy fuel oil). While refining margins have been strong over the last few years, real inflation adjustedvolatile from year to year, refining margins have declined at a rate of about one percent per year, on average, over the past 20 years.years in inflation adjusted terms. Intense competition in the retail fuels market similarly has driventended to drive down real margins.margins over time. 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.
Imperial’s downstreamDownstream strategies are to provide customers with quality service and products 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 company’s other businesses. Imperial owns and operates four refineries in Canada, with distillation capacity of 502,000 barrels a day and lubricant manufacturing capacity of 9,0008,000 barrels a day.
Imperial’s fuels marketing business includes retail operations across Canada serving customers through more thanabout 1,900 Esso-branded retail service stations, of which about 600570 are company-owned or leased, and wholesale and industrial operations through a network of 2724 primary distribution terminals, as well as a secondary distribution network.
Chemical
The North American petrochemical industry is cyclical. The company’s strategy for its chemicalsChemical business is to reduce costs and maximize value by continuing to increase the integration of its chemicalschemical plants at Sarnia and
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Results of operations
Net income in 20072008 of $3,188$3,878 million or $3.41$4.36 a share on a diluted basis was the best on record, exceeding the previous record achieved in 20062007 of $3,044$3,188 million or $3.11$3.41 a share. Earnings increased primarily due to higher crude oil and natural gas commodity prices, stronger industry refining and marketing margins, favourable refinery operations and higher Syncrude volumes. Gains from asset divestments were also higher in 2007. These factorsprices. Improved upstream realizations were partially offset by lower expected conventional resources volumes, the negative impactimpacts of a stronger Canadian dollar,lower upstream volumes, higher explorationroyalties, higher energy and share-based compensation expensesmaintenance costs and higher tax expense.
Upstream
Net income from natural resources was $2,923 million versus $2,369 million versus $2,376 million in 2006.2007. Earnings benefited from higher overall crude oil and natural gas commodity prices totaling about $325$2,100 million. Their positive impact on earnings was partially offset by lower conventional volumes from expected reservoir decline of about $420 million, and higherlower Syncrude volumes of about $125$135 million and lower cyclical Cold Lake heavy oil production of about $105 million. HigherEarnings were also negatively impacted by higher royalties of about $310 million, higher energy, Syncrude maintenance, and other production costs totaling about $290 million, the absence of favourable effects of tax rate changes of about $170 million and lower gains from asset divestments of about $65 million also contributed to higher earnings. Offsetting these positive factors were lower natural gas, conventional crude oil, and natural gas liquids (NGLs) volumes totaling about $285 million, the negative impact of a stronger Canadian dollar of about $175 million and higher exploration and other operating expenses of about $75$140 million.
Financial statistics
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Net income | 2,369 | 2,376 | 2,008 | 1,517 | 1,174 | |||||||||||||||
Operating revenues | 8,685 | 8,456 | 8,189 | 6,580 | 5,584 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(millions of dollars) | ||||||||||
Net income | 2,923 | 2,369 | 2,376 | 2,008 | 1,517 | |||||
Operating revenues | 11,222 | 8,685 | 8,456 | 8,189 | 6,580 |
World crude oil prices denominatedended in U.S. dollars, were higher in 20072008 much lower than the record levels reached earlier 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 $72declined from a high of $144.22 (U.S.) a barrel in 2007, about 11 percent higher thanJuly to a low of $33.65 (U.S.) in December. For the year, the average price of $65 in 2006 (2005 – $55). However, theBrent crude oil was $96.99 (U.S.) a barrel, up about 34 percent from 2007. The company’s Canadian-dollar realizations foron sales of Canadian conventional crude oil increased tomirrored the same trends as world prices, ending 2008 at a lesser extent becauselevel much lower than the average of a strongerthe year.
Prices for Canadian dollar. Average realizations for conventional crudeheavy oil, duringincluding the year were $71.70 (Cdn) a barrel, an increase of less than five percent from $68.58 in 2006 (2005 – $64.48).
Prices for Canadian natural gas in 20072008 were lowerhigher than in the previous year. The average of 30-day spot prices for natural gas in Alberta was about $7.01$8.61 a thousand cubic feet in 2007,2008, compared with $7.41$7.01 in 2006 (20052007 (2006 – $9.01)$7.41). The company’s average realizations on natural gas sales were $6.95$8.69 a thousand cubic feet, compared with $7.24$6.95 in 2006 (20052007 (2006 – $9.00)$7.24).
Average realizations and prices
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(Canadian dollars) | ||||||||||||||||||||
Conventional crude oil realizations(a barrel) | 71.70 | 68.58 | 64.48 | 48.96 | 40.10 | |||||||||||||||
Natural gas liquids realizations(a barrel) | 47.92 | 40.75 | 40.00 | 33.78 | 32.09 | |||||||||||||||
Natural gas realizations(a thousand cubic feet) | 6.95 | 7.24 | 9.00 | 6.78 | 6.60 | |||||||||||||||
Par crude oil price at Edmonton(a barrel) | 77.67 | 73.75 | 69.86 | 53.26 | 43.93 | |||||||||||||||
Heavy oil price at Hardisty(Bow River, a barrel) | 53.87 | 51.90 | 45.62 | 37.98 | 33.00 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(Canadian dollars) | ||||||||||
Conventional crude oil realizations(a barrel) | 95.76 | 71.70 | 68.58 | 64.48 | 48.96 | |||||
Natural gas liquids realizations(a barrel) | 59.35 | 47.92 | 40.75 | 40.00 | 33.78 | |||||
Natural gas realizations(a thousand cubic feet) | 8.69 | 6.95 | 7.24 | 9.00 | 6.78 | |||||
Par crude oil price at Edmonton(a barrel) | 103.60 | 77.67 | 73.75 | 69.86 | 53.26 | |||||
Heavy oil price at Hardisty(Bow River, a barrel) | 83.91 | 53.87 | 51.90 | 45.62 | 37.98 |
Gross production of heavy oil at the company’s wholly owned facilities at Cold Lake was a record 154,000147,000 barrels a day, surpassing the previous record of 152,000compared with 154,000 barrels in 2006 (20052007 (2006 – 139,000)152,000). IncreasedLower production was due to the cyclic nature of production at Cold Lake and increased volumes from the ongoing development drilling program.
Gross production of synthetic crude oil from the Syncrude oil sands operation, in which the company has a 25 percent interest, was higher during 2007 with increased volumes from the Stage 3 upgrader expansion. Gross production of synthetic crude oil increased to 305,000289,000 barrels a day from 258,000versus 305,000 barrels in 2006 (20052007 (2006 – 214,000)258,000). Lower volumes were primarily the result of planned and unplanned maintenance activities during the year, including work to improve reliability performance. Imperial’s share of average gross production increaseddecreased to 76,00072,000 barrels a day from 65,00076,000 barrels in 2006 (20052007 (2006 – 53,000)65,000).
Gross production of conventional oil decreased to 29,00027,000 barrels a day from 31,00029,000 barrels in 2006 (20052007 (2006 – 38,000)31,000) as a result of natural decline in Western Canadian reservoirs and the impact of divested properties.
20
Gross production of $142 million primarily from thenatural gas liquids (NGLs) available for sale of the company’s interests in several producing properties. Production of the company’s share of these properties averaged about 2,000 oil-equivalent10,000 barrels a day in 2006. In 2006,2008, down from 16,000 barrels in 2007 (2006 – 24,000), mainly due to the gain on divestmentcompletion of assets was approximately $76 million (2005 — $208 million).
Crude oil and NGLs —- production and sales(a)(1)
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||||||||||||||||||||||
gross | net | gross | net | gross | net | gross | net | gross | net | |||||||||||||||||||||||||||||||
(thousands of barrels a day) | ||||||||||||||||||||||||||||||||||||||||
Cold Lake | 154 | 130 | 152 | 127 | 139 | 124 | 126 | 112 | 129 | 116 | ||||||||||||||||||||||||||||||
Syncrude | 76 | 65 | 65 | 58 | 53 | 53 | 60 | 59 | 53 | 52 | ||||||||||||||||||||||||||||||
Conventional crude oil | 29 | 21 | 31 | 23 | 38 | 29 | 43 | 33 | 46 | 35 | ||||||||||||||||||||||||||||||
Total crude oil production | 259 | 216 | 248 | 208 | 230 | 206 | 229 | 204 | 228 | 203 | ||||||||||||||||||||||||||||||
NGLs available for sale | 16 | 12 | 24 | 19 | 31 | 25 | 33 | 26 | 28 | 22 | ||||||||||||||||||||||||||||||
Total crude oil and NGL production | 275 | 228 | 272 | 227 | 261 | 231 | 262 | 230 | 256 | 225 | ||||||||||||||||||||||||||||||
Cold Lake sales, including diluent(b) | 200 | 198 | 183 | 167 | 170 | |||||||||||||||||||||||||||||||||||
NGL sales | 20 | 29 | 39 | 42 | 39 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
gross | net | gross | net | gross | net | gross | net | gross | net | |||||||||||
(thousands of barrels a day) | ||||||||||||||||||||
Cold Lake | 147 | 124 | 154 | 130 | 152 | 127 | 139 | 124 | 126 | 112 | ||||||||||
Syncrude | 72 | 62 | 76 | 65 | 65 | 58 | 53 | 53 | 60 | 59 | ||||||||||
Conventional crude oil | 27 | 19 | 29 | 21 | 31 | 23 | 38 | 29 | 43 | 33 | ||||||||||
Total crude oil production | 246 | 205 | 259 | 216 | 248 | 208 | 230 | 206 | 229 | 204 | ||||||||||
NGLs available for sale | 10 | 8 | 16 | 12 | 24 | 19 | 31 | 25 | 33 | 26 | ||||||||||
Total crude oil and NGL production | 256 | 213 | 275 | 228 | 272 | 227 | 261 | 231 | 262 | 230 | ||||||||||
Cold Lake sales, including diluent(2) | 191 | 200 | 198 | 183 | 167 | |||||||||||||||
NGL sales | 11 | 20 | 29 | 39 | 42 |
Natural gas –- production and sales(a)(1)
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||||||||||||||||||||||
gross | net | gross | net | gross | net | gross | net | gross | net | |||||||||||||||||||||||||||||||
(millions of cubic feet a day) | ||||||||||||||||||||||||||||||||||||||||
Production(c) | 458 | 404 | 556 | 496 | 580 | 514 | 569 | 518 | 513 | 457 | ||||||||||||||||||||||||||||||
Sales | 407 | 513 | 536 | 520 | 460 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||||||||||||
gross | net | gross | net | gross | net | gross | net | gross | net | |||||||||||
(millions of cubic feet a day) | ||||||||||||||||||||
Production(3) | 310 | 249 | 458 | 404 | 556 | 496 | 580 | 514 | 569 | 518 | ||||||||||
Sales | 288 | 407 | 513 | 536 | 520 |
(1) | Daily volumes are calculated by dividing total volumes for the year by the number of days in the year. Gross production is the company’s share of production (excluding purchases) before deducting the share of mineral owners or governments or both. Net production excludes those shares. | ||
(2) | Diluent is natural gas condensate or other light hydrocarbons added to | ||
(3) | Production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected. |
Production costs increased by less than three percentmainly due to higher energy prices and Syncrude maintenance costs.
Downstream
Net income was $796 million, compared with $921 million in 2007. Higher exploration and other operating costs were partially offset by lower depreciation expenses.
Financial statistics
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Net income | 921 | 624 | 694 | 556 | 462 | |||||||||||||||
Operating revenues(a) | 21,535 | 20,783 | 24,017 | 19,169 | 16,004 |
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(millions of litres a day (b)) | ||||||||||||||||||||
Gasolines | 33.1 | 32.7 | 33.4 | 33.2 | 33.0 | |||||||||||||||
Heating, diesel and jet fuels | 26.0 | 26.4 | 26.9 | 27.3 | 26.2 | |||||||||||||||
Heavy fuel oils | 5.2 | 5.1 | 6.0 | 5.9 | 5.4 | |||||||||||||||
Lube oils and other products | 6.9 | 7.7 | 7.6 | 7.0 | 5.8 | |||||||||||||||
Net petroleum product sales | 71.2 | 71.9 | 73.9 | 73.4 | 70.4 | |||||||||||||||
Total domestic sales of petroleum products(percent) | 94.8 | 95.1 | 95.3 | 93.0 | 93.3 | |||||||||||||||
21
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(millions of dollars) | ||||||||||
Net income | 796 | 921 | 624 | 694 | 556 | |||||
Operating revenues(1) | 26,941 | 21,535 | 20,783 | 24,017 | 19,169 | |||||
Sale of petroleum products | ||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(thousands of barrels a day (2)) | ||||||||||
Gasolines | 204 | 208 | 206 | 210 | 209 | |||||
Heating, diesel and jet fuels | 157 | 164 | 166 | 169 | 172 | |||||
Heavy fuel oils | 30 | 33 | 32 | 38 | 37 | |||||
Lube oils and other products | 47 | 43 | 49 | 48 | 44 | |||||
Net petroleum product sales | 438 | 448 | 453 | 465 | 462 | |||||
Total domestic sales of petroleum products(percent) | 93.0 | 94.8 | 95.1 | 95.3 | 93.0 |
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(thousands of barrels a day (b)) | ||||||||||||||||||||
Total refinery throughput (c) | 442 | 442 | 466 | 467 | 450 | |||||||||||||||
Refinery capacity at December 31 | 502 | 502 | 502 | 502 | 502 | |||||||||||||||
Utilization of total refinery capacity(percent) | 88 | 88 | 93 | 93 | 90 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(thousands of barrels a day (2)) | ||||||||||
Total refinery throughput(3) | 446 | 442 | 442 | 466 | 467 | |||||
Refinery capacity at December 31 | 502 | 502 | 502 | 502 | 502 | |||||
Utilization of total refinery capacity (percent) | 89 | 88 | 88 | 93 | 93 |
(1) | 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 | ||
(2) | Volumes a day are calculated by dividing total volumes for the year by the number of days in the year. | ||
(3) | Crude oil and feedstocks sent directly to atmospheric distillation units. |
Industry refining margins were strongerlower in the refining segment of the industry in 20072008, compared with those in 2006, pushed up by increased2007, reflecting weakening demand for refined petroleum products that stemmed from generally stronger global economic conditions. However, the effects of stronger industry margins were reduced partially by aand higher Canadian dollar.inventory levels. Marketing margins in 20072008 were slightly higher than those in 2006.
Refinery throughput was 8889 percent of capacity in 2007, unchanged from2008, one percent higher than the previous year (2005(2006 - - 9388 percent). Refinery throughput in 2007 and 2006 was lower than in 2005 dueReliability improvements through the year were partially offset by the impact of declining economic conditions that did not support running the refineries to planned and unplanned downtime of crude processing facilities.
Downstream’s total sales volumes, excluding those resulting from reciprocal supply agreementspurchases/sales contracts with other companies,the same counterparty, were 71.2 million litres438,000 barrels a day, compared with 71.9 million litresdown from 448,000 barrels in 2006 (2005 — 73.9 million)2007 (2006 – 453,000). Lower refinery productionindustry demand was the main reason for the decline.
Manufacturing costs in 20072008 were lowerhigher than the previous year by about two percent,primarily reflecting lowerhigher energy prices and planned maintenance and project related expenses.
Chemical
Net income from chemicals operations was $97$100 million, compared with $143$97 million in 2006. Lower earnings were primarily due to lower industry2007. Higher margins for polyethylene products partiallywere essentially offset by the positive impact of lower tax rates. A stronger Canadian dollar also negatively impacted earnings in 2007.
Financial statistics
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Net income | 97 | 143 | 121 | 109 | 44 | |||||||||||||||
Operating revenues | 1,635 | 1,704 | 1,665 | 1,509 | 1,232 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(millions of dollars) | ||||||||||
Net income | 100 | 97 | 143 | 121 | 109 | |||||
Operating revenues | 1,832 | 1,635 | 1,704 | 1,665 | 1,509 |
Sales
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(thousands of tonnes a day (a)) | ||||||||||||||||||||
Polymers and basic chemicals | 2.2 | 2.2 | 2.1 | 2.4 | 2.4 | |||||||||||||||
Intermediate and others | 0.9 | 0.8 | 0.9 | 0.9 | 0.9 | |||||||||||||||
Total chemicals | 3.1 | 3.0 | 3.0 | 3.3 | 3.3 | |||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(thousands of tonnes a day (1)) | ||||||||||
Polymers and basic chemicals | 2.1 | 2.2 | 2.2 | 2.1 | 2.4 | |||||
Intermediate and others | 0.7 | 0.9 | 0.8 | 0.9 | 0.9 | |||||
Total petrochemicals | 2.8 | 3.1 | 3.0 | 3.0 | 3.3 |
(1) | Calculated by dividing total volumes for the year by the number of days in the year. |
The average industry price of polyethylene was $1,960 a tonne in 2008, up 18 percent from $1,666 a tonne in 2007 slightly lower than $1,703 a tonne in 2006 (2005 — $1,708).
Sales of chemicalschemical products were 3,1002,800 tonnes a day, compared withdown from 3,100 tonnes in 2007 (2006 – 3,000 tonnes a day in 2006 (2005 - 3,000 tonnes), primarily due to higher volumes inlower industry demand for both polyethylene and intermediate chemical products.
Manufacturing costs in the chemicals segment for 2008 were higher than 2007, were about three percent lower than in 2006, reflecting lower direct operating expenses.
Corporate and other
Net income effects from corporate and other waswere $59 million, versus negative $199 million versus negative $99 million last year. UnfavourableFavourable earnings effects were primarily due to higherlower share-based compensation charges and the impactabsence of unfavourable effects of tax rate changes.
22changes reported in 2007.
Sources and uses of cash
2007 | 2006 | |||||||
(millions of dollars) | ||||||||
Cash provided by/(used in) | ||||||||
Operating activities | 3,626 | 3,587 | ||||||
Investing activities | (620) | (965) | ||||||
Financing activities | (3,956) | (2,125) | ||||||
Increase/(decrease) in cash and cash equivalents | (950) | 497 | ||||||
Cash and cash equivalents at end of year | 1,208 | 2,158 | ||||||
2008 | 2007 | 2006 | ||||||||
(millions of dollars) | ||||||||||
Cash provided by/(used in) | ||||||||||
Operating activities | 4,263 | 3,626 | 3,587 | |||||||
Investing activities | (961) | (620) | (965) | |||||||
Financing activities | (2,536) | (3,956) | (2,125) | |||||||
Increase/(decrease) in cash and cash equivalents | 766 | (950) | 497 | |||||||
Cash and cash equivalents at end of year | 1,974 | 1,208 | 2,158 |
Although the company issues long-term debt from time to time and maintains a revolving commercial paper program, internally generated funds normally cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the company’s 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 company’s cash requirements.
Cash flows from operating activities are highly dependent on crude oil and natural gas prices and product margins. In addition, to support cash flows in future periods, the company will need to continually find and develop new fields, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production. Projects are in place or underway to increase production capacity. However, these volume increases are subject to a variety of risks, including project execution, operational outages, reservoir performance and regulatory changes.
The company’s financial strength enables it to make large, long-term capital expenditures. Imperial’s 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 company’s liquidity or ability to generate sufficient cash flows for its operations and fixed commitments.
The company’s registered pension plan is subject to an independent actuarial valuation that is required at least once every three years. The next such valuation will take place in 2010. Given the recent downturn in financial markets, the next valuation could require that Imperial increase its contributions to the plan over the next five years. The size of any required contribution will not be known until the valuation is completed. The company expects that it will meet any funding requirements without affecting current or future investment plans.
Cash flow from operating activities
Cash provided by operating activities was $4,263 million, versus $3,626 million versusin 2007 (2006 – $3,587 million in 2006 (2005 - - $3,451 million). Higher cash flow in 20072008 was primarily due to higher net income. Unfavourable impact of the timing of income tax payments was largely offset by net effects of higher commodity prices on working capital balances.
Cash flow from investing activities
Cash used in investing activities totaled $961 million in 2008, compared with $620 million in 2007 compared with(2006 - $965 million in 2006 (2005 — $992 million). Lower plannedHigher spending on property, plant and equipment and higher proceeds from asset sales contributed to the change.
Capital and exploration expenditures
Total capital and exploration expenditures were $1,363 million in 2008, compared with $978 million in 2007 compared with(2006 – $1,209 million in 2006 (2005 — $1,475 million).
The funds were used mainly to invest inadvance the Kearl oil sands project, maintain Cold Lake to maintain and expand production capacity, advance upstream projects, invest in environmental initiatives and upgrade the network of Esso retail outlets. About $160$250 million was spent on projects related to reducing the environmental impact of the company’s operations and improving safety.
The following table shows the company’s capital and exploration expenditures for natural resourcesUpstream during the five years ending December 31, 2007:
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Heavy oil and oil sands | 489 | 518 | 662 | 819 | 769 | |||||||||||||||
Production | 150 | 237 | 232 | 234 | 181 | |||||||||||||||
Exploration | 105 | 32 | 43 | 60 | 57 | |||||||||||||||
Total capital and exploration expenditures | 744 | 787 | 937 | 1,113 | 1,007 | |||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(millions of dollars) | ||||||||||
Heavy oil and oil sands | 740 | 489 | 518 | 662 | 819 | |||||
Production | 238 | 150 | 237 | 232 | 234 | |||||
Exploration | 132 | 105 | 32 | 43 | 60 | |||||
Total capital and exploration expenditures | 1,110 | 744 | 787 | 937 | 1,113 |
For the natural resourcesUpstream segment, over 8085 percent of the capital and exploration expenditures in 20072008 were focused on growth opportunities. Significant expenditures during the year were made tofor advancing the Kearl oil sands project and ongoing development drilling at Cold Lake. Other 20072008 investments included advancing the Kearl oil sands and Mackenzie gas projects,facilities improvements at Syncrude, drilling at Horn River and conventional fields in Western Canada and exploration offa 3-D seismic program in the East CoastBeaufort Sea.
Kearl is an oil sands mining project located northeast of Canada. Expenditures at SyncrudeFort McMurray, Alberta. Regulatory approvals were lower in 2007 primarily due to the completion of the Stage 3 upgrader project, partially offset by increased investment in other facility improvement projects and programs.
23
About $500 million had been invested in Kearl oil sands project, following a joint federal and provincial review. The company is advancingby the project including further progressend of 2008. Activities in 2008 focused on engineering work to define the project design and execution strategies and project cost estimate.
Imperial has acquired exploration rights for a parcellicenses to about 76,000 net acres in the Beaufort Sea. The company’s 50 percent share of the proposed exploration spending would be about $293 million with a minimum commitment of about $73 million.
Planned capital and exploration expenditures in natural resourcesthe Upstream segment are expected to be about $1,200 million$1.8 billion in 2008,2009, with over 80 percent of the total focused on growth opportunities. Investments are mainly planned for the Kearl oil sands project and development drilling at Cold Lake andLake. Other investments will include facilities improvements at Syncrude, development drilling at conventional oil and gas operations in Western Canada facilities improvement at Syncrude, the Kearl oil sands project, the Mackenzie gas project, and exploration off the East Coast.
The following table shows the company’s capital expenditures in the petroleum productsDownstream segment during the five years ending December 31, 2007:
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Refining and supply | 120 | 248 | 368 | 178 | 369 | |||||||||||||||
Marketing | 63 | 97 | 91 | 85 | 91 | |||||||||||||||
Other(a) | 4 | 16 | 19 | 20 | 18 | |||||||||||||||
Total capital expenditures | 187 | 361 | 478 | 283 | 478 | |||||||||||||||
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(millions of dollars) | ||||||||||
Refining and supply | 160 | 120 | 248 | 368 | 178 | |||||
Marketing | 61 | 63 | 97 | 91 | 85 | |||||
Other(1) | 11 | 4 | 16 | 19 | 20 | |||||
Total capital expenditures | 232 | 187 | 361 | 478 | 283 |
(1) | Consists primarily of real estate purchases. |
For the petroleum productsDownstream segment, capital expenditures were $232 million in 2008, compared with $187 million in 2007 compared with(2006 – $361 million in 2006 (2005 – $478 million). In 2006, the company completed the project to produce ultra-low sulphur diesel. In 2007, the majority of the2008, Downstream capital expenditures were directed to investments to continue enhancements tofocused mainly on improving air emissions, increasing refinery capacity utilization and upgrading the company’s retail network, environmental and safety initiatives, as well as capacity and efficiency improvements.
Capital expenditures for the petroleum productsDownstream segment in 20082009 are expected to be about $300 million. Major items include investments focused on reducing air$400 million, and will be mainly directed to increasing sulphur recovery to further reduce sulphur dioxide emissions, and improving refinery utilizations,upgrading water management systems as well as ongoingenhancing feedstock flexibility and energy efficiency. Retail projects will continue to focus on network upgrades to the retail network.
The following table shows the company’s capital expenditures for its chemicalsChemical operations during the five years ending December 31, 2007:
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Capital expenditures | 11 | 13 | 19 | 15 | 41 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
(millions of dollars) | ||||||||||
Capital expenditures | 13 | 11 | 13 | 19 | 15 |
Of the capital expenditures for chemicalsthe Chemical segment in 2007,2008, the major investment focused on operational reliabilitywas directed to upgrading water management systems, improving safety and energy conservation initiatives.
Planned capital expenditures for chemicalsChemical in 2008 will be2009 is about $25$35 million and will include continued investments to improveincrease feedstock flexibility and further upgrade water management and safety and increase future feedstock flexibility.
Total capital and exploration expenditures for the company in 2008,2009, which will focus mainly on growth and productivity improvements, are expected to total about $1.5$2.2 billion and willto be financed from internally generated funds.
Cash flow from financing activities
Cash used in financing activities was $2,536 million in 2008, compared with $3,956 million in 2007 compared with(2006 - $2,125 million in 2006 (2005 – $2,077 million).
In June, the company renewed the normal course issuer bid (share-repurchase program) for another 12 months.month share repurchase program was implemented. During 2007,2008, the company purchased 44.3 million shares for $2,210 million (2007 – 50.5 million shares for $2,358 million (2006 – 45.5 millionmillion), including shares for $1,818 million).purchased from ExxonMobil. Since Imperial initiated its first share-repurchaseshare repurchase program in 1995, the company has purchased 846
24
The company declared dividends totaling 3538 cents a share in 2007,2008, up from 3235 cents in 2006 (20052007 (2006 – 3132 cents). Regular annual per-share dividends paid have increased in each of the past 1314 years and, since 1986, payments per share have grown by 97102 percent.
Total debt outstanding at the end of 2007,2008, excluding the company’s share of equity company debt, was $146$143 million, compared with $1,437$146 million at the end of 2006 (20052007 (2006 – $1,439$1,437 million). Debt represented two percent of the company’s capital structure at the end of 2007, compared with 17 percent at2008, unchanged from the end of 2006 (20052007 (2006 – 1817 percent).
Debt-related interest incurred in 2007,2008, before capitalization of interest, was $62$8 million, compared with $63$62 million in 2006 (20052007 (2006 – $45$63 million). The average effective interest rate on the company’s debt was 5.5 percent in 2008, compared with 4.9 percent in 2007 compared with(2006 – 4.4 percent in 2006 (2005 – 3.1 percent).
Financial percentages and ratios
�� | 2007 | 2006 | 2005 | 2004 | 2003 | |||||||||||||||
Total debt as a percentage of capital(a) | 2 | 17 | 18 | 19 | 21 | |||||||||||||||
Interest coverage ratios | ||||||||||||||||||||
Earnings basis(b) | 72 | 66 | 88 | 83 | 64 | |||||||||||||||
Cash-flow basis(c) | 82 | 77 | 101 | 108 | 80 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
Total debt as a percentage of capital(1) | 2 | 2 | 17 | 18 | 19 | |||||
Interest coverage ratios | ||||||||||
Earnings basis(2) | 661 | 72 | 66 | 88 | 83 | |||||
Cash-flow basis(3) | 721 | 82 | 77 | 101 | 108 |
(1) | Current and long-term portions of debt (page | ||
(2) | Net income (page F-3), debt-related interest before capitalization (page F-19, note | ||
(3) | Cash flow from net income adjusted for other non-cash items (page |
The company’s financial strength, as evidenced by the above financial ratios, represents a competitive advantage of strategic importance. The company’s sound financial position gives it the opportunity to access capital markets in the full range of market conditions and enables the company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.
Commitments
The following table shows the company’s commitments outstanding at December 31, 2007.2008. It combines data from the consolidated balance sheet and from individual notes to the consolidated financial statements.
Financial | Payment due by period | |||||||||||||||||||
Statement | ||||||||||||||||||||
Note Reference | 2009 to | 2013 and | Total | |||||||||||||||||
2008 | 2012 | beyond | Amount | |||||||||||||||||
(millions of dollars) | ||||||||||||||||||||
Long-term debt(a) | Note 4 | 3 | 15 | 23 | 41 | |||||||||||||||
Operating leases(b) | Note 15 | 55 | 138 | 39 | 232 | |||||||||||||||
Unconditional purchase obligations(c) | Note 11 | 99 | 345 | 38 | 482 | |||||||||||||||
Firm capital commitments(d) | 250 | 43 | 63 | 356 | ||||||||||||||||
Pension and other post-retirement obligations(e) | Note 6 | 218 | 194 | 601 | 1,013 | |||||||||||||||
Asset retirement obligations(f) | Note 7 | 33 | 199 | 256 | 488 | |||||||||||||||
Other long-term purchase agreements(g) | 215 | 590 | 200 | 1,005 |
Financial Statement | Payment due by period | |||||||||||
2009 | 2010 to 2013 | 2014 and beyond | Total amount | |||||||||
(millions of dollars) | ||||||||||||
Capitalized lease obligations(1) | Note 14 | 4 | 15 | 19 | 38 | |||||||
Operating leases(2) | Note 14 | 64 | 210 | 158 | 432 | |||||||
Unconditional purchase obligations(3) | Note 10 | 127 | 262 | 31 | 420 | |||||||
Firm capital commitments(4) | 251 | 80 | - | 331 | ||||||||
Pension and other post-retirement obligations(5) | Note 5 | 253 | 203 | 740 | 1,196 | |||||||
Asset retirement obligations(6) | Note 6 | 42 | 309 | 360 | 711 | |||||||
Other long-term purchase agreements(7) | 302 | 506 | 166 | 974 |
(2) | Minimum commitments for operating leases, shown on an undiscounted basis, primarily cover office buildings, rail cars and service stations. | ||
(3) | Unconditional purchase obligations are those long-term commitments that are non-cancelable and that third parties have used to secure financing for the facilities that will provide the contracted goods and services. They mainly pertain to pipeline throughput agreements. | ||
(4) | Firm capital commitments related to capital projects, shown on an undiscounted basis. The largest | ||
(5) | The amount by which the benefit obligations exceeded the fair value of fund assets for pension and other post-retirement plans at year-end. The payments by period include expected contributions to funded pension plans in | ||
(6) | Asset retirement obligations represent the | ||
(7) | Other long-term purchase agreements are non-cancelable, long-term commitments other than unconditional purchase obligations. They include primarily raw material supply and transportation services agreements. |
25
The company was contingently liable at December 31, 2007,2008, for a maximum of $83$79 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing associates upon expiry of the associate agreement or the resignation of the associate. The company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payments under the guarantees.
Litigation and other contingencies
As discussed in note 1110 to the consolidated financial statements on page F-18, a variety of claims have been made against Imperial Oil Limited and its subsidiaries. Based on a consideration of all relevant facts and circumstances, the company does not believe the ultimate outcome of any currently pending lawsuits against the company will have a material adverse effect on the company’s operations or financial condition.
The Alberta government proposedenacted changes to the oil and gas and generic oil sands royalty regime beginning ineffective 2009. The company believes that this proposal couldimpacts of the changes have an adverse effect on future company investmentsbeen incorporated in Alberta and the company’s future financial results. The magnitude of the potential impact will depend on the final form of enacted legislation and the future prices of2008 oil and gas reserves and cannot be reasonably estimated at this time. The Syncrude Joint Venture owners have a Crown Agreementmined bitumen reserves calculation, where appropriate. In November 2008, Imperial, along with the Provinceother Syncrude joint-venture owners, signed an agreement with the Government of Alberta that codifiesto amend the royalty rates through December 31, 2015. Theexisting Syncrude Joint Venture owners are in discussions withCrown Agreement. Under the Alberta government to determine if an amended agreement, can be negotiated that would transitionbeginning January 1, 2010, Syncrude will begin transitioning to the new generic oil sands royalty regime before 2016.
Critical accounting policies
The company’s financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) and include estimates that reflect management’s best judgment. The company’s 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 and mined bitumen reserve quantities are used as the basis offor calculating unit-of-production depreciation rates and 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,volumes, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits.
The estimation of proved reserves is controlled by the company through long-standing approval guidelines. Reserve changes are made within a well-established, disciplined process driven by senior-level geoscience and engineering professionals (assisted by a central reserves group with significant technical experience), culminating in reviews with and approval by senior management and the company’s board of directors. Notably, the company does not use specific quantitative reserve targets to determine compensation. Key features of the estimation include rigorous peer-reviewed technical evaluations and analysis of well and field performance information and a requirement that management make significant funding commitments toward the development of the reserves prior to reporting as proved.
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The year-end oil and gas reserves volumes as well as the reserves change categories shown in the proved reserves tables are calculated using December 31 prices and costs. These reserves quantities are also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. The U.S. Securities and Exchange Commission regulations preclude the company from showing in the Financial section of this document the reserves that are calculated in a manner which is consistent with the basisWe understand that the company usesuse of December 31 prices and costs is intended to make its investment decisions. Theprovide a point in time measure to calculate reserves and to enhance comparability between companies. However, the use of year-end prices for reserves estimation introduces short-term price volatility into the process, which is inconsistent with the long-term nature of the upstream business, since annual adjustments are required based on prices occurring on a single day. The company believes that this approach is inconsistent withAs a result, the long-term nature of the natural resources business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the company and annual variations in reserves based on such year-end prices are not of consequence in how the business is actually managed.
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in year-end prices and costs that are used in the determination of reserves. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity. The quantities shown in the revisions category under heavy oil proved reserves in 2005 and 2006 on page 31 were due mainly to the changes in year-end prices and costs that were used in the determination of reserves.
The company uses the successful-efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field.method. 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 company’s 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 resourcesupstream 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 asset’s carrying value exceeds its fair value.
The company performs asset valuation analyses on an ongoing basis as a part of its asset management program. These analyses monitor the performance of assets against corporate objectives. They also assist the company in assessing whether the carrying amounts of any of its assets may not be recoverable. In addition to estimating oil and gas reserve volumes in conducting these analyses, it is also necessary to estimate future oil and gas prices. Trigger events for impairment evaluation triggersevaluations include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected and historical and current operating losses.
In general, the company does not view temporarily low oil prices as a triggering event for conducting impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously,significantly, the relative growth/decline in supply versus demand will determine industry prices over the long term, and these cannot be accurately predicted. Accordingly, any impairment tests that the company performs make use of the company’s price assumptions developed in the annual planning and budgeting process for crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used for capital investment decisions. Volumes are based on individual field production profiles, which are also updated annually.
The standardized measure of discounted future cash flows on page 3332 is based on the year-end price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (SFAS 69). Future
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Pension benefits
The company’s pension plan is managed in compliance with the requirements of governmental authorities and meets funding levels as determined by independent third-party actuaries. Pension accounting requires explicit assumptions regarding, among others, the discount rate for the benefit obligations, the expected rate of return on plan assets and the long-term rate of future compensation increases. All pension assumptions are reviewed annually by senior management. These assumptions are adjusted only as appropriate to reflect long-term changes in market rates and outlook. The long-term expected rate of return on plan assets of 8.00 percent used in 20072008 compares to actual returns of 8.295.00 percent and 9.848.31 percent achieved over the last 10- and 20-year periods ending December 31, 2007.2008. If different assumptions are used, the expense and obligations could increase or decrease as a result. The company’s potential exposure to changes in assumptions is summarized in note 65 to the consolidated financial statements on page F-12. At Imperial, differences between actual returns on plan assets and the long-term expected returns are not recorded in pension expense in the year the differences occur. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected remaining service life of employees. Pension expense represented less than one percent of total expenses in 2007.
Asset retirement obligations and other environmental liabilities
Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. The obligations are initially
measured at fair value and discounted to present value. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, with this effect included in operating expense. As payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long-term changes in market rates and outlook. For 2007,2008, the obligations were discounted at six percent and the accretion expense was $25$29 million, before tax, which was significantly less than one percent of total expenses in the year. There would be no material impact on the company’s 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 company’s 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 company’s reported financial results.
Tax Contingencies
The operations of the company are complex, and related tax interpretations, regulations and legislation are continually changing. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
GAAP requires recognition and measurement of uncertain tax positions that the company has taken or expects to take in its income tax returns. The benefit of an uncertain tax position can only be recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. A reserve is established for the difference between a position taken in an income tax return and the amount recognized in the financial statements. The company’s unrecognized tax benefits and a description of open tax years are summarized in note 54 to the consolidated financial statements on page F-11.
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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 company’s control, while others are not. For those risks that can be controlled, specific risk-management strategies are employed to reduce the likelihood of loss.
During 2008, credit markets tightened, and the global economy slowed. In 2009, the company does not expect to be dependent on credit markets to fund normal operations or investment plans.
In April 2007, the Government of Canada announced its intent to introduce a set of regulations to limit emissions of greenhouse gas and air pollutants from major industrial facilities in Canada, beginning in 2010, although the details of the regulations have not been finalized. Consequently, attempts to assess the impact on the company are premature. The company will continue to monitor the development of legal requirements in this area.
In the Province of Alberta, regulations governing greenhouse gas emissions from large industrial facilities came into effect July 1, 2007. TheCompliance costs were not material in 2007 and 2008, and the company does not expect ongoing compliance costs to have a material adverse effect on the company’s operations or financial condition.
The recently enacted U.S. Energy Independence and Security Act of 2007 precludes agencies of the U.S. federal government from procuring motive fuels from non-conventional petroleum sources that have lifecycle greenhouse gas emissions greater than equivalent conventional fuel. This may have implications for the company’s marketing in the United States of some heavy oil and oil sands production, but the impact cannot be determined at this time.
Other risks, such as changes in international commodity prices and currency-exchange rates, are beyond the company’s control. The company does not use derivative markets to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment.prices. The company’s size, strong financial position and the complementary nature of its natural resources, petroleum productsUpstream, Downstream and chemicalsChemical segments help mitigate the company’s exposure to changes in these other risks. The company’s potential exposure to these types of risk is summarized in the earnings sensitivitysensitivities table below, which shows the estimated annual effect, under current conditions, of certain sensitivities of the company’s after-tax net income.
Earnings sensitivities(a)
millions of dollars after tax | ||||||
Three dollars (U.S.) a barrel change in crude oil prices | +(-) | 150 | ||||
Seventy cents a thousand cubic feet change in natural gas prices | +(-) | 6 | ||||
One | +(-) | 140 | ||||
One cent (U.S.) a pound change in sales margins for polyethylene | +(-) | 7 | ||||
Eight cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar | +(-) | 300 |
(1) | 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 |
The sensitivity of net income to changes in crude oil prices decreasedincreased from 20062007 year-end by about $8$13 million (after-tax) for each one U.S.-dollar a barrel difference. An increaseA decrease in the value of the Canadian dollar has lessenedincreased the impact of the U.S. dollar denominated crude oil prices on the company’s revenues and earnings.
The presentation of the sensitivity of net income to changes in sales margins for total petroleum products has changed from a one cent (U.S.) a litre basis to a one dollar (U.S.) a barrel basis to conform to industry benchmarks’ unit of measure. The sensitivity of net income to changes in natural gas prices decreased from 2006 year-end bysales margins for total petroleum products was about $2$140 million (after-tax) for each 10-cent change, primarily due toone dollar (U.S.) a barrel difference at 2008 year-end, an increase of about $25 million from 2007 year-end. A decrease in the company’s 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
Syncrude’s crude bitumen is contained within the unconsolidated sands of the McMurray Formation. Ore bodies are buried beneath 50 to 150 feet of overburden, have bitumen grades ranging from 4four to 14 weight percent and ore thickness of 115 to 160180 feet. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volumes, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. In active mining areas, the approximate well spacing is 400 feet (150 wells per section) and in future mining areas, the well spacing is approximately 1,150 feet (20 wells per section). Proven reserves are within operating North and Aurora mines. In accordance with the long range mine plan approved by the Syncrude owners, there are extractable oil sands in the North and Aurora mines, with average bitumen grades of 10.6 and 11.2 weight percent respectively. After deducting royalties payable to the Province of Alberta, the company estimates its 25 percent net share of proven reserves at year end 20072008 was equivalent to 694734 million barrels of synthetic crude oil. Imperial’s reserve
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The following table sets forth the company’s share of net proven reserves of Syncrude after deducting royalties payable to the Province of Alberta:
Synthetic Crude Oil | ||||||||||||||||
Base mine and | Aurora mine | Total | ||||||||||||||
North mine | ||||||||||||||||
(millions of barrels) | ||||||||||||||||
Beginning of year 2005 | 217 | 540 | 757 | |||||||||||||
Revision of previous estimate | – | – | – | |||||||||||||
Production | (9) | (10) | (19) | |||||||||||||
End of year 2005 | 208 | 530 | 738 | |||||||||||||
Revision of previous estimate | – | 1 | 1 | |||||||||||||
Production | (9) | (12) | (21) | |||||||||||||
End of year 2006 | 199 | 519 | 718 | |||||||||||||
Revision of previous estimate | – | – | – | |||||||||||||
Production | (11) | (13) | (24) | |||||||||||||
End of year 2007 | 188 | 506 | 694 | |||||||||||||
Synthetic Crude Oil | ||||||
Base mine and North mine | Aurora mine | Total | ||||
(millions of barrels) | ||||||
Beginning of year 2006 | 208 | 530 | 738 | |||
Revision of previous estimate | – | 1 | 1 | |||
Production | (9) | (12) | (21) | |||
End of year 2006 | 199 | 519 | 718 | |||
Revision of previous estimate | – | – | – | |||
Production | (11) | (13) | (24) | |||
End of year 2007 | 188 | 506 | 694 | |||
Revision of previous estimate | 27 | 36 | 63 | |||
Production | (11) | (12) | (23) | |||
End of year 2008 | 204 | 530 | 734 |
Kearl Project
Bitumen deposits at Kearl are found throughout sandstones within the Lower, Middle and Upper McMurray members, concentrated primarily within the Middle and Upper McMurray members. The oil sands occur over depths ranging from approximately 30 feet to as much as 450 feet below surface. The oil sands are about 130 feet in net thickness, but can be as thick as 230 feet. Mined bitumen reserve estimates are based upon detailed geological and engineering assessments of in-place crude bitumen volumes, the mining plan, demonstrated extraction recovery factors, planned operating capacity and operating approval limits. The in-place volume, depth and grade of the first phase were established through extensive and closely spaced core drilling with spacing of approximately 1,400 feet (14 wells per section). Imperial’s reserve determination uses a seven percent bitumen grade cut-off by weight, a 77 percent overall extraction recovery (paraffinic froth treatment process) and a 95 percent mining dilution factor. Net proven reserves are based on the company’s best estimate of average royalty rates over the life of the project and incorporate the Alberta government’s new oil sands royalty regime. Actual future royalty rates may vary with production, price and costs.
The following table sets forth the company’s share of net proven reserves for Kearl after deducting royalties payable to the Province of Alberta:
Total | ||||||||
(millions of barrels) | ||||||||
End of year 2007 | – | |||||||
Additions | 807 | |||||||
Production | – | |||||||
End of year 2008 | 807 |
Oil and Gas Producing Activities
The following information is provided in accordance with the United States’ Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities”.
Results of operations
2007 | 2006 | 2005 | ||||||||||||||
(millions of dollars) | ||||||||||||||||
Sales to customers (1) | 2,383 | 2,601 | 2,739 | |||||||||||||
Intersegment sales (1)(2) | 1,131 | 1,251 | 1,013 | |||||||||||||
3,514 | 3,852 | 3,752 | ||||||||||||||
Production expenses | 1,074 | 1,016 | 1,035 | |||||||||||||
Exploration expenses | 100 | 32 | 31 | |||||||||||||
Depreciation and depletion | 371 | 467 | 583 | |||||||||||||
Income taxes | 526 | 564 | 716 | |||||||||||||
Results of operations | 1,443 | 1,773 | 1,387 | |||||||||||||
2008 | 2007 | 2006 | ||||
(millions of dollars) | ||||||
Sales to customers(1) | 3,343 | 2,383 | 2,601 | |||
Intersegment sales(1)(2) | 1,297 | 1,131 | 1,251 | |||
4,640 | 3,514 | 3,852 | ||||
Production expenses | 1,335 | 1,074 | 1,016 | |||
Exploration expenses | 122 | 100 | 32 | |||
Depreciation and depletion | 337 | 371 | 467 | |||
Income taxes | 814 | 526 | 564 | |||
Results of operations | 2,032 | 1,443 | 1,773 |
Capital and exploration expenditures
2007 | 2006 | 2005 | ||||||||||||||
(millions of dollars) | ||||||||||||||||
Property costs (3) | ||||||||||||||||
Proved | – | – | – | |||||||||||||
Unproved | 1 | – | 7 | |||||||||||||
Exploration costs | 100 | 32 | 37 | |||||||||||||
Development costs | 437 | 496 | 330 | |||||||||||||
Total capital and exploration expenditures | 538 | 528 | 374 | |||||||||||||
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2008 | 2007 | 2006 | ||||
(millions of dollars) | ||||||
Property costs(3) | ||||||
Proved | – | – | – | |||
Unproved | – | 1 | – | |||
Exploration costs | 122 | 100 | 32 | |||
Development costs | 525 | 437 | 496 | |||
Total capital and exploration expenditures | 647 | 538 | 528 | |||
Property, plant and equipment | ||||||
2008 | 2007 | |||||
(millions of dollars) | ||||||
Property costs(3) | ||||||
Proved | 3,168 | 3,167 | ||||
Unproved | 271 | 148 | ||||
Producing assets | 7,212 | 6,706 | ||||
Support facilities | 181 | 180 | ||||
Incomplete construction | 691 | 579 | ||||
Total cost | 11,523 | 10,780 | ||||
Accumulated depreciation and depletion | 7,840 | 7,505 | ||||
Net property, plant and equipment | 3,683 | 3,275 |
2007 | 2006 | |||||||
(millions of dollars) | ||||||||
Property costs (3) | ||||||||
Proved | 3,167 | 3,226 | ||||||
Unproved | 148 | 139 | ||||||
Producing assets | 6,706 | 6,392 | ||||||
Support facilities | 180 | 184 | ||||||
Incomplete construction | 579 | 595 | ||||||
Total cost | 10,780 | 10,536 | ||||||
Accumulated depreciation and depletion | 7,505 | 7,326 | ||||||
Net property, plant and equipment | 3,275 | 3,210 | ||||||
(1) | Sales to customers or intersegment sales do not include the sale of natural gas and natural gas liquids purchased for resale, as well as royalty payments. These items are reported gross in note 3 (page |
(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, arm’s-length transaction. |
(3) | “Property costs” are payments for rights to explore for petroleum and natural gas and for purchased reserves (acquired tangible and intangible assets such as gas plants, production facilities and producing-well costs are included under “producing assets”). “Proved” represents areas where successful drilling has delineated a field capable of production. “Unproved” represents all other areas. |
Oil and Gas Reserves
Net Proved developed and undeveloped reserves(1)
Crude oil and natural gas liquids | Natural Gas | |||||||||||||||
Conventional | Heavy Oil(2) | Total | Total | |||||||||||||
(millions of barrels) | (billions of | |||||||||||||||
cubic feet) | ||||||||||||||||
Beginning of year 2005 | 115 | 232 | 347 | 791 | ||||||||||||
Revisions | – | 350 | 350 | 137 | ||||||||||||
Improved recovery | – | – | – | – | ||||||||||||
(Sale)/purchase of reserves in place | (12) | – | (12) | (6) | ||||||||||||
Discoveries and extensions | – | 14 | 14 | 13 | ||||||||||||
Production | (20) | (45) | (65) | (188) | ||||||||||||
End of year 2005 | 83 | 551 | 634 | 747 | ||||||||||||
Revisions | 4 | 236 | 240 | 140 | ||||||||||||
Improved recovery | – | – | – | – | ||||||||||||
(Sale)/purchase of reserves in place | (1) | – | (1) | (6) | ||||||||||||
Discoveries and extensions | – | – | – | 10 | ||||||||||||
Production | (15) | (46) | (61) | (181) | ||||||||||||
End of year 2006 | 71 | 741 | 812 | 710 | ||||||||||||
Revisions | 24 | (27) | (3) | 75 | ||||||||||||
Improved recovery | – | 6 | 6 | 1 | ||||||||||||
(Sale)/purchase of reserves in place | (1) | – | (1) | (12) | ||||||||||||
Discoveries and extensions | – | 44 | 44 | 8 | ||||||||||||
Production | (12) | (47) | (59) | (147) | ||||||||||||
End of year 2007 | 82 | 717 | 799 | 635 | ||||||||||||
Crude oil and natural gas liquids | Natural gas | |||||||
Conventional | Heavy oil (2) | Total | Total | |||||
(millions of barrels) | (billions of cubic feet) | |||||||
Beginning of year 2006 | 83 | 551 | 634 | 747 | ||||
Revisions | 4 | 236 | 240 | 140 | ||||
Improved recovery | – | – | – | – | ||||
(Sale)/purchase of reserves in place | (1) | – | (1) | (6) | ||||
Discoveries and extensions | – | – | – | 10 | ||||
Production | (15) | (46) | (61) | (181) | ||||
End of year 2006 | 71 | 741 | 812 | 710 | ||||
Revisions | 24 | (27) | (3) | 75 | ||||
Improved recovery | – | 6 | 6 | 1 | ||||
(Sale)/purchase of reserves in place | (1) | – | (1) | (12) | ||||
Discoveries and extensions | – | 44 | 44 | 8 | ||||
Production | (12) | (47) | (59) | (147) | ||||
End of year 2007 | 82 | 717 | 799 | 635 | ||||
Revisions | (8) | (66) | (74) | 45 | ||||
Improved recovery | – | (1) | (1) | – | ||||
(Sale)/purchase of reserves in place | – | – | – | – | ||||
Discoveries and extensions | – | 25 | 25 | 4 | ||||
Production | (10) | (45) | (55) | (91) | ||||
End of year 2008 | 64 | 630 | 694 | 593 |
(1) |
(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 company’s heavy oil reserves |
The information above describes changes during the years and balances of proved oil and gas reserves at year-end 2005, 2006, 2007 and 2007.2008. The definitions used for oil and gas reserves are in accordance with the U.S. Securities and Exchange Commission’s (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.
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Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in year-end prices and costs that are used in the determination of reserves. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity. The quantities shown in the revisions category under heavy oil proved reserves in 2005 and 2006 were due mainly to changes in year-end prices and costs that were used in the determination of reserves.
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 futuremade incorporating the Alberta government new oil and gas royalty rates may vary with production and price.regime. For enhanced oil-recovery projects and heavy oil, net proved reserves are based on the company’s best estimate of average royalty rates over the life of each project. Actualproject and incorporate the Alberta government’s new oil sands royalty regime. In all cases actual future royalty rates may vary with production, price and costs.
Oil-equivalent barrels (OEB) may be misleading, particularly if used in isolation. An OEB conversion ratio of 6,000 cubic feet to one barrel on an energy-equivalent conversion method is primarily applicable at the burner tip and does not represent a value equivalency at the well head.
No independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data.
Net proved developed and undeveloped reserves of crude oil and natural gas as of December 31(1)
2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
Crude Oil(millions) | ||||||||||||||||||||
Conventional | ||||||||||||||||||||
Barrels | 82 | 71 | 83 | 115 | 126 | |||||||||||||||
Heavy Oil | ||||||||||||||||||||
Barrels | 717 | 741 | 551 | 232 | 763 | |||||||||||||||
Total | ||||||||||||||||||||
Barrels | 799 | 812 | 634 | 347 | 889 | |||||||||||||||
Natural Gas(billions) | ||||||||||||||||||||
Cubic feet | 635 | 710 | 747 | 791 | 1,023 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
Crude Oil(millions) | ||||||||||
Conventional | ||||||||||
Barrels | 64 | 82 | 71 | 83 | 115 | |||||
Heavy Oil | ||||||||||
Barrels | 630 | 717 | 741 | 551 | 232 | |||||
Total | ||||||||||
Barrels | 694 | 799 | 812 | 634 | 347 | |||||
Natural Gas(billions) | ||||||||||
Cubic feet | 593 | 635 | 710 | 747 | 791 |
(1) | Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both. |
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2007 | 2006 | 2005 | 2004 | 2003 | ||||||||||||||||
Crude Oil(millions) | ||||||||||||||||||||
Conventional | ||||||||||||||||||||
Barrels | 82 | 71 | 81 | 111 | 121 | |||||||||||||||
Heavy Oil | ||||||||||||||||||||
Barrels | 483 | 501 | 368 | 232 | 398 | |||||||||||||||
Total | ||||||||||||||||||||
Barrels | 565 | 572 | 449 | 343 | 519 | |||||||||||||||
Natural Gas(billions) | ||||||||||||||||||||
Cubic feet | 539 | 608 | 643 | 704 | 859 |
2008 | 2007 | 2006 | 2005 | 2004 | ||||||
Crude Oil(millions) | ||||||||||
Conventional | ||||||||||
Barrels | 63 | 82 | 71 | 81 | 111 | |||||
Heavy Oil | ||||||||||
Barrels | 425 | 483 | 501 | 368 | 232 | |||||
Total | ||||||||||
Barrels | 488 | 565 | 572 | 449 | 343 | |||||
Natural Gas(billions) | ||||||||||
Cubic feet | 513 | 539 | 608 | 643 | 704 |
(1) | Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both. |
Standardized measure of discounted future cash flows
As required by SFAS 69, the standardized measure of discounted future net cash flows is computed by applying year-end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and remediation obligations. The company believes the standardized measure does not provide a reliable estimate of the company’s 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 company’s interest in Syncrude.
Standardized measure of discounted future net cash flows related to proved oil and gas reserves
2007 | 2006 | 2005 | ||||||||||
(millions of dollars) | ||||||||||||
Future cash flows | 32,415 | 36,751 | 21,911 | |||||||||
Future production costs | (14,475) | (16,290) | (11,376) | |||||||||
Future development costs | (3,548) | (2,633) | (2,039) | |||||||||
Future income taxes | (3,655) | (5,039) | (2,777) | |||||||||
Future net cash flows | 10,737 | 12,789 | 5,719 | |||||||||
Annual discount of 10 percent for estimated timing of cash flows | (4,487) | (6,374) | (1,405) | |||||||||
Discounted future cash flows | 6,250 | 6,415 | 4,314 | |||||||||
2008 | 2007 | 2006 | ||||||||
(millions of dollars) | ||||||||||
Future cash flows | 18,956 | 32,415 | 36,751 | |||||||
Future production costs | (13,558) | (14,475) | (16,290) | |||||||
Future development costs | (4,642) | (3,548) | (2,633) | |||||||
Future income taxes | (111) | (3,655) | (5,039) | |||||||
Future net cash flows | 645 | 10,737 | 12,789 | |||||||
Annual discount of 10 percent for estimated timing of cash flows | 613 | (4,487) | (6,374) | |||||||
Discounted future cash flows | 1,258 | 6,250 | 6,415 |
Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves
2007 | 2006 | 2005 | ||||||||||
(millions of dollars) | ||||||||||||
Balance at beginning of year | 6,415 | 4,314 | 3,317 | |||||||||
Changes resulting from: | ||||||||||||
Sales and transfers of oil and gas produced, net of production costs | (2,430) | (2,839) | (2,650) | |||||||||
Net changes in prices, development costs and production costs | (625) | 4,221 | 3,343 | |||||||||
Extensions, discoveries, additions and improved recovery, less related costs | 164 | (4) | (513) | |||||||||
Development costs incurred during the year | 412 | 411 | 272 | |||||||||
Revisions of previous quantity estimates | 1,285 | 87 | 660 | |||||||||
Accretion of discount | 710 | 568 | 417 | |||||||||
Net change in income taxes | 319 | (343) | (532) | |||||||||
Net change | (165) | 2,101 | 997 | |||||||||
Balance at end of year | 6,250 | 6,415 | 4,314 | |||||||||
2008 | 2007 | 2006 | ||||
(millions of dollars) | ||||||
Balance at beginning of year | 6,250 | 6,415 | 4,314 | |||
Changes resulting from: | ||||||
Sales and transfers of oil and gas produced, net of production costs | (3,422) | (2,430) | (2,839) | |||
Net changes in prices, development costs and production costs | (6,016) | (625) | 4,221 | |||
Extensions, discoveries, additions and improved recovery, less related costs | 25 | 164 | (4) | |||
Development costs incurred during the year | 438 | 412 | 411 | |||
Revisions of previous quantity estimates | 1,460 | 1,285 | 87 | |||
Accretion of discount | 689 | 710 | 568 | |||
Net change in income taxes | 1,834 | 319 | (343) | |||
Net change | (4,992) | (165) | 2,101 | |||
Balance at end of year | 1,258 | 6,250 | 6,415 |
Within the past 12 months, the company has not filed oil and gas reserve estimates with any authority or agency of the United States.
33
Item 9A. | Controls and Procedures. |
As indicated in the certifications in Exhibit 31 of this report, the company’s principal executive officer and principal financial officer have evaluated the company’s disclosure controls and procedures as of December 31, 2007.2008. Based on that evaluation, these officers have concluded that the company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.
Reference is made to page F-2 of this report for management’s report on internal control over financial reporting.
There has not been any change in the company’s internal control over financial reporting during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting.
34
Item 9B. | Other Information. |
None.
The company currently has nineeight directors. Each director is elected to hold office until the close of the next annual meeting.
Each of the eight individuals listed below has been nominated for election at the annual meeting of shareholders to be held May 1, 2008.April 30, 2009. All of the nominees except for Krystyna T. Hoeg, are now directors and have been since the dates indicated. Timothy J. Hearn and James F. Shepard are currently directors and have both requested not to be nominated for re-election. Timothy J. Hearn has announced his intention to retire as director, chairman and chief executive officer effective March 31, 2008. Bruce H. March has been elected as chairman, president and chief executive officer effective April 1, 2008.
The following table provides information on the nominees for election as directors.
Name and current principal occupation or employment | Last major position or office
| Director since | Holdings (4)(5)(6) | |||||
K.T. (Krystyna) Hoeg Retired president and chief executive officer, Corby Distilleries Limited (1)(3) | – | May 1, 2008 | Common shares of Imperial Oil Limited | 0 | ||||
Deferred share units of Imperial Oil Limited | 1,931 | |||||||
Restricted stock units of Imperial Oil Limited | 2,000 | |||||||
Shares of Exxon Mobil Corporation
| 0
| |||||||
B.H. (Bruce) March Chairman, president and chief executive officer Imperial Oil Limited | President, Imperial Oil Limited, Calgary, Alberta | January 1, 2008 | Common shares of Imperial Oil Limited
| 5,000
| ||||
Deferred share units of Imperial Oil Limited
| 0
| |||||||
Restricted stock units of Imperial Oil Limited
| 43,300
| |||||||
Shares of Exxon Mobil Corporation (7)
| 71,935
| |||||||
J.M. (Jack) Mintz Palmer Chair in Public Policy for the University of Calgary (1)(3) | – | April 21, 2005 | Common shares of Imperial Oil Limited
| 1,000
| ||||
Deferred share units of Imperial Oil Limited
| 3,063
| |||||||
Restricted stock units of Imperial Oil Limited
| 8,500
| |||||||
Shares of Exxon Mobil Corporation
| 0
| |||||||
R.C. (Robert) Olsen Executive vice-president, ExxonMobil Production Company(2) | Chairman and production director, ExxonMobil International Limited, London, England | May 1, 2008 | Common shares of Imperial Oil Limited
| 3,000
| ||||
Deferred share units of Imperial Oil Limited
| 0
| |||||||
Restricted stock units of Imperial Oil Limited
| 0
| |||||||
Shares of Exxon Mobil Corporation (7)
| 267,554
|
(Table continued on followingnext page)
35
Name and current principal occupation or employment | Last major position or office
| Director since | Holdings (4)(5)(6) | |||||
R. (Roger) Phillips Retired president and chief executive officer, IPSCO Inc. (steel manufacturing) (1)(3) | – | April 23, 2002 | Common shares of Imperial Oil Limited
| 9,000
| ||||
Deferred share units of Imperial Oil Limited
| 17,736
| |||||||
Restricted stock units of Imperial Oil Limited
| 12,625
| |||||||
Shares of Exxon Mobil Corporation
| 2,000
| |||||||
P.A. (Paul) Smith Senior vice-president, finance and administration, and treasurer Imperial Oil Limited(3) | Controller and senior vice- president, finance and administration, Imperial Oil Limited, Calgary, Alberta | February 1, 2002 | Common shares of Imperial Oil Limited
| 13,059
| ||||
Deferred share units of Imperial Oil Limited
| 0
| |||||||
Restricted stock units of Imperial Oil Limited
| 181,850
| |||||||
Shares of Exxon Mobil Corporation | 1,662
| |||||||
S.D. (Sheelagh) Whittaker Corporate director(1)(3) | – | April 19, 1996 | Common shares of Imperial Oil Limited
| 9,000
| ||||
Deferred share units of Imperial Oil Limited
| 33,426
| |||||||
Restricted stock units of Imperial Oil Limited
| 12,625
| |||||||
Shares of Exxon Mobil Corporation
| 0
| |||||||
V.L. (Victor) Young Corporate director of several corporations(1)(3) | – | April 23, 2002 | Common shares of Imperial Oil Limited
| 11,250
| ||||
Deferred share units of Imperial Oil Limited
| 6,043
| |||||||
Restricted stock units of Imperial Oil Limited
| 12,625
| |||||||
Shares of Exxon Mobil Corporation | 0
|
Member of audit committee; member of executive resources committee; member of environment, health and safety |
(2) | Member of executive resources committee; member of environment health and safety committee; and member of nominations and corporate governance committee. |
(3) | Member of Imperial Oil Foundation board of |
(4) | 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. |
(5) | The company’s plans for |
(6) | The numbers for the company’s restricted stock units and deferred share units represent the total of the restricted stock units and deferred share units received in 2006, 2007 and |
B.H. March holds |
The ages of the directors, nominees for election as directors, and the five senior executivesnamed executive officers of the company are: Randy L.R.L. Broiles 50, Timothy J.51, C.W. Erickson 49, K.T. Hoeg 59, B.H. March 52, J.M. Mintz 57, R.C. Olsen 58, R. Phillips 69, P.A. Smith 55, S.M. Smith 51, S.D. Whittaker 61, V.L. Young 63. T.J. Hearn, 63, Krystyna T. Hoeg 58, Bruce H.who retired from the company on March 51, Jack M. Mintz 56, Roger Phillips 68, James F. Shepard 69, Paul A. Smith 54, Sheelagh D. Whittaker 60, Victor L. Young 62 and Brian W. Livingston 53.
3631, 2008 is 64.
Name | Other reporting issuers of which Director is also a director | |||
K.T. Hoeg | Sun Life Financial Inc. Shoppers Drug Mart Corporation Canadian Pacific Railway Limited Canadian Pacific Railway Company Cineplex Galaxy Income Fund | |||
J.M. Mintz | Brookfield Asset Management Inc. | |||
R. Phillips | Canadian Pacific Railway Company Canadian Pacific Railway Limited Cliffs Natural Resources Inc. The Toronto Dominion Bank | |||
V.L. Young | Bell Aliant Regional Communications Income Fund BCE Inc. Royal Bank of Canada |
All of the directors and nominees for election as directors, except for Krystyna T. Hoeg, Jack M. Mintz, James F. Shepard and Sheelagh D. Whittaker have been engaged for more than five years in their present principal occupations or in other executive capacities with the same firm or affiliated firms. During the five preceding years, Krystyna T. Hoeg was president and chief executive officer of Corby Distilleries Limited until she retired in February 2007, Jack M. Mintz was president and chief executive officer of The C.D. Howe Institute until he retired in July 2006 James F. Shepard became president and chief executive officer of Canfor Corporation in July 2007, and Sheelagh D. Whittaker was managing director of Electronic Data Systems until she retired in November 2005.
In addition to the named executive officers listed on page 37, the following table provides information on the senior executivesare also executive officers of the company as of February 14, 2008.
Name and office | Office held since | Age | ||||||
Sean R. Carleton Controller | February 1, 2008 | |||||||
Phil Dranse Assistant treasurer | August 1, 2008 | 55 | ||||||
Marvin E. Lamb Director, corporate tax | December 1, 2001 | 53 | ||||||
Brian W. Livingston Vice-president, general counsel and corporate secretary | August 1, 2004 | 54 |
All of the above senior executivesexecutive officers 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 executivesexecutive officers hold office until their appointment is rescinded by the board of 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: K.T. Hoeg, J.M. Mintz, R. Phillips, J.F. Shepard, S.D. Whittaker and V.L. Young, and J.M. Mintz.
Audit committee financial expert
The company’s board of directors has determined that K.T. Hoeg, 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 52-110Audit Committees, the Securities and Exchange Commission rules and the listing standards of the American Stock ExchangeNYSE Alternext 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 company’s ethics policy, conflicts of interest policy, corporate assets policy, directorships policy, and procedures and open door communication. Those documents are available at the company’s web site www.imperialoil.ca.
37
Named Executive Officers of the company’s compensation committee
The named executive officers of the company at the end of 2008 were:
B.H. (Bruce) March, Chairman, president and chief executive officer;
P.A. (Paul) Smith, Senior vice-president, finance and administration, and treasurer;
R.L. (Randy) Broiles, Senior vice-president, resources division;
C.W. (Chris) Erickson, Vice-president and general manager, refining and supply; and
S.M. (Simon) Smith, Vice-president and general manager, fuels marketing.
T.J. (Tim) Hearn was chairman and chief executive officer from January 1, 2008 until his retirement on March 31, 2008.
Senior Executive Compensation
The executive resources committee of the board of directors is composed of the five independent directors and R.C. Olsen, who is employed by ExxonMobil Production Company. The executive resources committee is responsible for corporate policy on compensation and for specific decisions on the compensation of the chief executive officer and key senior executives and officers reporting directly to that position. In addition to compensation matters, the committee is also responsible for succession plans and appointments to senior executive and officer positions, including the chief executive officer.
R.C. Olsen is not independent by virtue of his employment with ExxonMobil Production Company, which is a division of Exxon Mobil Corporation, which owns beneficially 596,357,122 common shares, representing 69.6 percent of the outstanding voting shares of the company. For that reason the company is a “controlled company”. During 2007,2008, the membership of the executive resources committee was as follows:
R. Phillips -Chair
V.L. Young -Vice-chair
K.T. Hoeg(since May 2008)
J.M. Mintz
R.C. Olsen(since July 2008)
J.F. Shepard
(until May 2008)
S.D. WhittakerJ.M. Mintz
B.H. March periodically attends meetings at the request of the committee.
Report of Executive Resources Committee Report on Executive Compensation
The Executive Resources Committee of the Board of Directors has reviewed and discussed the “Compensation Discussion and Analysis” for 2008 with management of the company. Based on that review and discussion, the committee recommended to the board that the “Compensation Discussion and Analysis” be included in the company’s management proxy circular for the 2009 annual meeting of shareholders.
Submitted on behalf of the executive resources committee:
R. Phillips - Chair | J.M. Mintz | |||
V.L. Young - Vice-chair | R.C. Olsen | |||
K.T. Hoeg | S.D. Whittaker |
Compensation Discussion and Analysis
Overview
Providing energy to meet Canada’s demands is a complex business. The company meets this challenge by taking a long-term view to managing its business rather than reacting to short-term business cycles. As such, the compensation program of the company aligns with this long-term business approach and key business strategies as outlined below.
Business Environment
Large capital expenditures with long investment periods;
Complex operating and financial risks;
National scope of company operations; and
Commodity-based cyclical product prices.
Key Business Strategies
Grow profitable sales volumes;
Disciplined, selective and long-term focus on improving the productivity of the company’s asset mix;
Flawless execution; and
Best-in-class cost structure to ensure industry-leading returns on capital and superior cash flow.
Focus on these key strategies for the business is a company priority and ensures long-term growth in shareholder value.
Key Elements of the Compensation Program
The key elements of the company’s compensation program and staffing objectives that support the business environment and key business strategies are:
long-term career orientation with high individual performance standards (see page 39);
base salary that rewards individual performance and experience (see page 39);
annual bonus grants based on business performance, as well as individual performance and experience (see pages 39 through 40);
payment of a large portion of executive compensation in the form of restricted stock units with lengthy vesting periods (see pages 40 through 41);
retirement benefits (pension and savings plans) that provide for financial security after employment (see pages 42 through 44).
The company’s executive compensation program is designed to to:
reinforce the company’s orientation toward career employment and individual performance. It acknowledgesperformance;
acknowledge the long-term nature of the company’s business andbusiness;
reinforce its philosophy that the experience, skill and motivation of the company’s executives are significant determinants of future business success. success; and
ensure alignment with long-term shareholder interests.
The compensation program emphasizes competitive salaries and performance-based incentives as the primary instruments to attract, develop and retain key personnel.
Other Supporting Compensation and Staffing Practices
A long established program of management development and succession planning is in place to reinforce a career orientation and ensure continuity of leadership.
All executives participate in common programs (the same salary, incentive and retirement programs). Within these programs, the compensation of executives is differentiated based on individual performance assessment, level of responsibility and individual experience. All senior executives on loan assignment from ExxonMobil participate in common programs, as well, which are administered by ExxonMobil.
Substantial amounts of executive compensation for the named executive officers are at risk of forfeiture, if the executive engages in activity that is detrimental to the company.
Inappropriate risk taking is discouraged by requiring senior executives to hold a substantial portion of their equity incentive award for their entire career and in some cases beyond retirement.
The use of perquisites at the company is limited, and mainly tied to financial planning for senior executives, and the use of club memberships is largely tied to building business relationships.
No tax assistance is provided by the company on any elements of executive officer compensation or perquisites other than relocation. The relocation program is broad-based and applies to all management, professional, technical and executive transferred employees.
Employee Appraisal and Ranking Process
The assessment of individual performance is conducted through the company’s employee appraisal program. Conducted annually, the appraisal process assesses performance against business performance measures and objectives relevant to each employee, including the means by which performance is achieved. ItThese business performance measures include:
total shareholder return;
net income;
return on capital employed;
cash distributed to shareholders;
safety, health, and environmental performance;
operating performance of the Upstream, Downstream, and Chemical segments;
business controls; and
effectiveness of actions that support the long-term, strategic direction of the company.
The ranking process, which is an integral part of the appraisal process, involves comparative rankingassessment of employee performance using a standard process throughout the organization and at all levels. The appraisal programprocess is integrated with the compensation program and also with the executive development process. Both have been in place for more than 50many years and are the basis for planning individual development and succession planning for management positions.
Compensation Program
Career Orientation
The company’s objective is to attract, develop and retain over a career the best talent available. It takes a long period of time and significant investment to develop the experienced executive talent necessary to succeed in the company’s business; senior executives must have experience with all phases of the executive resources committee relies on market comparisonsbusiness cycle to be effective leaders. The company’s compensation program elements reinforce the long term approach. Career orientation among a group of 25 major Canadian companiesdedicated and highly skilled workforce, combined 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 targetedhighest performance standards, contributes to a range between the mid-point and the upper quartile of comparable employers, reflecting the company’s emphasis on quality management.
Consistent with the company’s long-term career orientation, high-performing executives typically earn substantially higher levels of compensation in the final years of their careers than in the earlier years. This pay practice reinforces the importance of a long-term focus in making decisions that are key to business success.
Because the compensation program emphasizes individual experience and sustained performance, executives holding similar positions may receive substantially different levels of compensation.
The company’s executive compensation program is composed of base salaries, cash bonuses and medium/medium and long-term incentive compensation. The companydoes not have written employment contracts or any other agreement with its named executive officers providing for payments on change of control or termination of employment.
Base Salary
Salaries provide executives with a base level of income. The company’slevel of annual salary ranges for executives were increased by 2.5 percent in 2006is based on the executive’s responsibility, performance assessment and 8.0 percent in 2007 and 2008.career experience. The salary program in 2008 maintained the company’s competitive position on salaries in the marketplace. Individual salary increases vary depending on each executive’s performance assessment and other factors such as time in position and potential for advancement.
Annual Bonus
Annual bonuses are typically granted to approximately 8095 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 company’s financial and operating performance.performance, and can be highly variable depending on annual financial and operating results.
In setting the size of the annual bonus pool and individual executive awards, the executive resources committee:
considers input from the chairman, president and chief executive officer on the performance of the company and from the company’s internal compensation advisors regarding compensation trends as obtained from external consultants;
considers annual net income of the company and other key business performance indicators as described on page 38; and
uses judgment to manage the overall size of the annual bonus pool taking into consideration the cyclical nature and long-term orientation of the business.
The 2008 annual bonus pool was $11.9 million versus $12.8 million in 2007. This reflects the combined value at grant of annual cash bonus and earnings bonus units. Given the mix of participants, in 2008, the overall bonus pool generally remained the same aswas slightly lower than the previous year, and continuesbut continued to reflect improved financial results and operating performance. In relation to this, the company’s net income for 20072008 was a record $3.188$3.9 billion (up 522 percent), return on shareholders’ equity was 4246 percent, return on capital employed was 3845 percent and total annual shareholders’ return was 28-24.3 percent. Changes in individual cash bonus awards vary depending on each executive’s performance assessment.
The annual bonus program incorporates unique elements to further reinforce retention and recognize performance. Awards under this program are generally delivered as:
50 percent cash paid in the year of grant; and
50 percent earnings bonus units with a delayed payout based on cumulative earnings performance.
The cash component is intended to be a short-term incentive, compensation plan, calledwhile the earnings bonus unit plan was introduced in 2001 and continues today. This plan is intended to be a medium-term incentive. Earnings bonus units are made available to selected executives to promote individual contribution to sustained
38
Specifically, earnings bonus units are cash awards that are tied to approximately 80 executives annually. Infuture cumulative earnings per share. Earnings bonus units pay out when a specified level of cumulative earnings per share is achieved or within five years, whichever is earlier.
For earnings bonus units granted in 2008, the maximum settlement value (trigger) or cumulative earnings per share required for payout was increased to $2.75 per unit versus $2.25 in 2007, eachto reinforce the company’s
principle of continuous improvement in business performance and to reflect the reduction in the number of outstanding shares pursuant to the company’s share purchase program. The trigger of $2.75 is intentionally set at a level that is expected to be achieved within the five-year period.
If cumulative earnings per share did not reach $2.75 within five years, the payment with respect to the earnings bonus unit entitles the recipientwould be reduced to receive an amount equal to the company’snumber of units times the actual cumulative net earnings per common share as announced each quarter beginning afterover the grant. Payout occurs afterperiod.
The annual bonus includes the fifth anniversarycombined value of the grant, or when the maximum settlement value per unit is reached, if earlier. If after five years the maximum payout has not been reached, payout will be prorated. In 2007, similar to the cash bonus pool,and delayed earnings bonus unit portion and is intended to be competitive with the annual bonus awards of other major comparator companies adjusted to reflect the company’s performance relative to its comparators. The earnings bonus units are designed such that the timing of the payout is tied to the rate of the company’s future earnings; however, it is not intended to vary the amount of the award based on future earnings. In so doing, the delayed portion of the annual bonus, that is the earnings bonus unit, puts part of the annual bonus at risk of forfeiture and thus reinforces the performance basis of the annual bonus grant.
Prior to payment, the earnings bonus units pool generally remainedmay be forfeited if the same asexecutive leaves the previous year.
Long-Term Incentive Compensation
Restricted Stock Units
In December 2002, the company introduced a restricted stock unit plan, which is the company’s primary long-term incentive compensation plan. The purposeGiven the long-term nature of the plancompany’s business, granting compensation in the form of restricted stock units with long vesting periods keeps executives focused on the key premise that decisions made today affect the performance of the organization and company stock for many years to come. This practice supports a risk/reward model that reinforces a long-term view, which is critical to align the company’s business success, and discourages inappropriate risk taking. The amount granted is intended to provide an incentive to promote individual contribution to the company’s performance and motivation to remain with the company. The amount is computed by reference to the most recent ranking of performance as an indication of future potential, but may also consider an adjustment at time of grant, if near term performance is deemed to have changed significantly at time of grant. This type of compensation removes employee discretion in the exercise of restricted stock units and ensures alignment with the long-term interests of selected employeesshareholders and nonemployee directors directly withreinforces retention objectives. The company does not re-price restricted stock awards. The utilization of restricted stock units, instead of stock options, and the interestsdetermination of shareholders. annual grants on a share-denominated versus price basis help reinforce this practice. Restricted stock units are not included in pension calculations.
The restricted stock unit plan is a straightforward, primarily cash-based approach to long-term incentive compensation.
In 2006, the guidelines were reviewed in light of the company’s three-for-one share split. Given the significant appreciation in the company’s share price over the previous several years, restricted stock unit guidelines were adjusted on a two-for-one basis rather than the three-for-one share split. This had the effect of reducing grant values in 2006 and 2007 compared to earlier years.
Exercise of Restricted Stock Units and Amendments to the Restricted Stock Unit Plan
Restricted stock units will be exercised only during employment except in the event of death, disability or retirement. Restricted stock units cannot be assigned. In the case of any subdivision, consolidation, or reclassification of the shares of the company or other relevant change in the capitalization of the company, the company, in its discretion, may make appropriate adjustments in the number of common shares to be issued and the calculation of the cash amount payable per restricted stock unit.
Each restricted stock unit granted in 2007 entitles the recipient the right to receive from the company, upon exercise, an amount equal to the five day average of the closing price of the company’s shares precedingon the exercise dates.date and the four preceding trading days. 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 payswill 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.
There are 7,928,818 common shares that may be issued in the future with respect to outstanding restricted stock units including 95 executives.
39
Annual Compensation | Long-Term Compensation | |||||||||||||||||||||||||||||||||||||||||||||||||||
Awards | Payouts | |||||||||||||||||||||||||||||||||||||||||||||||||||
Shares or | Shares or | |||||||||||||||||||||||||||||||||||||||||||||||||||
Securities | Units | Units | ||||||||||||||||||||||||||||||||||||||||||||||||||
Under | Subject to | Subject to | ||||||||||||||||||||||||||||||||||||||||||||||||||
Name and | Other Annual | Options/ | Resale | Resale | LTIP | All Other | Total | |||||||||||||||||||||||||||||||||||||||||||||
Principal | Bonus | Compensation | SARs | Restrictions | Restrictions | Payouts | Compensation | Compensation | ||||||||||||||||||||||||||||||||||||||||||||
Position at the | Salary | (2) | (3) | Granted (4) | (5) (6) | (5) (6) | (7) | (8) | (9) | |||||||||||||||||||||||||||||||||||||||||||
end of 2007 | Year | ($) | ($) | ($) | (#) | (#) | ($) | ($) | ($) | ($) | ||||||||||||||||||||||||||||||||||||||||||
T.J. Hearn | 2007 | 1,200,000 | 1,000,050 | 671,855 | – | 130,000 | 6,464,900 | 999,950 | 36,000 | 10,372,755 | ||||||||||||||||||||||||||||||||||||||||||
Chairman, | restricted | |||||||||||||||||||||||||||||||||||||||||||||||||||
president and | stock units | |||||||||||||||||||||||||||||||||||||||||||||||||||
chief executive | 2 | 109 | ||||||||||||||||||||||||||||||||||||||||||||||||||
officer | deferred | |||||||||||||||||||||||||||||||||||||||||||||||||||
2006 | 1,140,000 | 1,000,050 | 562,665 | – | share units 130,000 | 5,623,800 | 900,000 | 34,200 | 9,260,801 | |||||||||||||||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2 | 86 | |||||||||||||||||||||||||||||||||||||||||||||||||||
deferred share units | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2005 | 1,100,000 | 900,000 | 385,028 | – | 193,200 | 7,432,404 | 870,000 | 33,000 | 10,720,526 | |||||||||||||||||||||||||||||||||||||||||||
restricted stock | ||||||||||||||||||||||||||||||||||||||||||||||||||||
units | ||||||||||||||||||||||||||||||||||||||||||||||||||||
3 | 115 | |||||||||||||||||||||||||||||||||||||||||||||||||||
deferred share units | ||||||||||||||||||||||||||||||||||||||||||||||||||||
P.A. Smith | 2007 | 412,500 | 181,233 | 125,486 | – | 27,200 | 1,352,656 | 197,225 | 24,750 | 2,293,850 | ||||||||||||||||||||||||||||||||||||||||||
Controller and | restricted | |||||||||||||||||||||||||||||||||||||||||||||||||||
senior | stock units | |||||||||||||||||||||||||||||||||||||||||||||||||||
vice-president, | 2006 | 404,167 | 197,267 | 111,279 | – | 35,100 | 1,518,426 | 193,050 | 24,250 | 2,448,439 | ||||||||||||||||||||||||||||||||||||||||||
finance and | restricted | |||||||||||||||||||||||||||||||||||||||||||||||||||
administration | stock units | |||||||||||||||||||||||||||||||||||||||||||||||||||
2005 | 398,333 | 193,675 | 87,198 | – | 55,200 restricted | 2,123,544 | 193,125 | 23,900 | 3,019,775 | |||||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||||||||||||||
R.L. Broiles (1) | 2007 | U.S. 345,000 | U.S. 159,000 | U.S. 206,336 | – | 11,000 | U.S. 967,120 | U.S. 159,265 | U.S. 22,950 | U.S. 1,859,671 | ||||||||||||||||||||||||||||||||||||||||||
Senior | restricted | |||||||||||||||||||||||||||||||||||||||||||||||||||
vice-president, | shares | |||||||||||||||||||||||||||||||||||||||||||||||||||
resources division | 2006 | U.S. 325,083 | U.S. 159,200 | U.S. 421,481 | – | 11,000 | U.S. 815,760 | U.S. 140,513 | U.S. 21,705 | U.S. 1,883,742 | ||||||||||||||||||||||||||||||||||||||||||
(from July 1, 2005) | restricted | |||||||||||||||||||||||||||||||||||||||||||||||||||
shares | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2005 | U.S. 159,000 | U.S. 140,500 | U.S. 112,214 | – | 11,000 | U.S. 641,740 | U.S. 116,253 | U.S. 10,175 | U.S. 1,179,882 | |||||||||||||||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||||||||||||||
shares | ||||||||||||||||||||||||||||||||||||||||||||||||||||
B.W. Livingston | 2007 | 342,916 | 157,574 | 75,274 | – | 22,000 | 1,094,060 | 158,900 | 10,287 | 1,839,011 | ||||||||||||||||||||||||||||||||||||||||||
Vice-president, | restricted | |||||||||||||||||||||||||||||||||||||||||||||||||||
general counsel | stock units | |||||||||||||||||||||||||||||||||||||||||||||||||||
and corporate | 2006 | 318,750 | 159,088 | 83,236 | – | 22,000 | 951,720 | 153,450 | 9,562 | 1,675,806 | ||||||||||||||||||||||||||||||||||||||||||
secretary | restricted | |||||||||||||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2005 | 303,750 | 154,330 | 66,401 | – | 33,000 | 1,269,510 | 128,625 | 9,112 | 1,931,648 | |||||||||||||||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||||||||||||||
J.F. Kyle | 2007 | 366,166 | 122,083 | 103,405 | – | 19,000 | 944,870 | 119,000 | 21,970 | 1,677,494 | ||||||||||||||||||||||||||||||||||||||||||
Vice-president | restricted | |||||||||||||||||||||||||||||||||||||||||||||||||||
and treasurer | stock units | |||||||||||||||||||||||||||||||||||||||||||||||||||
2006 | 365,000 | 119,145 | 124,081 | – | 20,800 | 899,808 | 112,500 | 21,900 | 1,642,434 | |||||||||||||||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||||||||||||||
stock units | ||||||||||||||||||||||||||||||||||||||||||||||||||||
2005 | 364,166 | 112,500 | 90,821 | – | 33,900 | 1,304,133 | 171,375 | 21,850 | 2,064,845 | |||||||||||||||||||||||||||||||||||||||||||
restricted | ||||||||||||||||||||||||||||||||||||||||||||||||||||
stock units |
40
Restricted Stock Units | Deferred Share Units | |||||||||||||
Name | Total (#) | Total ($) | Total (#) | Total ($) | ||||||||||
T.J. Hearn | 714,800 | 39,042,376 | 306 | 16,714 | ||||||||||
P.A. Smith | 190,250 | 10,391,455 | 0 | 0 | ||||||||||
R.L. Broiles | – | – | – | – | ||||||||||
B.W. Livingston | 119,750 | 6,540,745 | 0 | 0 | ||||||||||
J.F. Kyle | 126,500 | 6,909,430 | 0 | 0 | ||||||||||
41
On February 26, 2008, the restricted stock unit plan is described in more detail on page 44.
Performance | |||||||||||||||||
Securities | or Other | Estimated Future Payouts Under | |||||||||||||||
Name | Units or | Period Until | Non-Securities-Price Based Plans | ||||||||||||||
Other Rights | Maturation or | ||||||||||||||||
(#) | Payout (1) | Threshold | Target | Maximum | |||||||||||||
($) | ($) (2) | ($) (2) | |||||||||||||||
T.J. Hearn | 444,400 | Nov 20, 2012 | 0 | 2.25 | 2.25 | ||||||||||||
P.A. Smith | 80,500 | Nov 20, 2012 | 0 | 2.25 | 2.25 | ||||||||||||
R.L. Broiles (3) | – | – | – | – | – | ||||||||||||
B.W. Livingston | 70,000 | Nov 20, 2012 | 0 | 2.25 | 2.25 | ||||||||||||
J.F. Kyle | 54,200 | Nov 20, 2012 | 0 | 2.25 | 2.25 | ||||||||||||
Securities | Aggregate | Unexercised | Value of | |||||||||||||||||
Acquired | Value | Options/SARs | Unexercised | |||||||||||||||||
Name | on Exercise | Realized | at Financial | in-the-Money | ||||||||||||||||
(#) | ($) | Year End | Options/SARs | |||||||||||||||||
(#) | at Financial | |||||||||||||||||||
Year End | ||||||||||||||||||||
($) | ||||||||||||||||||||
Exercisable | Unexercisable | Exercisable | Unexercisable | |||||||||||||||||
(1) | (1) | |||||||||||||||||||
T.J. Hearn | – | 2,711,250 | 0 | 0 | 0 | 0 | ||||||||||||||
P.A. Smith | – | 596,100 | 120,000 | 0 | 5,115,900 | 0 | ||||||||||||||
R.L. Broiles | – | – | – | – | – | – | ||||||||||||||
B.W. Livingston | – | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
J.F. Kyle | – | 0 | 0 | 0 | 0 | 0 | ||||||||||||||
42
Securities | Aggregate | Unexercised | Value of | |||||||||||||||||
Acquired | Value | Options/SARs | Unexercised | |||||||||||||||||
Name | on Exercise | Realized | at Financial | in-the-Money | ||||||||||||||||
(#) (1) | ($) | Year End | Options/SARs | |||||||||||||||||
(#) (1) | at Financial | |||||||||||||||||||
Year End ($) | ||||||||||||||||||||
Exercisable | Unexercisable | Exercisable | Unexercisable | |||||||||||||||||
(2) | (2) | |||||||||||||||||||
T.J. Hearn | 10,002 | 296,272 | 154,998 | 0 | 6,063,522 | 0 | ||||||||||||||
P.A. Smith | – | – | 75,000 | 0 | 2,934,000 | 0 | ||||||||||||||
R.L. Broiles (3) | – | – | – | – | – | – | ||||||||||||||
B.W. Livingston | 15,000 | 512,255 | 30,000 | 0 | 1,173,600 | 0 | ||||||||||||||
J.F. Kyle | 57,000 | 1,790,530 | 0 | 0 | 0 | 0 | ||||||||||||||
Effective May 1, 2008, the restricted stock unit plan was amended by the company to include an additional vesting period option for 50 percent of restricted stock units to vest on the fifth anniversary of the date of grant, with the remaining 50 percent of the grant to vest on the later of the tenth anniversary of the date of grant or the date of retirement of the grantee. The recipient of such restricted stock units may receive one common share of the company each year.
In respect of restricted stock units granted in 2008:
to the chairman, president and chief executive officer:
50 percent of each grant is exercisable on the fifth anniversary of the date of grant; and
the balance is exercisable on the later of the tenth anniversary of the date of grant date. Incentive shareor the date of retirement; and
to all other senior executives:
50 percent of each grant is exercisable on the third anniversary of the date of grant; and
the balance is exercisable on the seventh anniversary of the date of grant.
The long vesting periods, which are longer than those in use by many other companies, reinforce the company’s focus on growing shareholder value over the long term by subjecting a large percentage of executive compensation and the personal net worth of senior executives to the long term return on the company’s stock realized by shareholders. The vesting period for restricted stock unit awards is not subject to acceleration, except in the case of death.
Forfeiture Risk
Restricted stock units are eligible for exercise upsubject to 10 years from issuance.forfeiture if:
A recipient retires or terminates employment with the company. The company has indicated its intention not to forfeit restricted stock units of employees who retire at age 65. In other circumstances, where a recipient retires or terminates employment, the company may determine that restricted stock units shall not be forfeited.
During employment or during the period of 24 months after the termination of employment, the recipient, 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.
Deferred Share Units
In 1998, an additional form of long-term incentive compensation (“deferred share units”) was made available to nonemployee directors (as described on pages 50 through 51) and to selected executives and nonemployee directors whose decisions are considered to have a direct effect on the long term financial performance of the company. TheyThe selected executives 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 executive’s bonus elected to be received as deferred share units by the average of the closing prices of the company’s shares on the Toronto Stock Exchange for the five consecutive trading days (“average closing price”) immediately prior to the date that the bonus would have been paid to the executive. Additional units will be granted to recipients of these units, in respect of unexercised units, based on the cash dividend payable on the company shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient.
An executive may not exercise these units until after termination of employment with the company and must exercise the units no later than December 31 of the year following termination of employment with the company. The units held must all be exercised on the same date. On the date of exercise, the cash value to be received for the units will be determined by multiplying the number of units exercised by the average closing price immediately prior to the date of exercise. In 2007,2008, no executive elected to receive deferred share units.
The deferred share unit plan was amended on November 20, 2008 to provide that for U.S. taxpayers, subject to the United States Internal Revenue Code, Section 409A, for units earned after December 31, 2004, the exercise date must not be later than five months after the date of termination of employment and the date for the cash payment from the plan will be six months after the date of termination of employment.
Retirement Benefits
Named executive officers participate in the same pension plan, including supplemental retirement income provisions, as other employees. B.H. March, R.L. Broiles and C.W. Erickson participate in the Exxon Mobil Corporation pension plans (both tax-qualified and nonqualified).
Pension Plan Benefits
The following table sets forth the estimated annual benefits that would be payable to each named executive officer of the company upon retirement under the company’s pension plan and supplemental retirement income provisions and Exxon Mobil Corporation’s tax qualified and non-qualified pension plans, and the change in the accrued obligation for each named executive officer of the company in 2008.
Name | Number of years credited service December 31, 2008 (#) | Annual benefits payable ($) | Accrued ($) (5) | Compensatory ($) (6) | Non-compensatory ($) (7) | Accrued ($) (8) | ||||||||
At year end (3)
| At age
| |||||||||||||
B.H. March(1) | – | – | – | – | – | – | – | |||||||
P.A. Smith(2) | 28.9 | 365,100 | 482,800 | 3,624,900 | (13,100) | (573,100) | 3,038,700 | |||||||
R.L. Broiles(1) | – | – | – | – | – | – | – | |||||||
C.W. Erickson(1) | – | – | – | – | – | – | – | |||||||
S.M. Smith(2) | 27.1 | 308,200 | 464,800 | 2,752,100 | 350,200 | (591,900) | 2,510,400 | |||||||
T.J. Hearn (2) (9) (retired from the company on | 41.6 | 97,200 | 97,200 | 24,482,600 | 124,200 | (23,586,200) | 1,020,600 |
(1) | Member of the Exxon Mobil Corporation pension plans, including tax qualified and non-qualified plans. As of December 31, 2008, B.H. March had 28.5 years of credited service, R.L. Broiles had 29.6 years and C.W. Erickson had 27.5 years. All amounts referenced were converted from U.S. dollars to Canadian dollars at the average 2008 exchange rate of 1.066. |
(2) | Member of the company pension plan as supplemented by payments from the company. |
(3) | For members of the company pension plan, the annual benefits include the amount of the accrued annual lifetime pension from the company’s registered pension plan and supplemented by payments from the company. For members of the Exxon Mobil Corporation pension plans, the annual benefits include the accrued annual lifetime pension from the Exxon Mobil Corporation tax qualified plan and the accrued annual amount calculated under the Exxon Mobil Corporation non-qualified plan. Non-qualified plan benefits are payable only as a lump sum equivalent upon retirement. For B.H. March, this value was $379,281, for R.L. Broiles, this value was $331,911 and for C.W. Erickson, this value was $311,141. |
(4) | For members of the company pension plan, the annual benefits include the amount of the accrued annual lifetime pension from the company’s registered pension plan and supplemented by payments from the company that would be earned to age 65 assuming final average earnings as at December 31, 2008. For members of the Exxon Mobil Corporation pension plan, the annual benefits include the annual lifetime pension from Exxon Mobil Corporation’s tax qualified plan and the annual amount calculated under the Exxon Mobil Corporation non-qualified plans that would be earned to age 65 assuming final average earnings as at December 31, 2008. Non-qualified plan benefits are payable only as a lump sum equivalent upon retirement. For B.H. March, this value was $550,374, for R.L. Broiles, this value was $486,517 and for C.W. Erickson, this value was $493,350. |
(5) | For members of the company’s pension plan, the “Accrued obligation at start of year” is defined for purposes of Financial Accounting Standard 87 (FAS 87) and is calculated based on earnings eligible for pension as described on page 43 and Yearly Maximum Pensionable Earnings (YMPE) as defined by the Canada Revenue Agency, projected to retirement and pro-rated on service to the date of valuation, December 31, 2007. The calculations assume that the Canada Pension Plan offset is based on the annual maximum benefit at retirement and the Old Age Security (OAS) offset is based on the OAS benefit in the fourth quarter of 2007 projected to retirement. For members of the Exxon Mobil Corporation pension plans, the “Accrued obligation at start of year” is defined for purposes of FAS 87 and is calculated based on earnings eligible for pension as described on page 43. The calculations assume that the U.S. Social Security offset against the Exxon Mobil Corporation qualified plan benefit is calculated on the basis of the Social Security law in effect as of year end 2007. For B.H. March, this value was $2,448,424, for R.L. Broiles, this value was $2,295,189 and for C.W. Erickson, this value was $1,793,459. |
(6) | The value for “Compensatory change” includes service cost for 2008. Service cost for 2008 is calculated by using the individual’s additional pensionable service in 2008 and the actual salary and bonus received in 2008 as described on page 43. There were no plan amendments in 2008 that affected these benefits. The service cost is calculated on a basis that is consistent with FAS 87 and with the valuation that was performed as at that date for accounting purposes for the plan as a whole. For B.H. March, this value was $611,774, for R.L. Broiles, this value was $254,286 and for C.W. Erickson, this value was $234,192. |
(7) | The value for “Non-compensatory change” includes impact of experience not related to earnings, benefit payments and change in measurement assumptions. With respect to the company pension plan, the discount rate used to determine the accrued obligation at the end of 2008 increased to 7.50 percent, up from 5.75 percent at the end of 2007, thereby causing the Non-compensatory change to be negative. For members of the Exxon Mobil Corporation pension plans, the value for “Non-compensatory change” includes the impact of experience not related to earnings or service. This includes the effect of interest, based on a discount rate of 6.25 percent in each year, and operation of the plan’s rules for converting annuities to lump sums upon retirement. For B.H. March, this value was $355,560, for R.L. Broiles, this value was $296,220 and for C.W. Erickson, this value was $73,612. |
(8) | For members of the company’s pension plan, the “Accrued obligation at year end” is defined for purposes of FAS 87 and is calculated based on earnings eligible for pension as described on page 43 and YMPE, projected to retirement and pro-rated on service to the date of valuation, December 31, 2008. The calculations assume that the Canada Pension Plan offset is based on the annual maximum benefit at retirement and the OAS offset is based on the OAS benefit in the fourth quarter of 2008 projected to retirement. For members of the Exxon Mobil Corporation pension plans, the “Accrued obligation at year end” is defined for purposes of FAS 87 and is calculated based on earnings eligible for pension as described on page 43. The calculations assume that the U.S. Social Security offset against the Exxon Mobil Corporation qualified plan benefit is calculated on the basis of the Social Security law in effect as of year end 2008. For B.H. March, this value was $3,415,757, for R.L. Broiles, this value was $2,845,696 and for C.W. Erickson, this value was $2,101,262. |
(9) | T.J. Hearn retired on March 31, 2008. At retirement, T.J. Hearn was provided the standard election option to receive his supplemental retirement income as a monthly annuity or a lump sum. T.J. Hearn exercised his option to receive the benefit as a lump sum. The change in non-compensatory obligation was adjusted accordingly. |
The registered pension plan and supplemental retirement income provisions provide an annual benefit of 1.6 percent of earnings per each year of service with respect to the named executive officers, with an offset for government benefits. Earnings, for this purpose, include average base salary during the last 36 consecutive months of service prior to retirement or the highest consecutive three calendar years of earnings in the last 10 years of service prior to retirement and the average annual bonus for the highest three of the last five years prior to retirement for eligible executives, but do not include long-term compensation, including restricted stock units. By limiting inclusion of bonuses in pensionable earnings to those granted in the five years prior to retirement, there is a strong motivation for executives to continue to perform at a high level. Annual bonus includes the cash amounts that are paid at grant, any cash amount deferred as described on pages 39 through 40 and the value of any earnings bonus units received, as described on pages 39 through 40. The aggregate maximum settlement value that could be paid for earnings bonus units is included in the employee’s final three year average earnings for the year of grant of such units. The portion of annual bonus deferred, and the value of earnings bonus units, are not intended to be at risk and, therefore, are included for pension purposes in the year of grant rather than the year of payment. An employee may also elect to forego three of the six percent of the company’s contributions to the savings plan under one of the options of that plan (except for B.H. March, R.L. Broiles and C.W. Erickson), to receive additional pension value equal to 0.4 percent of the employee’s “final three year average earnings”, multiplied by the employee’s 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 remuneration used to determine the payments on retirement to the individuals named in the summary compensation table on page 47 corresponds generally to the salary, bonus and earnings bonus units received in the current year, as described in the previous paragraph. As of February 13, 2009, the number of completed years of service with Imperial Oil Limited used to determine payments on retirement was 29 for P.A. Smith and 27 for S.M. Smith. T.J. Hearn retired from the company on March 31, 2008 with 41 completed years of service.
B.H. March, R.L. Broiles and C.W. Erickson are not members of the company’s pension plan, but are members of Exxon Mobil Corporation’s pension plans. Under those plans, B.H. March has 28 years of credited service, R.L. Broiles has 29 years of credited service and C.W. Erickson has 27 years of credited service. Their respective pensions are payable in U.S. dollars. Pay for the purpose of the pension calculation is based on final average base salary over the highest 36 consecutive months in the 10 years of service prior to retirement, and the average annual bonus for the three highest grants out of the last five grants prior to retirement.
Savings Plan Benefits
The company maintains a savings plan into which career employees with more than one year of service may contribute between one and 30 percent of normal earnings. The company provides equal matching contributions to a maximum of six percent when an employee participates in the pre-1998 historic 1.6 percent defined-benefit pension arrangement. The current version of the historic 1.6 percent defined benefit plan has been in place since 1976; predecessor plans have been in place since 1919. All named executive officers are members of the historic 1.6 percent plan, except for B.H. March, R.L. Broiles and C.W. Erickson who participate in the Exxon Mobil Corporation savings plan and tax qualified and non-qualified pension plans. An employee may also elect to forego three of the six percent of the company’s contributions to the savings plan to receive additional pension value equal to 0.4 percent of the employee’s “final three year average earnings”, multiplied by the employee’s years of service, while foregoing such company contributions (except for B.H. March, R.L. Broiles and C.W. Erickson). T.J. Hearn elected to forego three of the six percent of the company’s contribution to the savings plan in order to receive this additional pension value.
Employee and company contributions can be allocated in any combination to a non-registered (tax-paid) account or a registered (tax-deferred) group retirement savings plan (RRSP) account, subject in the latter case to contribution limits under the Income Tax Act.
Available investment options include cash savings, a money market mutual fund, a suite of four index-based mutual funds and company shares. Company matching contributions must be allocated to company shares initially, and remain in that investment for a minimum of 24 months, after which they can be redeemed in favour of the other investment options.
During employment, withdrawals are only permitted from employee contributions and investment earnings within the tax-paid account, to a maximum of three withdrawals per year. Assets in the RRSP account, and company contributions to the tax-paid account, may only be withdrawn upon retirement or termination of employment, reinforcing the company’s long-term approach to total compensation. Income Tax regulations require RRSP’s to be closed by the end of the year in which the individual reaches age 71.
Named Executive Officer Compensation
Compensation Decision Making Process and Considerations
Benchmarking
In addition to the assessment of business performance, individual performance and level of responsibility, 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. Canadian companies are selected on the basis of being large in scope and complexity, capital intensive and proven sustainability. The 25 companies benchmarked are as follows:
Comparator Companies - Named Executive Officers | ||||
Agrium Inc. | EnCana Corporation | Procter & Gamble Inc. | ||
BCE Inc. | General Electric Canada | Royal Bank of Canada | ||
BP Canada Energy Company | Husky Energy Inc. | Shell Canada Limited | ||
Canadian Tire Corporation Limited | IBM Canada Ltd. | Suncor Energy Inc. | ||
Chevron Canada Limited | Irving Oil Limited | Talisman Energy Inc. | ||
Canadian Natural Resources Limited | Lafarge Canada Inc. | TransCanada Corporation | ||
ConocoPhillips Canada | Nexen Inc. | Vale Inco Limited | ||
Canadian Pacific Railway Limited | Nova Chemicals Corporation | |||
Enbridge Inc. | Petro-Canada |
The company is a national employer drawing from a wide range of disciplines. It is important to understand its competitive position relative to a variety of oil and non-oil employers. Annual market comparisons, based on survey data, are prepared by independent external compensation consultant, Towers Perrin, with additional analysis and recommendation provided by the company’s internal compensation advisors. Consistent with the executive resources committee’s practice of using well-informed judgment rather than formulae to determine executive compensation, the committee does not target any specific percentile among comparator companies to align compensation. Rather, on a case-by-case basis, depending on the scope of market coverage represented by a particular comparison, total compensation (excluding perquisites) is targeted to a range between the mid-point and the upper quartile of comparable employers, reflecting the company’s emphasis on quality management. This approach applies to salaries and the annual bonus.
As a secondary source of data, the company also considers a comparison with Exxon Mobil Corporation, when it determines the annual bonus program. For the restricted stock unit program, the executive resources committee also reviews a summary of data for a subset of the comparator companies provided by the same external consultant above, in order to assist in assessing total value of long-term compensation grants. This approach provides the company with the ability to better respond to changing business conditions, manage salaries based on a career orientation, minimize potential for automatic increasing of salaries, which could occur with an inflexible and narrow target among benchmarked companies, and finally to differentiate salaries based on performance and experience levels among executives.
The elements of the ExxonMobil compensation program, that include salary and annual bonus and equity (long-term) compensation considerations for B.H. March, R.L. Broiles and C.W. Erickson, are similar to those of the company. The data used for long-term compensation determination for B.H. March is as described above, as he received Imperial Oil Limited restricted stock units in 2008. The executive resources committee reviews and approves recommendations for each named executive officer prior to implementation. B.H. March’s compensation determination is described in more detail on pages 45 through 46.
2008 Named Executive Officer Compensation Assessment
When determining the annual compensation for the named executive officers, the executive resources committee has reflected on the following business performance result indicators in its determination of 2008 salary and incentive compensation.
Business Performance Results for Consideration
The operating and financial performance measurements listed below and the company’s continued maintenance of sound business controls and a strong corporate governance environment formed the basis for the salary and incentive award decisions made by the executive resources committee in 2008. The executive resources committee considered the results over multiple years, in recognition of the long-term nature of the company’s business.
Total shareholder return of about -24 percent. Ten-year annual average of about 19 percent.
Record earnings of $3.9 billion. Five-year annual average earnings of $3.0 billion.
Strong results in 1999,the areas of safety, health, and environment.
Industry-leading return on average capital employed of 45 percent, with an average of 30 percent since the beginning of 2000.
$330 million distributed to shareholders as dividends in 2008.
$2.2 billion distributed to shareholders through the share purchase program in 2008 and $15 billion since 1995.
Effective business controls and corporate governance.
Performance Assessment Considerations
The above results form the context in which the committee assesses the individual performance of each senior executive, taking into account experience and level of responsibility.
Annually, the chairman, president and chief executive officer reviews the performance of the senior executives in achieving business results and individual development needs.
The same long-term business strategies noted on page 37 and results on page 45 are key elements in the assessment of the chairman, president and chief executive officer’s performance by the executive resources committee.
The performance of all named executive officers is also assessed by the board of directors throughout the year during specific business reviews and board committee meetings that provide reports on strategy development; operating and financial results; safety, health, and environmental results; business controls; and other areas pertinent to the general performance of the company.
The executive resources committee does not use quantitative targets or formulae to assess executive performance or determine compensation. The executive resources committee does not assign weights to the factors considered. Formula-based performance assessments and compensation typically require emphasis on two or three business metrics. For the company to be an industry leader and effectively manage the technical complexity and integrated scope of its operations, most senior executives must advance multiple strategies and objectives in parallel, versus emphasizing one or two at the expense of others that require equal attention.
Senior executives and officers are expected to perform at the highest level or they are replaced. If it is determined that another executive is ready and would make a stronger contribution than one of the current incumbents, a replacement plan is implemented.
2008 CEO Compensation Assessment
B.H. March was elected chairman, president and chief executive officer of the company on April 1, 2008. Mr. March is a 29-year veteran of ExxonMobil, including service with heritage Mobil Corporation before the merger with Exxon Corporation on November 30, 1999. Mr. March has extensive operating and management experience in the oil and gas business, including assignments in multiple locations in the United States, as well as experience working in London and Brussels. His level of salary was determined by the executive resources committee based on his individual performance and to align with that of his peers in ExxonMobil. It was also the objective of the executive resources committee to ensure appropriate internal alignment with senior management in the company. The committee also approved a salary increase of $35,000 U.S. to $485,000 U.S., effective January 1, 2009.
Mr. March’s 2008 annual bonus was based on his performance as assessed by the executive resources committee since his assignment to the position of chairman, president and chief executive officer. His long-term incentive award was paid in the form of company restricted stock units, not ExxonMobil restricted stock, to reinforce alignment of his interests with that of the company’s shareholders. His company restricted stock units are subject to vesting periods longer than those applied by most companies conducting business in Canada. Fifty percent of the restricted stock units awarded vest in five years and the other 50 percent vest on the later of 10 years from the date of grant or the date of retirement. The purpose of these long vesting periods is to reinforce the long investment lead times in the business and to link a substantial portion of Mr. March’s net worth to the performance of the company. During these vesting periods, the awards are subject to risk of forfeiture based on detrimental activity, or if Mr. March should leave the company before normal retirement.
The executive resources committee has determined that the overall compensation of Mr. March is appropriate based on the company’s financial and operating performance and their assessment of his effectiveness in leading the organization. Key factors considered by the committee in determining his overall compensation level include continuing progress on advancing key strategic interests, financial results, safety metrics, environmental performance, government relations, productivity, cost effectiveness and asset management. The committee’s decisions reflect judgment, taking all factors into consideration, rather than the application of formulas or targets. The higher level of
pay for Mr. March, compared to the other named executive officers reflects his greater level of responsibility, including his ultimate responsibility for the performance of the company, and oversight of the other senior executives.
Pay Awarded to Other Named Executive Officers
Within the context of the compensation program structure and performance assessment processes described above, the value of 2008 incentive awards and salary adjustments align with:
performance of the company;
individual performance;
long-term strategic plan of the business; and
annual compensation of comparator companies.
The executive resources committee’s decisions reflect judgment taking all factors into consideration, rather than application of formulae or targets. The executive resources committee approved the individual elements of compensation and the total compensation as shown in the summary compensation table on page 47.
Independent Consultant
In fulfilling its responsibilities during 2008, the executive resources committee retained one independent consultant to assist in determining compensation for senior executives. Towers Perrin provided an independent assessment of competitive chief executive officer compensation and of market data for long-term incentive compensation levels for senior executives to assist in the committee’s assessment and decision-making on elements of compensation for B.H. March, as well as an assessment of the portion of senior executives pay attributable to long-term equity. Towers Perrin was not retained to provide any other compensation determinations or advice for the company or committee in determining the compensation of the chief executive officer or long-term incentive compensation levels for senior executives.
Performance Graph
The following graph shows changes over the past 10 years in the value of $100 invested in (1) Imperial Oil Limited common shares, (2) the S&P/TSX Composite Index, and (3) the S&P/TSX Equity Energy Index. The S&P/TSX Equity Energy Index is made up of share performance data for 37 oil and gas companies including integrated oil companies, oil and gas producers and oil and gas service companies.
The year-end values in the graph represent appreciation in share price and the value of dividends paid and reinvested. The calculations exclude trading commissions and taxes. Total shareholder returns from each investment, whether measured in dollars or percent, can be calculated from the year-end investment values shown beneath the graph.
During the past 10 years, the company’s cumulative total shareholder return was about 582 percent, for an average annual return of about 19 percent. During that same 10-year period, the company’s compensation (which compensation excludes the compensatory change in pension value) of its named executive officers increased by 223 percent for an average annual increase of eight percent.
(1) From 2002 to 2004, the S&P/TSX Composite Energy Index was used. Prior to 2002, the S&P/TSX Energy Index was used.
Summary Compensation Table for Named Executive Officers
The following table shows the compensation for the chairman, president and chief executive officer; the senior vice-president, finance and administration, and treasurer and the three other most highly compensated executive officers of the company who were serving as at the end of 2008. The table includes information on T.J. Hearn, who also served as chairman and chief executive officer from January 1, 2008 to March 31, 2008, inclusive. This information includes the Canadian dollar value of base salaries, cash bonus awards and units of other long-term incentive compensation and certain other compensation.
Name and Principal Position at the end of 2008 | Year | Salary ($) | Share- Based Awards ($) (2) | Option- Based Awards ($)(3) | Non-Equity Incentive Plan ($) | Pension ($) (6) | All Other Compensation ($) (7) | Total Compensation ($) (8) | ||||||||||
Annual (4) | Long-term (5) | |||||||||||||||||
B.H. March (1) President (January 1- March 31) Chairman, president and chief executive officer (April 1-December 31) | 2008 | 479,700 | 1,584,780 | - | 286,114 | 207,870 | 611,774 | 821,511 | 3,991,749 | |||||||||
P.A. Smith Senior vice-president, finance and administration, and treasurer | 2008 | 420,833 | 702,720 | - | 177,128 | 181,125 | (13,100) | 135,187 | 1,603,893 | |||||||||
R.L Broiles (1) Senior vice-president, resources division | 2008 | 398,418 | 915,918 | - | 186,443 | 169,494 | 254,286 | 506,051 | 2,430,610 | |||||||||
C.W. Erickson (1) Vice-president and general manager, refining and supply | 2008 | 394,864 | 999,183 | - | 196,144 | 187,147 | 234,192 | 413,604 | 2,425,134 | |||||||||
S.M. Smith Vice-president and general manager, fuels marketing | 2008 | 374,000 | 1,006,500 | - | 197,899 | 162,675 | 350,200 | 117,394 | 2,208,668 | |||||||||
T.J. Hearn Chairman and chief executive officer (January 1-March 31)
| 2008 | 300,000 | - | - | - | 999,900 | 124,200 | 719,049 | 2,143,149 |
(1) | B.H. March, R.L. Broiles and C.W. Erickson have been on a loan assignment from Exxon Mobil Corporation since January 1, 2008, July 1, 2005 and June 1, 2007 respectively. Their compensation is paid directly by ExxonMobil Corporation in U.S. dollars, but is disclosed in Canadian dollars. They also receive employee benefits under Exxon Mobil Corporation’s employee benefit plans, and not under the company’s employee benefit plans. The company reimburses Exxon Mobil Corporation for the compensation paid and employee benefits provided to them. All amounts paid to B.H. March, R.L. Broiles and C.W. Erickson in U.S. dollars were converted to Canadian dollars at the average 2008 exchange rate of 1.066. |
(2) | The grant date fair value equals the number of restricted stock units multiplied by the closing price of the company’s shares on the date of grant. The closing price of the company’s shares on the grant date was $36.60, which is the same as the accounting fair value for the restricted stock units on the date of grant. The company chose this method of valuation as it believes it results in the most accurate representation of fair value. For R.L. Broiles and C.W. Erickson, who received ExxonMobil restricted stock units, values are based on the closing price of Exxon Mobil Corporation shares on the date of grant ($78.11 U.S.), multiplied by the number of units granted. This amount was converted to Canadian dollars at the average 2008 exchange rate of 1.066. |
(3) | The company has not granted stock options since 2002. The stock option plan is described on pages 49 through 50. |
(4) | The amounts listed in “Annual Incentive Plans” column for each named executive officer represent their 2008 cash bonus. Any part of bonus elected to be received as deferred share units would be excluded, although no named executive officers so elected. |
(5) | The amounts listed in “Long-term Incentive Plans” column for the named executive officer represents their earnings bonus units granted in 2007 and paid out in 2008. The plan is described on pages 39 through 40. B.H. March, R.L. Broiles and C.W. Erickson received earnings bonus units under ExxonMobil’s program, which is similar to the company’s plan. They also received pay outs in 2008 for earnings bonus units granted in 2007. These amounts were converted to Canadian dollars at the average 2008 exchange rate of 1.066. |
(6) | “Pension Value” is the compensatory change in pensions as of December 31, 2008, as set out in the pension plan benefits table on page 42. |
(7) | Amounts under “All Other Compensation”, consist of dividend equivalent payments on restricted stock units granted, interest paid in respect of deferred payments of bonuses and earnings bonus units, expatriate allowances, tax reimbursements, company savings |
plans contributions, other compensation and cost of perquisites including club memberships, earned benefit allowance (for T.J. Hearn, P.A. Smith and S.M. Smith only), any costs associated with the personal use of the company aircraft, parking and security. There is no tax assistance from the company for taxes related to personal use of the company aircraft. In 2008, only T.J. Hearn had interest paid in respect of deferred payments of bonuses and earnings bonus units which was $260,336. The earned benefits allowance in 2008 was $50,000 for T.J. Hearn, $30,000 for P.A. Smith and $25,000 for S.M. Smith. For each named executive officer, except B.H. March and T.J. Hearn, the aggregate value of perquisites received was not greater than $50,000. For B.H. March, the total value of perquisites was $58,898, which total includes club memberships valued at $41,974. For T.J. Hearn, the total value of perquisites was $67,862, which total includes an earned benefit allowance of $50,000. The 2008 annual vacation allowance payment of $120,000 for T.J. Hearn is also included under “All Other Compensation”. While already factored into valuation of share based awards, it is noted that in 2008, the actual dividend equivalent payments made were $70,550 for P.A. Smith, $56,124 for S.M. Smith and $261,470 for T.J. Hearn. For B.H. March, R.L. Broiles and C.W. Erickson, the dividend equivalent payments on restricted stock granted by Exxon Mobil Corporation in previous years were $83,028 for B.H. March, $80,137 for R.L. Broiles and $77,617 for C.W. Erickson. These amounts were converted to Canadian dollars at the average 2008 exchange rate of 1.066. |
(8) | “Total Compensation” for 2008 consists of the total dollar value of “Salary”, “Share-Based Awards”, “Option-Based Awards”, “Non-Equity Incentive Plan Compensation”, “Pension Value” and “All Other Compensation”. |
Outstanding share-based awards and option-based awards for named executive officers
The following table sets forth all share-based and option-based awards outstanding as at December 31, 2008 for each of the named executive officers of the company.
Option-based Awards | Share-based Awards | |||||||||||||||||||||
Name |
Number of (#) (4) |
Option ($) |
Option |
Value of ($) |
Number of (#) (5) |
Market or payout ($) (5) | ||||||||||||||||
B.H. March(1) | - | - | - | - | 43,300 | 1,774,867 | ||||||||||||||||
P.A. Smith | 75,000 | 15.50 | April 29, 2012 | 1,911,750 | 181,850 | 7,454,032 | ||||||||||||||||
R.L. Broiles(2) | - | - | - | - | - | - | ||||||||||||||||
C.W. Erickson(3) | - | - | - | - | - | - | ||||||||||||||||
S.M. Smith | - | - | - | - | 158,900 | 6,513,311 | ||||||||||||||||
T.J. Hearn (retired from the company on March 31, 2008) | 150,000 | 15.50 | April 29, 2012 | 3,823,500 | 618,200 | 25,340,018 |
(1) | In 2001 and previous years, B.H. March participated in Exxon Mobil Corporation’s stock option plan. Under that plan, B. H. March held options to acquire 44,758 Exxon Mobil Corporation shares, of which all options were exercisable. The value of B.H. March’s exercisable options was $2,154,332 as at December 31, 2008, based on the closing price of Exxon Mobil Corporation common shares of $79.83 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2008 of 1.2246 provided by the Bank of Canada. B.H. March was granted restricted stock units in 2008 under the company’s plan. With respect to previous years, B.H. March participated in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. Under that plan, B. H. March held 44,750 restricted shares whose value on December 31, 2008 was $4,374,752 based on a closing price for Exxon Mobil Corporation shares on December 31, 2008 of $79.83 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2008 of 1.2246 provided by the Bank of Canada. |
(2) | In 2001 and previous years, R.L. Broiles participated in Exxon Mobil Corporation’s stock option plan. Under that plan, R.L. Broiles held options to acquire 56,398 Exxon Mobil Corporation shares, of which all options were exercisable. The value of R.L. Broiles’ exercisable options was $2,687,938 as at December 31, 2008, based on the closing price of Exxon Mobil Corporation common shares of $79.83 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2008 of 1.2246 provided by the Bank of Canada. R.L. Broiles participates in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. Under that plan, R.L. Broiles held 54,000 restricted shares whose value on December 31, 2008 was $5,279,030 based on a closing price for Exxon Mobil Corporation shares on December 31, 2008 of $79.83 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2008 of 1.2246 provided by the Bank of Canada. |
(3) | In 2001 and previous years, C.W. Erickson participated in Exxon Mobil Corporation’s stock option plan. Under that plan, C.W. Erickson held options to acquire 14,825 Exxon Mobil Corporation shares, of which all options were exercisable. The value of C.W. Erickson’s exercisable options was $690,437 as at December 31, 2008, based on the closing price of Exxon Mobil Corporation common shares of $79.83 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2008 of 1.2246 provided by the Bank of Canada. C.W. Erickson participates in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. Under that plan, C.W. Erickson holds 53,475 restricted shares whose value on December 31, 2008 was $5,227,706 based on a closing price for Exxon Mobil Corporation shares on December 31, 2008 of $79.83 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2008 of 1.2246 provided by the Bank of Canada. |
(4) | Represents the number of shares underlying options and three times the number of stock options granted in 2002 before the three-for-one share split in May 2006 and still held by the employee. |
(5) | Represents the total of the restricted stock units received in 2006, 2007 and 2008 after the three-for-one share split in May 2006, plus three times the number of restricted stock units received before the share split and still held by the employee. The value is based on the closing price of the company’s shares on December 31, 2008 of $40.99. |
Incentive plan awards for named executive officers– value vested or earned during the year
The following table sets forth the value of the incentive plan awards that vested for each named executive officer of the company for the year.
Name |
Option-based awards – ($) |
Share-based awards – ($) (4) |
Non-equity incentive plan ($) (5) | |||||||||
B.H. March(1) | - | - | - | |||||||||
P.A. Smith | - | 1,088,084 | 358,253 | |||||||||
R.L. Broiles(2) | - | - | - | |||||||||
C.W. Erickson(3) | - | - | - | |||||||||
S.M. Smith | - | 833,803 | 360,574 | |||||||||
T.J. Hearn (retired from the company on March 31, 2008) | - | 3,808,294 | 999,900 |
(1) | Although B.H. March received restricted stock units under the company’s plan in 2008, none of these restricted stock units have vested. In previous years B.H. March participated in Exxon Mobil Corporation’s restricted stock plan under which the grantee may receive restricted stock or restricted stock units (both of which are referred to herein as restricted stock or restricted shares), which plan is similar to the company’s restricted stock unit plan. In 2008, restrictions were removed on 5,500 restricted stock having a value as at December 31, 2008 of $537,679 based on the closing price of Exxon Mobil Corporation common shares of $79.83 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2008 of 1.2246 provided by the Bank of Canada. B.H. March received an annual bonus from Exxon Mobil Corporation in 2008 and participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan. B.H. March received $493,984 with respect to annual bonus awarded in 2008 and earnings bonus units granted in 2007 and paid out in 2008, which amount was paid in U.S. dollars and is converted to Canadian dollars at the average 2008 exchange rate of 1.066. |
(2) | R.L. Broiles participates in Exxon Mobil Corporation’s restricted stock plan under which the grantee may receive restricted stock, which plan is similar to the company’s restricted stock unit plan. In 2008, restrictions were removed on 5,500 restricted stock having a value as at December 31, 2008 of $537,679 based on the closing price of Exxon Mobil Corporation common shares of $79.83 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2008 of 1.2246 provided by the Bank of Canada. R.L. Broiles received an annual bonus from Exxon Mobil Corporation in 2008 and participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan. R.L. Broiles received $355,937 with respect to annual bonus awarded in 2008 and earnings bonus units granted in 2007 and paid out in 2008, which amount was paid in U.S. dollars and is converted to Canadian dollars at the average 2008 exchange rate of 1.066. |
(3) | C.W. Erickson participates in Exxon Mobil Corporation’s restricted stock plan under which the grantee may receive restricted stock, which plan is similar to the company’s restricted stock unit plan. In 2008, restrictions were removed on 5,500 restricted stock having a value as at December 31, 2008 of $537,679 based on the closing price of Exxon Mobil Corporation common shares of $79.83 U.S., which was converted to Canadian dollars at the noon-rate for December 31, 2008 of 1.2246 provided by the Bank of Canada. C.W. Erickson received an annual bonus from Exxon Mobil Corporation in 2008 and participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan. C.W. Erickson received $383,291 with respect to annual bonus awarded in 2008 and earnings bonus units granted in 2007 and paid out in 2008, which amount was paid in U.S. dollars and is converted to Canadian dollars at the average 2008 exchange rate of 1.066. |
(4) | These values show restricted stock units that vested in 2008. |
(5) | These values show annual bonus received in 2008 and earnings bonus units granted in 2007 and vesting in 2008. |
Details of Former Long-Term Incentive Compensation Plans
The following describes forms of long-term incentive compensation similarformerly used by the company. While incentive share units and stock options are no longer granted, incentive share units and stock options formerly granted continue to remain outstanding and are referenced in the foregoing tables.
Incentive Share Units
The company’s incentive share units give the recipient a right to receive cash equal to the deferred shareamount by which the market price of the company’s common shares at the time of exercise exceeds the issue price of the units. These units for executives, was made availablewere granted prior to nonemployee directors in lieu2002. The issue price 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 atexecutives was the end of each calendar quarter by dividing the amountclosing price of the directors’ fees for that calendar quarter thatcompany’s shares on the nonemployee director elected to receive as deferredToronto Stock Exchange on the grant date. Incentive share units by the average closing price immediately priorare eligible for exercise up to the10 years from issuance. The last day of the calendar quarter.
43
The maximum number of common shares that any one person may receive from the exercise of stock options is 154,998150,000 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.
Directors’ Compensation
Director compensation elements are designed to:
ensure alignment with long-term shareholder interests;
provide motivation to promote sustained improvement in the company’s business performance and shareholder value;
ensure the company introduced acan attract and retain outstanding director candidates who meet the selection criteria outlined in Section 9 of the board of directors charter;
recognize the substantial time commitments necessary to oversee the affairs of the company; and
support the independence of thought and action expected of directors.
Nonemployee director compensation levels are reviewed by the nominations and corporate governance committee each year, and resulting recommendations are presented to the full board for approval.
Employees of the company or ExxonMobil receive no extra pay for serving as directors. Nonemployee directors receive compensation consisting of cash and restricted stock unit plan, which will beunits. Since 1999, the primary long-term incentive compensation plannonemployee directors have been able to receive all or part of their cash directors’ fees in future years.the form of deferred share units. The purpose of the deferred share unit plan for nonemployee directors is to provide them with additional motivation to promote sustained improvement in the company’s 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 company’s common shares. The number of units granted to a nonemployee director is determined at the end of each calendar quarter by dividing the amount of the directors’ fees for that calendar quarter that the nonemployee director elected to receive as deferred share units by the average closing price immediately prior to the last day of the calendar quarter. The deferred share unit plan is described in more detail on pages 41 through 42.
In 2008, the base cash retainer for nonemployee directors was $100,000 per year. Nonemployee directors were paid $20,000 for membership on all board committees. Additionally, each board committee chair received a retainer of $10,000 for each committee chaired. Nonemployee directors were not paid a fee for attending board and committee meetings on each of the eight regularly-scheduled meeting days. However, they were eligible to receive a fee of $2,000 per board or committee meeting occurring on any other day. Four board and committee meetings occurred outside the eight regularly scheduled meeting days.
The following table shows the portion of the annual retainer for board membership, annual retainer for committee membership and annual retainer for committee chair which each nonemployee director elected to receive in cash and deferred share units in 2008.
Election for 2008 Director Fees in Cash (%) |
Election for 2008 Director Fees in Deferred Share Units (%) | |||||||
K.T. Hoeg(Director since May 1, 2008) | - | 100 | ||||||
J.M. Mintz | 50 | 50 | ||||||
R. Phillips | - | 100 | ||||||
J.F. Shepard(Director until May 1, 2008) | - | 100 | ||||||
S.D. Whittaker | - | 100 | ||||||
V.L. Young | 75 | 25 |
In addition to the cash fees described above, the company pays a significant portion of director compensation in restricted stock units to align the interests of the selected key employees and nonemployee directors directlydirector compensation with the long-term interests of shareholders. Each unit entitles the recipient the right to receiveRestricted stock units are awarded annually with 50 percent vesting in cash three years from the company, upon exercise, an amount equal to the closing pricedate of the company’s 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 exercisedremaining 50 percent vesting on the seventh anniversary of the grant date. The company will pay the recipients cash with respectDirectors can elect 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 perfor each unit or elect to receive thea cash payment for the units to be exercised on the seventh anniversary date of the grant date. A totaldate of 1,713,488 units were granted on December 4, 2007.
Components of Directors’ Compensation
Director | Annual Retainer for ($) | Annual Retainer for ($) | Annual Retainer ($) | Restricted (RSU) (#) | Fee for Board and Committee Meetings Not Regularly Scheduled | Total ($) (1) | Total (DSU) ($) (2) | Total ($) (3) | Total ($) | |||||||||||
Number of (#) | Fee ($2,000 x ($) | |||||||||||||||||||
K.T. Hoeg (Director since May 1, 2008) | 66,944 | 13,388 (IOF) | 6,694 | 2,000 | - | - | - | 87,027 | 73,200 | 160,227 | ||||||||||
J.M. Mintz | 100,000 | 20,000 (EH&S) | 10,000 | 2,000 | 2 | 4,000 | 69,000 | 65,000 | 73,200 | 207,200 | ||||||||||
R. Phillips | 100,000 | 20,000 (ERC) | 10,000 | 2,000 | 2 | 4,000 | 4,000 | 130,000 | 73,200 | 207,200 | ||||||||||
J.F. Shepard (Director until May 1, 2008) | 33,611 | 6,722 (AC) | 3,361 | - | 2 | 4,000 | 4,000 | 43,694 | - | 47,694 | ||||||||||
S.D. Whittaker | 100,000 | 20,000 (N&CG) | 10,000 | 2,000 | 4 | 8,000 | 8,000 | 130,000 | 73,200 | 211,200 | ||||||||||
V.L. Young | 100,000 | 20,000 (AC) | 10,000 | 2,000 | 4 | 8,000 | 105,500 | 32,500 | 73,200 | 211,200 |
(1) | “Total Cash” is the portion of the annual retainer for board membership, annual retainer for committee membership and annual retainer for committee chair which the director elected to receive as cash, plus the fee for board and committee meetings not regularly scheduled. This amount is reported as “Fees Earned” in the “Director Compensation Table” on page 52. |
(2) | “Total Deferred Share Units” is the portion of the annual retainer for board membership, annual retainer for committee membership and annual retainer for committee chair, which the director elected to receive as deferred share units, as set out in the previous table on page 50. This amount plus the total restricted stock units amount is shown as “Share-based Awards” in the “Director Compensation Table” on page 52. |
(3) | The values of the restricted stock units shown are the number of units multiplied by the closing price of the company’s shares on the date of grant. |
On November 20, 2008, the board amended the restricted stock unit plan to provide that the board will no longer have the general discretion to cancel restricted stock units awarded to a nonemployee director subsequent to leaving the company’s board. Previously, the board had to approve the retention of restricted stock units when the nonemployee director left the board. The objective of this language was to encourage board members to remain on the board until standard retirement time, thereby ensuring board member alignment with long-term shareholder value. It has been determined by the board that, to reinforce the independence of each board member, this provision of the incentive plan language for nonemployee directors would be removed. This change applies to the terms of all outstanding restricted stock units and any restricted stock unit grants going forward. However, while on the board and for a 24-month period after leaving the company’s board, 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, engagednonemployee director engages in any business that was indirect competition with the company or otherwise engagedengages in any activity that was detrimental to the company. The company may determineboard agreed that restricted stock units willthe word “detrimental” shall not be forfeited afterinclude any actions taken by a nonemployee director or former nonemployee director who acted in good faith and in the cessation of employment. Restricted stock units cannot be assigned. In the case of any subdivision, consolidation, or reclassificationbest interests of the sharescompany.
Compensation Decision Making Process and Considerations
The nominations and corporate governance committee relies on market comparisons with a group of the21 major Canadian companies with national and international scope and complexity. The company or other relevant changedraws its non-employee directors from a wide variety of industrial sectors, so a broad sample is appropriate for this purpose. The nominations and corporate governance committee does not target any specific percentile among comparator companies at which to align compensation for this group, but rather considers current developments and practices in director
compensation elements based on analysis of published management proxy circulars completed every two years. The 21 comparator companies included in the capitalization of the company, the company, in its discretion, may make appropriate adjustments in the number of common shares to be issued and the calculation of the cash amount payable per restricted stock unit. Effective December 31, 2004, the restricted stock unit plan was amended by the company to
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Remuneration for | ||||||||||||||||||||||||||||||||
determining | Estimated undiscounted payments on retirement | |||||||||||||||||||||||||||||||
payments | at the age of 65 after years of service indicated below ($) (1) | |||||||||||||||||||||||||||||||
on retirement | ||||||||||||||||||||||||||||||||
($) | 20 Years | 25 Years | 30 Years | 35 Years | 40 Years | 45 Years | ||||||||||||||||||||||||||
100,000 | 32,000 | 40,000 | 48,000 | 56,000 | 64,000 | 72,000 | ||||||||||||||||||||||||||
200,000 | 64,000 | 80,000 | 96,000 | 112,000 | 128,000 | 144,000 | ||||||||||||||||||||||||||
300,000 | 96,000 | 120,000 | 144,000 | 168,000 | 192,000 | 216,000 | ||||||||||||||||||||||||||
400,000 | 128,000 | 160,000 | 192,000 | 224,000 | 256,000 | 288,000 | ||||||||||||||||||||||||||
500,000 | 160,000 | 200,000 | 240,000 | 280,000 | 320,000 | 360,000 | ||||||||||||||||||||||||||
600,000 | 192,000 | 240,000 | 288,000 | 336,000 | 384,000 | 432,000 | ||||||||||||||||||||||||||
800,000 | 256,000 | 320,000 | 384,000 | 448,000 | 512,000 | 576,000 | ||||||||||||||||||||||||||
1,000,000 | 320,000 | 400,000 | 480,000 | 560,000 | 640,000 | 720,000 | ||||||||||||||||||||||||||
1,500,000 | 480,000 | 600,000 | 720,000 | 840,000 | 960,000 | 1,080,000 | ||||||||||||||||||||||||||
2,000,000 | 640,000 | 800,000 | 960,000 | 1,120,000 | 1,280,000 | 1,440,000 | ||||||||||||||||||||||||||
2,500,000 | 800,000 | 1,000,000 | 1,200,000 | 1,400,000 | 1,600,000 | 1,800,000 | ||||||||||||||||||||||||||
3,000,000 | 960,000 | 1,200,000 | 1,440,000 | 1,680,000 | 1,920,000 | 2,160,000 | ||||||||||||||||||||||||||
3,500,000 | 1,120,000 | 1,400,000 | 1,680,000 | 1,960,000 | 2,240,000 | 2,520,000 | ||||||||||||||||||||||||||
4,000,000 | 1,280,000 | 1,600,000 | 1,920,000 | 2,240,000 | 2,560,000 | 2,880,000 | ||||||||||||||||||||||||||
Alcan Inc. | Bank of | |||
Bank of Montreal | George Weston Limited | Sun Life Financial Inc. | ||
BCE Inc. | Manulife Financial Corporation | Suncor Energy Inc. | ||
Bombardier Inc. | Nortel Networks Corporation | TELUS Corporation | ||
Canadian Imperial Bank of Commerce | Petro-Canada | Thomson Reuters Corporation | ||
Canadian National Railway Company | Power Financial Corporation | The Toronto Dominion Bank | ||
Canadian Pacific Railway Limited | Royal Bank of Canada | TransCanada Corporation |
Director Compensation Table
The company’s pension plan appliesfollowing table summarizes the compensation paid, payable, awarded or granted for 2008 to almost all employees. The plan provides an annual pension of a specific percentage of an employee’s “final three year average earnings”, multiplied by the employee’s years of service, subject to certain requirements concerning age and length of service. An employee may elect to forego threeeach of the six percentindependent directors of the company’s 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 employee’s “final three year average earnings”, multiplied by the employee’s 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.
45
Name (1) |
Fees Earned |
Share- ($) (4) |
Option- ($) |
Non-equity ($) |
Pension (#) |
All other ($) |
Total ($) | |||||||||||||||||||||
K.T. Hoeg(2) (Director since May 1, 2008) | - | 160,227 | - | - | - | - | 160,227 | |||||||||||||||||||||
J.M. Mintz(2) | 69,000 | 138,200 | - | - | - | - | 207,200 | |||||||||||||||||||||
R. Phillips(2) | 4,000 | 203,200 | - | - | - | - | 207,200 | |||||||||||||||||||||
J.F. Shepard(2) (Director until May 1, 2008) | 4,000 | 43,694 | - | - | - | - | 47,694 | |||||||||||||||||||||
S.D. Whittaker(2) | 8,000 | 203,200 | - | - | - | - | 211,200 | |||||||||||||||||||||
V.L. Young(2) | 105,500 | 105,700 | - | - | - | - | 211,200 |
Accrued | Annual Pension | |||||||||||||||||||
Current 2007 | Obligations at | Benefit Payable at | Age | Normal | ||||||||||||||||
Service Cost | Dec. 31, 2007 | age 65 | (at Dec. 31, | Credited | Retirement | |||||||||||||||
Name | ($)(3) | (4) | (5) | 2007) | Service | Age | ||||||||||||||
T.J. Hearn | 515,200 | 24,482,600 | 2,144,400 | 63 | 41 | 65 | ||||||||||||||
P.A. Smith | 133,600 | 3,624,900 | 474,000 | 54 | 27 | 65 | ||||||||||||||
R.L. Broiles | – | – | – | 50 | 28 | 65 | ||||||||||||||
B.W. Livingston | 122,000 | 2,522,900 | 382,800 | 53 | 23 | 65 | ||||||||||||||
J.F. Kyle | 90,100 | 3,535,400 | 298,800 | 64 | 31 | 65 | ||||||||||||||
(1) |
(2) |
(3) | Represents all fees awarded, earned, paid or payable in cash for services as a director, including retainer fees, committee, chair and meeting fees. |
The values of the | ||
Outstanding share-based awards and option-based awards for directors
The following table sets forth all outstanding awards held by independent directors of the company as at December 31, 2008.
Option-based Awards | Share-based Awards | |||||||||||||||||||||||
Name (1) | Number of securities underlying unexercised options (#) | Option exercise price ($) | Option Expiration Date | Value of unexercised money ($) | Number of shares or units of shares that have not vested (#) (2) | Market or payout value of share- based awards that have not vested ($) (3) | ||||||||||||||||||
K.T. Hoeg (Director since May 1, 2008) | - | - | - | - | 3,931 | 161,131 | ||||||||||||||||||
J.M. Mintz | - | - | - | - | 11,563 | 473,967 | ||||||||||||||||||
R. Phillips | - | - | - | - | 30,361 | 1,244,497 | ||||||||||||||||||
J.F. Shepard (Director until May 1, 2008) | - | - | - | - | 10,625 | 435,519 | ||||||||||||||||||
S.D. Whittaker | - | - | - | - | 46,051 | 1,887,630 | ||||||||||||||||||
V.L. Young | - | - | - | - | 18,668 | 765,201 |
(1) | As directors employed by the company or Exxon Mobil Corporation, T.J. Hearn, B.H. March, R.L. Broiles, P.A. Smith and R.C. Olsen did not receive compensation for acting as directors. |
(2) | Includes restricted stock units and deferred share units held as of December 31, |
(3) | Value is |
Incentive plan awards for directors – value vested or earned during the year
The following table sets forth the value of the awards that vested or were earned by each independent director of the company in 2008.
Name (1) | Option-based awards – Value vested during the ($) | Share-based awards – ($) | Non-equity incentive plan ($) | |||||||
K.T. Hoeg (Director since May 1, 2008) | - | - | - | |||||||
J.M. Mintz(2) | - | 59,135 | - | |||||||
R. Phillips(2) | - | 59,135 | - | |||||||
J.F. Shepard(2)(3) (Director until May 1, 2008) | - | 1,443,396 | - | |||||||
S.D. Whittaker(2) | - | 59,135 | - | |||||||
V.L. Young(2) | - | 59,135 | - |
(1) | As directors employed by the company or Exxon Mobil Corporation, T.J. Hearn, B.H. March, R.L. Broiles, P.A. Smith and R.C. Olsen did not receive compensation for acting as directors. |
(2) | Includes restricted stock units granted in |
(3) | For J.F. Shepard, the value includes deferred share units that vested as of his retirement date from the board on |
Share Ownership Guidelines for Directors
Directors are required to hold the equivalent of at least 15,000 shares of Imperial Oil Limited, including common shares, deferred share units and restricted stock units. Directors are expected to reach this level within five years. The board of directors believes that the share ownership guideline will result in an alignment of the interest of board members with the interests of all other shareholders.
Director |
Director Since |
Amount (February |
Total Holdings |
Minimum |
Minimum |
Date Required to | ||||||||||||||||
K.T. Hoeg | May 1, 2008 | 3,931 | 3,931 | 15,000 | No | May 1, 2013 | ||||||||||||||||
B.H. March (1) | January 1, 2008 | 43,300 | 48,300 | 15,000 | Yes | January 1, 2013 | ||||||||||||||||
J.M. Mintz | April 21, 2005 | 1,879 | 12,563 | 15,000 | No | April 21, 2010 | ||||||||||||||||
R.C. Olsen | May 1, 2008 | 3,000 | 3,000 | 15,000 | No | May 1, 2013 | ||||||||||||||||
R. Phillips | April 23, 2002 | 3,349 | 39,361 | 15,000 | Yes | April 23, 2007 | ||||||||||||||||
P.A. Smith | February 1, 2002 | (8,678) | 194,909 | 15,000 | Yes | February 1, 2007 | ||||||||||||||||
S.D. Whittaker | April 19, 1996 | 3,474 | 55,051 | 15,000 | Yes | April 19, 2001 | ||||||||||||||||
V.L. Young | April 23, 2002 | 2,223 | 29,918 | 15,000 | Yes | April 23, 2007 |
(1) | Paragraph 10(b) of the Board of Directors Charter provides that B.H. March, as chairman, president and |
Item 12. | Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. |
To the knowledge of the managementdirectors and executive officers of the company, the only shareholder who, as of February 14, 2008,13, 2009, owned beneficially, or exercised control or direction over, directly or indirectly, more than five10 percent of the outstanding common shares of the company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard, Irving, Texas 75039-2298, which owns beneficially 626,939,795596,357,122 common shares, representing 69.6 percent of the outstanding voting shares of the company.
Reference is made to the security ownership information under the preceding Items 10 and 11. As of February 14, 2008, J.F.Kyle13, 2009, S.M. Smith was the owner of 12,5853,794 common shares of the company and held 126,500158,900 restricted stock units of the company. As of February 14, 2008, B.W.Livingston was the owner of 5,908 common shares of the company, held options to acquire 30,000 common shares of the company and held 119,750 restricted stock units of the company.
The directorsexecutive officers and the senior executivesdirectors of the company, whose compensation for the year ended December 31, 20072008 is described on pages 3937 through 41,53, consist of 1115 persons, who, as a group, own beneficially 176,72271,991 common shares of the company, being approximately 0.020.01 percent of the total number of outstanding shares of the company, and 150,926515,218 shares of Exxon Mobil Corporation (including 98,750334,805 restricted shares). This information
not being within the knowledge of the company has been provided by the directors and the senior executivesexecutive officers individually. As a group, the directors and senior executivesexecutive officers of the company held options to acquire 259,998145,500 common shares of the company and held restricted stock units to acquire 827,100504,925 common shares of the company, as of February 14, 2008.
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The following table provides information on the common shares of the company that may be issued as of the end of 20072008 pursuant to compensation plans of the company.
Plan category | Number of securities to | Weighted-average | Number of securities | ||||||||
be issued upon exercise | exercise price of | remaining available for future | |||||||||
of outstanding options, | outstanding options, | issuance under equity | |||||||||
warrants and rights | warrants and rights | compensation plans (excluding | |||||||||
(3) | ($) | securities reflected in | |||||||||
column (a)) | |||||||||||
(3) | |||||||||||
(a) | (b) | (c) | |||||||||
Equity compensation | 4,728,780 | 15.50 | 0 | ||||||||
plans approved by security holders (1) | |||||||||||
Equity compensation | 7,074,314 | – | 3,425,686 | ||||||||
plans not approved by security holders (2) | |||||||||||
Total | 11,803,094 | 15.50 | 3,425,686 | ||||||||
Plan Category | Number of securities to be issued upon exercise of (3) | Weighted-average exercise price of ($) (4) | Number of securities remaining available for future issuance under equity (3) | |||||||||||
Equity compensation plans approved by security holders (1) | 4,294,635 | 15.50 | - | |||||||||||
Equity compensation plans not approved by security holders (2) | 7,928,818 | - | 2,571,182 | |||||||||||
Total | 12,223,453 | 15.50 | 2,571,182 |
(1) | This is a stock option plan, which is described on pages 49 through 50. |
(2) | This is a restricted stock unit plan, which is described on |
(3) | The number of securities reserved for the stock option plan represents three times the number of stock options granted in 2002 before the three-for-one share split in May 2006 and still outstanding. The number of securities reserved for the restricted stock unit plan represents the securities reserved for restricted stock units issued in 2006, 2007 and |
(4) | 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, and Director Independence. |
On June 23, 2006,25, 2007, the company implemented anothera 12-month “normal course” share-purchase program under which it purchased 47,868,66345,794,291 of its outstanding shares between June 23, 200625, 2007 and June 22, 2007.24, 2008. On June 25, 2007, another2008, a 12-month “normal course”share purchase program was implemented under which the company may purchase up to 46,459,96744,194,961 of its outstanding shares, less any shares purchased by the employee savings plan and company pension fund. Exxon Mobil Corporation participated by selling shares to maintain its ownership at 69.6 percent. In 2007,2008, such share purchases cost $2,358about $2,210 million, of which $1,615about $1,521 million was received by Exxon Mobil Corporation.
The amounts of purchases and sales by the company and its subsidiaries for other transactions in 20072008 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $3,525$4,890 million and $1,772$2,150 million, respectively. These transactions were conducted on terms as favourable as they would have been with unrelated parties, and primarily consisted of the purchase and sale of crude oil, natural gas, petroleum and chemical products, as well as transportation, technical and engineering services. Transactions with Exxon Mobil Corporation also included amounts paid and received in connection with the company’s participation in a number of natural resourcesupstream activities conducted jointly in Canada. The company also has agreements with affiliates of Exxon Mobil Corporation to provide computer and customer support services to the company and to share common business and operational support services to allow the companies to consolidate duplicate work and systems. The company has a contractual agreement with an affiliate of Exxon Mobil Corporation in Canada to operate the Western Canada production properties owned by ExxonMobil. There are no asset ownership changes. The company and that affiliate also have a contractual agreement to share new upstream opportunities on an up to equal basis. During 2007, the company entered into agreements with Exxon Mobil Corporation and one of its affiliated companies that provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil.
47
The aggregate fees of the company’s auditor PricewaterhouseCoopers LLP (PwC) for professional services rendered for the audit of the company’s financial statements and other services for the fiscal years ended December 31, 20072008 and December 31, 20062007 were as follows:
Dollars (thousands) | 2007 | 2006 | ||||||
Audit Fees | 1,117 | 1,117 | ||||||
Audit-Related Fees | 62 | 62 | ||||||
Tax Fees | 942 | 815 | ||||||
All Other Fees | Nil | Nil | ||||||
Total Fees | 2,121 | 1,994 | ||||||
Dollars(thousands) | 2008 | 2007 | ||||
Audit Fees | 1,140 | 1,117 | ||||
Audit-Related Fees | 62 | 62 | ||||
Tax Fees | 176 | 942 | ||||
All Other Fees | - | - | ||||
Total Fees | 1,378 | 2,121 |
Audit fees include the audit of the company’s annual financial statements and internal control over financial reporting, and a review of the first three quarterly financial statements in 2007.
The audit committee recommends the external auditor to be appointed by the shareholders, fixes its remuneration and oversees its work. The audit committee also approves the proposed current year audit program of the external auditor, assesses the results of the program after the end of the program period and approves in advance any non-audit services to be performed by the external auditor after considering the effect of such services on their independence.
All of the services rendered by the auditor to the company were approved by the audit committee.
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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 company’s Form 8-Q filed on May 3, 2006 (File No. 0-12014)). | ||||
(ii) | By-laws of the company (Incorporated herein by reference to Exhibit (3)(ii) to the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 0-12014)). | |||||
(4) | The company’s long term debt authorized under any instrument does not exceed 10 percent of the company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s Annual Report on Form 10-K for the year ended December 31, 1987 (File No. 0-12014)). | |||||
(13) | Amendment to Alberta Crown Agreement, dated November 25, 1987 (Incorporated herein by reference to Exhibit (10)(ii)(13) of the company’s Annual Report on Form 10-K for the year ended December 31, 1987 (File No. 0-12014)). |
49
(14)
Amendment to Syncrude Ownership and Management Agreement, dated March 10, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(14) of the company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)). |
(25) | Syncrude Royalty Amending Agreement, dated November 18, 2008, setting out various items, including the amount of additional royalties that are to be paid to the Province of Alberta in the period from January 1, 2010 to December 31, 2015 in return for certain assurances from the Government of Alberta (Incorporated herein by reference to Exhibit 1.01(10)(ii)(1) of the company’s Form 8-K filed on November 19, 2008 (File No. 0-12014)). | |||||
(26) | Syncrude Bitumen Royalty Option Agreement, dated November 18, 2008, setting out the terms of the exercise by the Syncrude Joint Venture owners of the option contained in the existing Crown Agreement to convert to a royalty payable on the value of bitumen, effective January 1, 2009 (Incorporated herein by reference to Exhibit 1.01(10)(ii)(2) of the company’s Form 8-K filed on November 19, 2008 (File No. 0-12014)). | |||||
(27) | Project Approval Order No. OSR045 made under the Alberta Mines and Minerals Act and Oil Sands Royalty Regulation, 1997 in respect of the Syncrude Project (Incorporated herein by reference to Exhibit 1.01(10)(ii)(3) of the company’s Form 8-K filed on November 19, 2008 (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 company’s 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 company’s 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 company’s 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 company’s 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 company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014). |
50
(3) | Deferred Share Unit Plan. (Incorporated herein by reference to Exhibit(10)(iii)(A)(5) of the company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s 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 company’s Form 8-K filed on February 2, 2007 (File No. | |||||
(15) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2002, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(15)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)). | |||||
(16) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2003, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(16)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)). | |||||
(17) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2004 and 2005, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(17)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)). | |||||
(18) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2006 and 2007, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(18)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)). |
(19) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2008 and subsequent years, as amended effective February 26, 2008 and May 1, 2008 (Incorporated herein by reference to Exhibit 6 [10(iii)(A)(19)] of the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2008 (File No. 0-12014)). | |||||||
(20) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2002, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)). | |||||||
(21) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2003, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(2)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)). | |||||||
(22) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2004 and 2005, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(3)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)). | |||||||
(23) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2006 and 2007, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(4)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)). | |||||||
(24) | Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2008 and subsequent years, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(5)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)). | |||||||
(25) | Amended Deferred Share Unit Plan effective November 20, 2008 (Filed as Exhibit 15(10)(iii)(A)(25) to this Form 10-K). | |||||||
(21) | Imperial Oil Resources Limited, McColl-Frontenac Petroleum Inc., Imperial Oil Resources N.W.T. Limited and Imperial Oil Resources Ventures Limited, all incorporated in Canada, are wholly-owned subsidiaries of the company. The names of all other subsidiaries of the company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2006. |
(23)(ii) | (A) Consent of Independent Registered Public Accounting Firm (PricewaterhouseCoopers LLP). | |||||||
(31.1) | Certification by principal executive officer of Periodic Financial Report pursuant to Rule 13a-14(a). | |||||||
(31.2) | Certification by principal financial officer of Periodic Financial Report pursuant to Rule 13a-14(a). | |||||||
(32.1) | Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350. | |||||||
(32.2) | Certification by chief financial officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350. |
Copies of Exhibits may be acquired upon written request of any shareholder to the investor relations manager, Imperial Oil Limited, 237 Fourth Avenue S.W., Calgary, Alberta, Canada T2P 3M9, and payment of processing and mailing costs.
51
SIGNATURES
By | /s/ | |||||
( | ||||||
President and Chief Executive Officer) |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 26, 200824, 2009 by the following persons on behalf of the registrant and in the capacities indicated.
Signature | Title | |
/s/ Bruce H. March (Bruce H. March) | Chairman of the Board, President and Chief Executive Officer and Director (Principal Executive Officer) | |
/s/ Paul A. Smith (Paul A. Smith) | Senior Vice-President, Finance and Administration, and Treasurer and Director (Principal Accounting Officer and Principal Financial Officer) | |
/s/ Krystyna T. Hoeg (Krystyna T. Hoeg) | Director | |
/s/ Jack M. Mintz (Jack M. Mintz) | Director | |
/s/ Robert C. Olsen (Robert C. Olsen) | Director | |
/s/ Roger Phillips (Roger Phillips) | Director | |
/s/ Sheelagh D. Whittaker (Sheelagh D. Whittaker) | Director | |
/s/ Victor L. Young (Victor L. Young ) | Director |
52
Pages in this Report | |||
Management’s report on internal control over financial reporting | F-2 | ||
Auditors’ report of independent registered public accounting firm | F-2 | ||
Financial statements: | |||
F-3 | |||
F-5 | |||
Consolidated statement of cash flows for the years 2006, 2007 and 2008 | F-6 | ||
F-7 – F-20 |
F-1
Management, including the company’s chief executive officer and principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on theInternal Control - Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Imperial Oil Limited’s internal control over financial reporting was effective as of December 31, 2007.
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the company’s internal control over financial reporting as of December 31, 2007,2008, as stated in their report which is included herein.
/s/ | /s/ Paul A. Smith | |||||
Chairman, president and chief executive officer | Senior vice-president, finance and administration, and treasurer | |||||
To the Shareholders of Imperial Oil Limited
We have completed integrated audits of Imperial Oil Limited’s 2008, 2007 2006 and 20052006 consolidated financial statements and of its internal control over financial reporting as of December 31, 2007.2008. 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, 20072008 and December 31, 2006,2007, and the results of their operations and their cash flows for each of the years in the three year period ended December 31, 20072008 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
Internal control over financial reporting
Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007,2008, based on criteria established inInternal Control - Integrated Frameworkissued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting. Our responsibility is to express an opinion on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s 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 company’s 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 company’s 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 | ||
Chartered Accountants | ||
Calgary, Alberta, Canada | ||
February | 24, 2009 |
F-2
millions of Canadian dollars | ||||||||||||
For the years ended December 31 | 2007 | 2006 | 2005 | |||||||||
Revenues and other income | ||||||||||||
Operating revenues (a)(b)(c) | 25,069 | 24,505 | 27,797 | |||||||||
Investment and other income (note 10) | 374 | 283 | 417 | |||||||||
Total revenues and other income | 25,443 | 24,788 | 28,214 | |||||||||
Expenses | ||||||||||||
Exploration | 106 | 32 | 43 | |||||||||
Purchases of crude oil and products (b)(d) | 14,026 | 13,793 | 17,168 | |||||||||
Production and manufacturing (e) | 3,474 | 3,446 | 3,327 | |||||||||
Selling and general | 1,335 | 1,284 | 1,577 | |||||||||
Federal excise tax (a) | 1,307 | 1,274 | 1,278 | |||||||||
Depreciation and depletion | 780 | 831 | 895 | |||||||||
Financing costs (note 14)(f) | 36 | 28 | 8 | |||||||||
Total expenses | 21,064 | 20,688 | 24,296 | |||||||||
Income before income taxes | 4,379 | 4,100 | 3,918 | |||||||||
Income taxes (note 5) | 1,191 | 1,056 | 1,318 | |||||||||
Net income | 3,188 | 3,044 | 2,600 | |||||||||
Per-share information(Canadian dollars) | ||||||||||||
Net income per common share - basic (note 12) | 3.43 | 3.12 | 2.54 | |||||||||
Net income per common share - diluted (note 12) | 3.41 | 3.11 | 2.53 | |||||||||
Dividends | 0.35 | 0.32 | 0.31 | |||||||||
millions of Canadian dollars | ||||||||||
For the years ended December 31 | 2008 | 2007 | 2006 | |||||||
Revenues and other income | ||||||||||
Operating revenues (a)(b) | 31 240 | 25 069 | 24 505 | |||||||
Investment and other income (note 9) | 339 | 374 | 283 | |||||||
Total revenues and other income | 31 579 | 25 443 | 24 788 | |||||||
Expenses | ||||||||||
Exploration | 132 | 106 | 32 | |||||||
Purchases of crude oil and products (c) | 18 865 | 14 026 | 13 793 | |||||||
Production and manufacturing (d) | 4 228 | 3 474 | 3 446 | |||||||
Selling and general | 1 038 | 1 335 | 1 284 | |||||||
Federal excise tax (a) | 1 312 | 1 307 | 1 274 | |||||||
Depreciation and depletion | 728 | 780 | 831 | |||||||
Financing costs (note 13) | - | 36 | 28 | |||||||
Total expenses | 26 303 | 21 064 | 20 688 | |||||||
Income before income taxes | 5 276 | 4 379 | 4 100 | |||||||
Income taxes(note 4) | 1 398 | 1 191 | 1 056 | |||||||
Net income | 3 878 | 3 188 | 3 044 | |||||||
Per-share information(Canadian dollars) | ||||||||||
Net income per common share - basic (note 11) | 4.39 | 3.43 | 3.12 | |||||||
Net income per common share - diluted (note 11) | 4.36 | 3.41 | 3.11 | |||||||
Dividends | 0.38 | 0.35 | 0.32 |
(a) | Operating revenues include federal excise tax of $1,312 million (2007 - $1,307 million, | |
(b) | ||
Operating revenues include amounts from related parties of $2,150 million (2007 - $1,772 million, |
(c) | Purchases of crude oil and products include amounts from related parties of $4,729 million (2007 - $3,331 million, |
(d) | Production and manufacturing expenses include amounts to related parties of $161 million (2007 - $194 million, | |
The information on pages F-7 through F-20 is an integral part of these consolidated financial statements.
F-3
Consolidated balance sheet(U.S. GAAP)
millions of Canadian dollars | ||||||
At December 31 | 2008 | 2007 | ||||
Assets | ||||||
Current assets | ||||||
Cash | 1 974 | 1 208 | ||||
Accounts receivable, less estimated doubtful amounts | 1 455 | 2 132 | ||||
Inventories of crude oil and products (note 12) | 673 | 566 | ||||
Materials, supplies and prepaid expenses | 180 | 128 | ||||
Deferred income tax assets (note 4) | 361 | 660 | ||||
Total current assets | 4 643 | 4 694 | ||||
Long-term receivables, investments and other long-term assets | 881 | 766 | ||||
Property, plant and equipment, less accumulated depreciation and depletion (note 3) | 11 248 | 10 561 | ||||
Goodwill (note 3) | 204 | 204 | ||||
Other intangible assets, net | 59 | 62 | ||||
Total assets(note 3) | 17 035 | 16 287 | ||||
Liabilities | ||||||
Current liabilities | ||||||
Notes and loans payable (note 13) | 109 | 108 | ||||
Accounts payable and accrued liabilities (a) | 2 542 | 3 335 | ||||
Income taxes payable | 1 498 | 1 498 | ||||
Total current liabilities | 4 149 | 4 941 | ||||
Capitalized lease obligations (note 14) | 34 | 38 | ||||
Other long-term obligations (note 6) | 2 298 | 1 914 | ||||
Deferred income tax liabilities (note 4) | 1 489 | 1 471 | ||||
Total liabilities | 7 970 | 8 364 | ||||
Commitments and contingent liabilities (note 10) | ||||||
Shareholders’ equity | ||||||
Common shares at stated value (note 11)(b) | 1 528 | 1 600 | ||||
Earnings reinvested | 8 484 | 7 071 | ||||
Accumulated other comprehensive income | (947) | (748) | ||||
Total shareholders’ equity | 9 065 | 7 923 | ||||
Total liabilities and shareholders’ equity | 17 035 | 16 287 |
(a) | Accounts payable and accrued liabilities include amounts to related parties of $96 million (2007 - $260 million), (note 15). |
(b) | Number of common shares outstanding was 859 million (2007 - 903 million), (note 11). |
The information on pages F-7 through F-20 is an integral part of these consolidated financial statements.
Approved by the directors
/s/ B.H. March | /s/ P.A. Smith | |||
Chairman, president and | Senior vice-president, | |||
chief executive officer | finance and administration, and treasurer |
millions of Canadian dollars | ||||||||||
At December 31 | 2008 | 2007 | 2006 | |||||||
Common shares at stated value(note 11) | ||||||||||
At beginning of year | 1 600 | 1 677 | 1 747 | |||||||
Issued under the stock option plan | 7 | 12 | 10 | |||||||
Share purchases at stated value | (79) | (89) | (80) | |||||||
At end of year | 1 528 | 1 600 | 1 677 | |||||||
Earnings reinvested | ||||||||||
At beginning of year | 7 071 | 6 462 | 5 466 | |||||||
Cumulative effect of accounting change (note 4) | - | 14 | - | |||||||
Net income for the year | 3 878 | 3 188 | 3 044 | |||||||
Share purchases in excess of stated value | (2 131) | (2 269) | (1 737) | |||||||
Dividends | (334) | (324) | (311) | |||||||
At end of year | 8 484 | 7 071 | 6 462 | |||||||
Accumulated other comprehensive income | ||||||||||
At beginning of year | (748) | (733) | (580) | |||||||
Post-retirement benefits liability adjustment (note 5) | (283) | (87) | (733) | |||||||
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost | 84 | 72 | - | |||||||
Minimum pension liability adjustment (note 5) | - | - | 580 | |||||||
At end of year | (947) | (748) | (733) | |||||||
Shareholders’ equity at end of year | 9 065 | 7 923 | 7 406 | |||||||
Comprehensive income for the year | ||||||||||
Net income for the year | 3 878 | 3 188 | 3 044 | |||||||
Other comprehensive income | ||||||||||
Post-retirement benefits liability adjustment | (199) | (15) | - | |||||||
Minimum pension liability adjustment | - | - | 334 | |||||||
Total comprehensive income for the year | 3 679 | 3 173 | 3 378 |
The information on pages F-7 through F-20 is an integral part of these consolidated financial statements.
millions of Canadian dollars | ||||||||||||
Inflow/(outflow) | ||||||||||||
For the years ended December 31 | 2007 | 2006 | 2005 | |||||||||
Operating activities | ||||||||||||
Net income | 3,188 | 3,044 | 2,600 | |||||||||
Adjustments for non-cash items: | ||||||||||||
Depreciation and depletion | 780 | 831 | 895 | |||||||||
(Gain)/loss on asset sales, after tax | (156) | (96) | (233) | |||||||||
Deferred income taxes and other | 16 | 254 | (116) | |||||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable | (261) | 203 | (414) | |||||||||
Inventories and prepaids | 13 | (97) | (67) | |||||||||
Income taxes payable | (77) | (225) | 304 | |||||||||
Accounts payable | 250 | (86) | 644 | |||||||||
All other items - net(a) | (127) | (241) | (162) | |||||||||
Cash from operating activities | 3,626 | 3,587 | 3,451 | |||||||||
Investing activities | ||||||||||||
Additions to property, plant and equipment and intangibles | (899) | (1,177) | (1,432) | |||||||||
Proceeds from asset sales | 279 | 212 | 440 | |||||||||
Cash from (used in) investing activities | (620) | (965) | (992) | |||||||||
Financing activities | ||||||||||||
Short-term debt - net | (65) | 72 | 18 | |||||||||
Repayment of long-term debt | (1,726) | (74) | (21) | |||||||||
Long-term debt issued | 500 | – | – | |||||||||
Issuance of common shares under stock option plan | 12 | 10 | 38 | |||||||||
Common shares purchased(note 12) | (2,358) | (1,818) | (1,795) | |||||||||
Dividends paid | (319) | (315) | (317) | |||||||||
Cash from (used in) financing activities | (3,956) | (2,125) | (2,077) | |||||||||
Increase (decrease) in cash | (950) | 497 | 382 | |||||||||
Cash at beginning of year | 2,158 | 1,661 | 1,279 | |||||||||
Cash at end of year(b) | 1,208 | 2,158 | 1,661 | |||||||||
millions of Canadian dollars | ||||||||||
Inflow/(outflow) | ||||||||||
For the years ended December 31 | 2008 | 2007 | 2006 | |||||||
Operating activities | ||||||||||
Net income | 3 878 | 3 188 | 3 044 | |||||||
Adjustments for non-cash items: | ||||||||||
Depreciation and depletion | 728 | 780 | 831 | |||||||
(Gain)/loss on asset sales | (241) | (215) | (134) | |||||||
Deferred income taxes and other | 387 | 75 | 292 | |||||||
Changes in operating assets and liabilities: | ||||||||||
Accounts receivable | 679 | (261) | 203 | |||||||
Inventories and prepaids | (159) | 13 | (97) | |||||||
Income taxes payable | - | (77) | (225) | |||||||
Accounts payable | (798) | 250 | (86) | |||||||
All other items - net (a) | (211) | (127) | (241) | |||||||
Cash from operating activities | 4 263 | 3 626 | 3 587 | |||||||
Investing activities | ||||||||||
Additions to property, plant and equipment and intangibles | (1 231) | (899) | (1 177) | |||||||
Proceeds from asset sales | 272 | 279 | 212 | |||||||
Loans to equity company | (2) | - | - | |||||||
Cash from (used in) investing activities | (961) | (620) | (965) | |||||||
Financing activities | ||||||||||
Short-term debt - net | - | (65) | 72 | |||||||
Repayment of long-term debt | - | (1 722) | (70) | |||||||
Long-term debt issued | - | 500 | - | |||||||
Reduction in capitalized lease obligations | (3) | (4) | (4) | |||||||
Issuance of common shares under stock option plan | 7 | 12 | 10 | |||||||
Common shares purchased (note 11) | (2 210) | (2 358) | (1 818) | |||||||
Dividends paid | (330) | (319) | (315) | |||||||
Cash from (used in) financing activities | (2 536) | (3 956) | (2 125) | |||||||
Increase (decrease) in cash | 766 | (950) | 497 | |||||||
Cash at beginning of year | 1 208 | 2 158 | 1 661 | |||||||
Cash at end of year(b) | 1 974 | 1 208 | 2 158 |
(a) | Includes contribution to registered pension plans of $165 million (2007 - $163 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-4statements
millions of Canadian dollars | ||||||||
At December 31 | 2007 | 2006 | ||||||
Assets | ||||||||
Current assets | ||||||||
Cash | 1,208 | 2,158 | ||||||
Accounts receivable, less estimated doubtful amounts | 2,132 | 1,871 | ||||||
Inventories of crude oil and products(note 13) | 566 | 556 | ||||||
Materials, supplies and prepaid expenses | 128 | 151 | ||||||
Deferred income tax assets(note 5) | 660 | 573 | ||||||
Total current assets | 4,694 | 5,309 | ||||||
Long-term receivables, investments and other long-term assets | 766 | 104 | ||||||
Property, plant and equipment, less accumulated depreciation and depletion(note 3) | 10,561 | 10,457 | ||||||
Goodwill(note 3) | 204 | 204 | ||||||
Other intangible assets, net | 62 | 67 | ||||||
Total assets(note 3) | 16,287 | 16,141 | ||||||
Liabilities | ||||||||
Current liabilities | ||||||||
Short-term debt | 105 | 171 | ||||||
Accounts payable and accrued liabilities(a) | 3,335 | 3,080 | ||||||
Income taxes payable | 1,498 | 1,190 | ||||||
Current portion of long-term debt(b) | 3 | 907 | ||||||
Total current liabilities | 4,941 | 5,348 | ||||||
Long-term debt(note 4)(c) | 38 | 359 | ||||||
Other long-term obligations(note 7) | 1,914 | 1,683 | ||||||
Deferred income tax liabilities(note 5) | 1,471 | 1,345 | ||||||
Total liabilities | 8,364 | 8,735 | ||||||
Commitments and contingent liabilities(note 11) | ||||||||
Shareholders’ equity | ||||||||
Common shares at stated value(note 12)(d) | 1,600 | 1,677 | ||||||
Earnings reinvested | 7,071 | 6,462 | ||||||
Accumulated other comprehensive income | (748) | (733) | ||||||
Total shareholders’ equity | 7,923 | 7,406 | ||||||
Total liabilities and shareholders’ equity | 16,287 | 16,141 | ||||||
F-5
millions of Canadian dollars | ||||||||||||
At December 31 | 2007 | 2006 | 2005 | |||||||||
Common shares at stated value(note 12) | ||||||||||||
At beginning of year | 1,677 | 1,747 | 1,801 | |||||||||
Issued under the stock option plan | 12 | 10 | 38 | |||||||||
Share purchases at stated value | (89) | (80) | (92) | |||||||||
At end of year | 1,600 | 1,677 | 1,747 | |||||||||
Earnings reinvested | ||||||||||||
At beginning of year | 6,462 | 5,466 | 4,889 | |||||||||
Cumulative effect of accounting change(note 2) | 14 | – | – | |||||||||
Net income for the year | 3,188 | 3,044 | 2,600 | |||||||||
Share purchases in excess of stated value | (2,269) | (1,737) | (1,703) | |||||||||
Dividends | (324) | (311) | (320) | |||||||||
At end of year | 7,071 | 6,462 | 5,466 | |||||||||
Accumulated other comprehensive income | ||||||||||||
At beginning of year | (733) | (580) | (368) | |||||||||
Post-retirement benefits liability adjustment(note 6) | (87) | (733) | – | |||||||||
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost | 72 | – | – | |||||||||
Minimum pension liability adjustment(note 6) | – | 580 | (212) | |||||||||
At end of year | (748) | (733) | (580) | |||||||||
Shareholders’ equity at end of year | 7,923 | 7,406 | 6,633 | |||||||||
Comprehensive income for the year | ||||||||||||
Net income for the year | 3,188 | 3,044 | 2,600 | |||||||||
Post-retirement benefits liability adjustment(note 18) | (15) | – | – | |||||||||
Minimum pension liability adjustment(note 18) | – | 334 | (212) | |||||||||
Total comprehensive income for the year | 3,173 | 3,378 | 2,388 | |||||||||
F-6
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Imperial Oil Limited.
The company’s principal business is energy, involving the exploration, production, transportation and sale of crude oil and natural gas and the manufacture, transportation and sale of petroleum products. The company is also a major manufacturer and marketer of petrochemicals.
The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America. The financial statements include certain estimates that reflect management’s best judgment. Certain reclassifications to prior years have been made to conform to the 2008 presentation. All amounts are in Canadian dollars unless otherwise indicated.
1. | ||
Summary of significant accounting policies | ||
F-7
The | ||
F-8
Inventories
Inventories are recorded at the lower of cost or current market 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 Imperial’s share of earnings since the investment was made, less dividends received. Imperial’s 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 are 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 company’s 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 company’s 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 and natural gas commodity prices and foreign-currency exchange rates. Annual volumes are based on individual field production profiles, which are also updated annually.
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 company’s 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 mining and extraction assets begins when bitumen ore is produced on a sustained basis, and depreciation of bitumen upgrading assets begins when feed is introduced to the upgrading unit and maintained on a continuous 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 reserves. Investments in mining and transportation systems are generally depreciated on a straight-line basis over a 15-year life. Other mining related infrastructure costs that are of a long-term nature intended for continued use in or to provide long-term benefit to the operation, such as pre-production stripping, certain roads, etc., are depreciated on a unit-of-production basis based on proven reserves.
Oil sands assets held and used by the company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts are not recoverable. The impairment evaluation for oil sands assets is based on a comparison of undiscounted cash flows to book carrying value.
Gains or losses on assets sold are included in “investment and other income” in the consolidated statement of income.
(a) Oil sands are a semi-solid material composed of bitumen, sand, water and clays and are recovered through surface mining methods. Currently, the company’s oil sands production volumes are the company’s share of production volumes in the Syncrude joint venture, and the company’s reserves from oil sands operations are the company’s share of synthetic crude oil reserves in the Syncrude joint venture and the company’s share of mined bitumen reserves in the Kearl oil sands project.
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 values of the company’s 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.
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.
Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold.
Share-based compensation
The company awards share-based compensation to employees in the form of restricted stock units. Compensation expense is measured each reporting period based on the company’s current stock price and is recorded as “selling and general” expenses in the consolidated statement of income over the requisite service period of each award. See note 8 to the consolidated financial statements for further details.
Consumer taxes
Taxes levied on the consumer and collected by the company are excluded from the consolidated statement of income. These are primarily provincial taxes on motor fuels and the federal goods and services tax.
2. | ||
Accounting change for |
Effective January 1, 2008, the company adopted the Financial Accounting Standards Board’s (FASB) Statement No. 157 (SFAS 157), “Fair Value Measurements” for financial assets and liabilities that are measured at fair value and nonfinancial assets and liabilities that are remeasured at fair value on a recurring basis. SFAS 157 defines fair value, establishes a framework for measuring fair value when an entity is required to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measurements. The initial application of SFAS 157 had no material impact on the company’s financial statements. Effective January 1, 2009, SFAS 157 is applicable to all nonfinancial assets and liabilities that are measured at fair value.
3. | ||
Business segments | ||
F-9
Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash, long-term debt and liabilities associated with incentive compensation and post-retirement benefits liability adjustment. Net income in this segment primarily includes financing costs, interest income and share-based incentive compensation expenses.
Natural resources (a) | Petroleum products | Chemicals | ||||||||||||||||||||||||||||||||||
millions of dollars | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||||||||||
Revenues and other income | ||||||||||||||||||||||||||||||||||||
External sales (b) | 4,539 | 4,619 | 4,702 | 19,230 | 18,527 | 21,793 | 1,300 | 1,359 | 1,302 | |||||||||||||||||||||||||||
Intersegment sales | 4,146 | 3,837 | 3,487 | 2,305 | 2,256 | 2,224 | 335 | 345 | 363 | |||||||||||||||||||||||||||
Investment and other income | 233 | 111 | 331 | 52 | 105 | 60 | – | – | – | |||||||||||||||||||||||||||
8,918 | 8,567 | 8,520 | 21,587 | 20,888 | 24,077 | 1,635 | 1,704 | 1,665 | ||||||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||
Exploration | 106 | 32 | 43 | – | – | – | – | – | – | |||||||||||||||||||||||||||
Purchases of crude oil and products | 3,113 | 2,841 | 2,837 | 16,469 | 16,178 | 19,212 | 1,230 | 1,209 | 1,191 | |||||||||||||||||||||||||||
Production and manufacturing | 2,057 | 1,994 | 1,931 | 1,232 | 1,266 | 1,203 | 185 | 189 | 195 | |||||||||||||||||||||||||||
Selling and general (c) | 8 | 13 | 36 | 987 | 1,018 | 1,096 | 71 | 76 | 81 | |||||||||||||||||||||||||||
Federal excise tax | – | – | – | 1,307 | 1,274 | 1,278 | – | – | – | |||||||||||||||||||||||||||
Depreciation and depletion | 519 | 584 | 651 | 244 | 233 | 230 | 12 | 11 | 12 | |||||||||||||||||||||||||||
Financing costs (note 14) | 4 | 2 | – | 1 | 6 | 2 | – | – | – | |||||||||||||||||||||||||||
Total expenses | 5,807 | 5,466 | 5,498 | 20,240 | 19,975 | 23,021 | 1,498 | 1,485 | 1,479 | |||||||||||||||||||||||||||
Income before income taxes | 3,111 | 3,101 | 3,022 | 1,347 | 913 | 1,056 | 137 | 219 | 186 | |||||||||||||||||||||||||||
Income taxes(note 5) | ||||||||||||||||||||||||||||||||||||
Current | 682 | 602 | 955 | 491 | 174 | 409 | 42 | 60 | 69 | |||||||||||||||||||||||||||
Deferred | 60 | 123 | 59 | (65) | 115 | (47) | (2) | 16 | (4) | |||||||||||||||||||||||||||
Total income tax expense | 742 | 725 | 1,014 | 426 | 289 | 362 | 40 | 76 | 65 | |||||||||||||||||||||||||||
Net income | 2,369 | 2,376 | 2,008 | 921 | 624 | 694 | 97 | 143 | 121 | |||||||||||||||||||||||||||
Cash flow from (used in) operating activities | 2,411 | 3,024 | 2,440 | 1,151 | 507 | 799 | 109 | 161 | 94 | |||||||||||||||||||||||||||
Capital and exploration expenditures | 744 | 787 | 937 | 187 | 361 | 478 | 11 | 13 | 19 | |||||||||||||||||||||||||||
Property, plant and equipment | ||||||||||||||||||||||||||||||||||||
Cost | 15,285 | 14,926 | 14,229 | 6,655 | 6,581 | 6,350 | 718 | 702 | 701 | |||||||||||||||||||||||||||
Accumulated depreciation and depletion | (8,474) | (8,255) | (7,780) | (3,320) | (3,178) | (3,037) | (496) | (484) | (474) | |||||||||||||||||||||||||||
Net property, plant and equipment(d)(e) | 6,811 | 6,671 | 6,449 | 3,335 | 3,403 | 3,313 | 222 | 218 | 227 | |||||||||||||||||||||||||||
Total assets | 8,171 | 7,513 | 7,289 | 6,727 | 6,450 | 6,257 | 476 | 504 | 500 | |||||||||||||||||||||||||||
Corporate and other | Eliminations | Consolidated | ||||||||||||||||||||||||||||||||||
millions of dollars | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | |||||||||||||||||||||||||||
Revenues and other income | ||||||||||||||||||||||||||||||||||||
External sales (b) | – | – | – | 25,069 | 24,505 | 27,797 | ||||||||||||||||||||||||||||||
Intersegment sales | – | – | – | (6,786) | (6,438) | (6,074) | – | – | – | |||||||||||||||||||||||||||
Investment and other income | 89 | 67 | 26 | 374 | 283 | 417 | ||||||||||||||||||||||||||||||
89 | 67 | 26 | (6,786) | (6,438) | (6,074) | 25,443 | 24,788 | 28,214 | ||||||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||
Exploration | – | – | – | 106 | 32 | 43 | ||||||||||||||||||||||||||||||
Purchases of crude oil and products | – | – | – | (6,786) | (6,435) | (6,072) | 14,026 | 13,793 | 17,168 | |||||||||||||||||||||||||||
Production and manufacturing | – | – | – | – | (3) | (2) | 3,474 | 3,446 | 3,327 | |||||||||||||||||||||||||||
Selling and general (c) | 269 | 177 | 364 | 1,335 | 1,284 | 1,577 | ||||||||||||||||||||||||||||||
Federal excise tax | – | – | – | 1,307 | 1,274 | 1,278 | ||||||||||||||||||||||||||||||
Depreciation and depletion | 5 | 3 | 2 | 780 | 831 | 895 | ||||||||||||||||||||||||||||||
Financing costs (note 14) | 31 | 20 | 6 | 36 | 28 | 8 | ||||||||||||||||||||||||||||||
Total expenses | 305 | 200 | 372 | (6,786) | (6,438) | (6,074) | 21,064 | 20,688 | 24,296 | |||||||||||||||||||||||||||
Income before income taxes | (216) | (133) | (346) | 4,379 | 4,100 | 3,918 | ||||||||||||||||||||||||||||||
Income taxes(note 5) | ||||||||||||||||||||||||||||||||||||
Current | (52) | (60) | (72) | 1,163 | 776 | 1,361 | ||||||||||||||||||||||||||||||
Deferred | 35 | 26 | (51) | 28 | 280 | (43) | ||||||||||||||||||||||||||||||
Total income tax expense | (17) | (34) | (123) | 1,191 | 1,056 | 1,318 | ||||||||||||||||||||||||||||||
Net income | (199) | (99) | (223) | – | – | – | 3,188 | 3,044 | 2,600 | |||||||||||||||||||||||||||
Cash flow from (used in) operating activities | (45) | (105) | 118 | 3,626 | 3,587 | 3,451 | ||||||||||||||||||||||||||||||
Capital and exploration expenditures | 36 | 48 | 41 | 978 | 1,209 | 1,475 | ||||||||||||||||||||||||||||||
Property, plant and equipment | ||||||||||||||||||||||||||||||||||||
Cost | 304 | 269 | 246 | 22,962 | 22,478 | 21,526 | ||||||||||||||||||||||||||||||
Accumulated depreciation and depletion | (111) | (104) | (103) | (12,401) | (12,021) | (11,394) | ||||||||||||||||||||||||||||||
Net property, plant and equipment(d)(e) | 193 | 165 | 143 | 10,561 | 10,457 | 10,132 | ||||||||||||||||||||||||||||||
Total assets | 1,251 | 2,145 | 1,959 | (338) | (471) | (423) | 16,287 | 16,141 | 15,582 | |||||||||||||||||||||||||||
F-10Segment accounting policies are the same as those described in the summary of significant accounting policies. Upstream, Downstream and Chemical 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.
Upstream (a) | Downstream | Chemical | ||||||||||||||||
millions of dollars | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | |||||||||
Revenues and other income | ||||||||||||||||||
External sales (b) | 5 819 | 4 539 | 4 619 | 24 049 | 19 230 | 18 527 | 1 372 | 1 300 | 1 359 | |||||||||
Intersegment sales | 5 403 | 4 146 | 3 837 | 2 892 | 2 305 | 2 256 | 460 | 335 | 345 | |||||||||
Investment and other income | 18 | 233 | 111 | 271 | 52 | 105 | 1 | - | - | |||||||||
11 240 | 8 918 | 8 567 | 27 212 | 21 587 | 20 888 | 1 833 | 1 635 | 1 704 | ||||||||||
Expenses | ||||||||||||||||||
Exploration | 132 | 106 | 32 | - | - | - | - | - | - | |||||||||
Purchases of crude oil and products | 3 995 | 3 113 | 2 841 | 22 223 | 16 469 | 16 178 | 1 401 | 1 230 | 1 209 | |||||||||
Production and manufacturing | 2 569 | 2 057 | 1 994 | 1 452 | 1 232 | 1 266 | 208 | 185 | 189 | |||||||||
Selling and general (c) | 6 | 8 | 13 | 998 | 987 | 1 018 | 72 | 71 | 76 | |||||||||
Federal excise tax | - | - | - | 1 312 | 1 307 | 1 274 | - | - | - | |||||||||
Depreciation and depletion | 474 | 519 | 584 | 234 | 244 | 233 | 12 | 12 | 11 | |||||||||
Financing costs (note 13) | 2 | 4 | 2 | (5) | 1 | 6 | - | - | - | |||||||||
Total expenses | 7 178 | 5 807 | 5 466 | 26 214 | 20 240 | 19 975 | 1 693 | 1 498 | 1 485 | |||||||||
Income before income taxes | 4 062 | 3 111 | 3 101 | 998 | 1 347 | 913 | 140 | 137 | 219 | |||||||||
Income taxes(note 4) | ||||||||||||||||||
Current | 1 051 | 682 | 602 | (56) | 491 | 174 | 37 | 42 | 60 | |||||||||
Deferred | 88 | 60 | 123 | 258 | (65) | 115 | 3 | (2) | 16 | |||||||||
Total income tax expense | 1 139 | 742 | 725 | 202 | 426 | 289 | 40 | 40 | 76 | |||||||||
Net income | 2 923 | 2 369 | 2 376 | 796 | 921 | 624 | 100 | 97 | 143 | |||||||||
Cash flow from (used in) operating activities | 3 699 | 2 411 | 3 024 | 280 | 1 151 | 507 | 183 | 109 | 161 | |||||||||
Capital and exploration expenditures | 1 110 | 744 | 787 | 232 | 187 | 361 | 13 | 11 | 13 | |||||||||
Property, plant and equipment | ||||||||||||||||||
Cost | 16 344 | 15 285 | 14 926 | 6 776 | 6 655 | 6 581 | 732 | 718 | 702 | |||||||||
Accumulated depreciation and depletion | (8 832) | (8 474) | (8 255) | (3 452) | (3 320) | (3 178) | (514) | (496) | (484) | |||||||||
Net property, plant and equipment(d)(e) | 7 512 | 6 811 | 6 671 | 3 324 | 3 335 | 3 403 | 218 | 222 | 218 | |||||||||
Total assets | 8 758 | 8 171 | 7 513 | 6 038 | 6 727 | 6 450 | 431 | 476 | 504 | |||||||||
Corporate and other | Eliminations | Consolidated | ||||||||||||||||
millions of dollars | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | |||||||||
Revenues and other income | ||||||||||||||||||
External sales (b) | - | - | - | - | - | - | 31 240 | 25 069 | 24 505 | |||||||||
Intersegment sales | - | - | - | (8 755) | (6 786) | (6 438) | - | - | - | |||||||||
Investment and other income | 49 | 89 | 67 | - | - | - | 339 | 374 | 283 | |||||||||
49 | 89 | 67 | (8 755) | (6 786) | (6 438) | 31 579 | 25 443 | 24 788 | ||||||||||
Expenses | ||||||||||||||||||
Exploration | - | - | - | - | - | - | 132 | 106 | 32 | |||||||||
Purchases of crude oil and products | - | - | - | (8 754) | (6 786) | (6 435) | 18 865 | 14 026 | 13 793 | |||||||||
Production and manufacturing | - | - | - | (1) | - | (3) | 4 228 | 3 474 | 3 446 | |||||||||
Selling and general (c) | (38) | 269 | 177 | - | - | - | 1 038 | 1 335 | 1 284 | |||||||||
Federal excise tax | - | - | - | 1 312 | 1 307 | 1 274 | ||||||||||||
Depreciation and depletion | 8 | 5 | 3 | - | - | - | 728 | 780 | 831 | |||||||||
Financing costs (note 13) | 3 | 31 | 20 | - | - | - | - | 36 | 28 | |||||||||
Total expenses | (27) | 305 | 200 | (8 755) | (6 786) | (6 438) | 26 303 | 21 064 | 20 688 | |||||||||
Income before income taxes | 76 | (216) | (133) | - | - | - | 5 276 | 4 379 | 4 100 | |||||||||
Income taxes(note 4) | ||||||||||||||||||
Current | (27) | (52) | (60) | - | - | - | 1 005 | 1 163 | 776 | |||||||||
Deferred | 44 | 35 | 26 | - | - | - | 393 | 28 | 280 | |||||||||
Total income tax expense | 17 | (17) | (34) | - | - | - | 1 398 | 1 191 | 1 056 | |||||||||
Net income | 59 | (199) | (99) | - | - | - | 3 878 | 3 188 | 3 044 | |||||||||
Cash flow from (used in) operating activities | 101 | (45) | (105) | - | - | - | 4 263 | 3 626 | 3 587 | |||||||||
Capital and exploration expenditures | 8 | 36 | 48 | - | - | - | 1 363 | 978 | 1 209 | |||||||||
Property, plant and equipment | ||||||||||||||||||
Cost | 313 | 304 | 269 | - | - | - | 24 165 | 22 962 | 22 478 | |||||||||
Accumulated depreciation and depletion | (119) | (111) | (104) | - | - | - | (12 917) | (12 401) | (12 021) | |||||||||
Net property, plant and equipment(d)(e) | 194 | 193 | 165 | - | - | - | 11 248 | 10 561 | 10 457 | |||||||||
Total assets | 1 982 | 1 251 | 2 145 | (174) | (338) | (471) | 17 035 | 16 287 | 16 141 |
(a) | A significant portion of activities in the |
millions of dollars | 2007 | 2006 | 2005 | |||||||||
Total external and intersegment sales | 3,923 | 3,303 | 3,687 | |||||||||
Total expenses | 2,394 | 1,966 | 1,805 | |||||||||
Net income, after income tax | 1,224 | 1,148 | 1,249 | |||||||||
Total current assets | 1,211 | 516 | 245 | |||||||||
Long-term assets | 4,868 | 4,833 | 4,742 | |||||||||
Total current liabilities | 705 | 810 | 967 | |||||||||
Other long-term obligations | 485 | 344 | 382 | |||||||||
Cash flow from operating activities | 697 | 1,229 | 1,223 | |||||||||
Cash (used in) investing activities | (131) | (403) | (403) | |||||||||
millions of dollars | 2008 | 2007 | 2006 | |||||||
Total external and intersegment sales | 4 766 | 3 923 | 3 303 | |||||||
Total expenses | 3 002 | 2 394 | 1 966 | |||||||
Net income, after income tax | 1 302 | 1 224 | 1 148 | |||||||
Total current assets | 758 | 1 043 | 516 | |||||||
Long-term assets | 5 380 | 4 868 | 4 833 | |||||||
Total current liabilities | 659 | 705 | 810 | |||||||
Other long-term obligations | 619 | 460 | 344 | |||||||
Cash flow from operating activities | 1 891 | 865 | 1 229 | |||||||
Cash (used in) investing activities | (685) | (131) | (403) |
(b) | Includes export sales to the United States, as follows: |
millions of dollars | 2007 | 2006 | 2005 | |||||||||
Natural resources | 2,013 | 1,936 | 1,633 | |||||||||
Petroleum products | 922 | 869 | 856 | |||||||||
Chemicals | 768 | 793 | 750 | |||||||||
Total export sales | 3,703 | 3,598 | 3,239 | |||||||||
millions of dollars | 2008 | 2007 | 2006 | |||||||
Upstream | 3 095 | 2 013 | 1 936 | |||||||
Downstream | 1 685 | 922 | 869 | |||||||
Chemical | 844 | 768 | 793 | |||||||
Total export sales | 5 624 | 3 703 | 3 598 |
(c) | Consolidated selling and general expenses include delivery costs from final storage areas to customers of | ||
(d) | Includes property, plant and equipment under construction of | ||
(e) | All goodwill has been assigned to the |
millions of dollars | 2007 | 2006 | ||||||||||
Long-term debt (a)(b)(c) | – | 318 | ||||||||||
Capital leases (d) | 38 | 41 | ||||||||||
Total long-term debt(e)(f) | 38 | 359 | ||||||||||
4. | Income taxes |
millions of dollars | 2008 | 2007 | 2006 | |||||||
Current income tax expense | 1 005 | 1 163 | 776 | |||||||
Deferred income tax expense (a) | 393 | 28 | 280 | |||||||
Total income tax expense(b) | 1 398 | 1 191 | 1 056 | |||||||
Statutory corporate tax rate (percent) | 29.5 | 30.1 | 32.8 | |||||||
Increase/(decrease) resulting from: | ||||||||||
Enacted tax rate change | - | (2.2) | (2.7) | |||||||
Other | (3.0) | (0.7) | (4.3) | |||||||
Effective income tax rate | 26.5 | 27.2 | 25.8 |
(a) | |||
millions of dollars | 2007 | 2006 | 2005 | |||||||||
Current income tax expense | 1,163 | 776 | 1,361 | |||||||||
Deferred income tax expense (a) | 28 | 280 | (43) | |||||||||
Total income tax expense(b) | 1,191 | 1,056 | 1,318 | |||||||||
Statutory corporate tax rate (percent) | 30.1 | 32.8 | 35.6 | |||||||||
Increase/(decrease) resulting from: | ||||||||||||
Non-deductible royalty payments to governments | – | – | 3.8 | |||||||||
Resource allowance in lieu of royalty deduction | – | – | (5.2) | |||||||||
Enacted tax rate change | (2.2) | (2.7) | – | |||||||||
Other | (0.7) | (4.3) | (0.6) | |||||||||
Effective income tax rate | 27.2 | 25.8 | 33.6 | |||||||||
The provisions for deferred income taxes in | |||
(b) | Cash outflow from income taxes, plus investment credits earned, was $1,101 million in 2008 (2007 – $1,395 million, |
F-11
millions of dollars | 2007 | 2006 | 2005 | |||||||||
Post-retirement benefits liability adjustment: | ||||||||||||
Net actuarial loss/(gain) | 21 | |||||||||||
Amortization of net actuarial loss/(gain) | (24) | |||||||||||
Prior service cost | 13 | |||||||||||
Amortization of prior service cost | (6) | |||||||||||
Total post-retirement benefits liability adjustment | 4 | 212 | – | |||||||||
Minimum pension liability adjustment | – | (146) | 105 | |||||||||
millions of dollars | 2008 | 2007 | 2006 | |||||||
Post-retirement benefits liability adjustment: | ||||||||||
Net actuarial loss/(gain) | 102 | 21 | ||||||||
Amortization of net actuarial (loss)/gain | (26) | (24) | ||||||||
Prior service cost | - | 13 | ||||||||
Amortization of prior service cost | (5) | (6) | ||||||||
Total post-retirement benefits liability adjustment | 71 | 4 | 212 | |||||||
Minimum pension liability adjustment | - | - | (146) |
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 | 2007 | 2006 | ||||||
Depreciation and amortization | 1,624 | 1,588 | ||||||
Successful drilling and land acquisitions | 276 | 263 | ||||||
Pension and benefits | (249) | (311) | ||||||
Site restoration | (156) | (161) | ||||||
Net tax loss carryforwards (a) | (37) | (42) | ||||||
Capitalized interest | 49 | 50 | ||||||
Other | (36) | (42) | ||||||
Deferred income tax liabilities | 1,471 | 1,345 | ||||||
LIFO inventory valuation | (547) | (448) | ||||||
Other | (113) | (125) | ||||||
Deferred income tax assets | (660) | (573) | ||||||
Valuation allowance | – | – | ||||||
Net deferred income tax liabilities | 811 | 772 | ||||||
millions of dollars | 2008 | 2007 | 2006 | |||||||
Depreciation and amortization | 1685 | 1624 | 1588 | |||||||
Successful drilling and land acquisitions | 258 | 276 | 263 | |||||||
Pension and benefits | (312) | (249) | (311) | |||||||
Site restoration | (202) | (156) | (161) | |||||||
Net tax loss carryforwards (a) | (2) | (37) | (42) | |||||||
Capitalized interest | 53 | 49 | 50 | |||||||
Other | 9 | (36) | (42) | |||||||
Deferred income tax liabilities | 1 489 | 1 471 | 1 345 | |||||||
LIFO inventory valuation | (301) | (547) | (448) | |||||||
Other | (60) | (113) | (125) | |||||||
Deferred income tax assets | (361) | (660) | (573) | |||||||
Valuation allowance | - | - | - | |||||||
Net deferred income tax liabilities | 1 128 | 811 | 772 |
(a) | Tax losses can be carried forward indefinitely. |
Unrecognized tax benefits
As of January 1, 2007, the company adopted the Financial Accounting Standards Board (FASB) Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”. The company’s unrecognizedcumulative adjustment for the accounting change reported in 2007 was an after-tax gain of $14 million. The gain reflected the recognition of several refund claims with associated interest, partly offset by increased income tax reserves.
Unrecognized tax benefits at December 31, 2007 were $170 million.reflect the difference between positions taken on tax returns and the amounts recognized in the financial statements. Resolution of the related tax positions will take many years to complete. Accordingly, itIt is difficult to predict the timing of resolution for individual tax positions.positions, since such timing is not entirely within the control of the company. The company’s effective tax rate will be reduced if any of these tax benefits isare subsequently recognized.
The changefollowing table summarizes the movement in the amount of unrecognized tax benefits is as follows:
millions of dollars | 2008 | 2007 | ||||||||
January 1 balance | 170 | 142 | ||||||||
Additions for prior years’ tax positions | 9 | 28 | ||||||||
Reductions for prior years’ tax positions | (29) | - | ||||||||
December 31 balance | 150 | 170 |
The 2008 and 2007 changes in unrecognized tax benefits did not have a material effect on the company’s net income or cash flow. The company’s tax filings from 20032004 to 20062007 are subject to examination by the tax authorities. The Canada Revenue Agency has proposed certain adjustments to the company’s filings for several years in the period 19871994 to 2002.2003. Management is currently evaluating those proposed adjustments. Management believes that a number of outstanding matters before 2003 is2004 are expected to be resolved in 2008.2009. The impact on unrecognized tax benefits and the company’s effective income tax rate from these matters is not expected to be material.
The company classifies interest on income tax related balances as interest expense or interest income and classifies tax related penalties as operating expense.
5. | Employee retirement benefits |
Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension income and certain health care and life insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients. Funding of registered retirement plans complies with federal and provincial pension regulations, and the company makes contributions to the plans based 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 company’s 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 company’s defined benefit plans are measured on December 31.
F-12
Pension benefits | Other benefits | |||||||||||||||||||||
2008 | 2007 | 2008 | 2007 | |||||||||||||||||||
Assumptions used to determine benefit obligations at December 31 (percent) | ||||||||||||||||||||||
Discount rate | 7.50 | 5.75 | 7.50 | 5.75 | ||||||||||||||||||
Long-term rate of compensation increase | 4.50 | 3.50 | 4.50 | 3.50 | ||||||||||||||||||
millions of dollars | ||||||||||||||||||||||
Change in projected benefit obligation | ||||||||||||||||||||||
Projected benefit obligation at January 1 | 4 685 | 4 716 | 426 | 441 | ||||||||||||||||||
Current service cost | 94 | 100 | 6 | 6 | ||||||||||||||||||
Interest cost | 271 | 246 | 25 | 23 | ||||||||||||||||||
Amendments | - | 41 | - | - | ||||||||||||||||||
Actuarial loss/(gain) | (583 | ) | (131 | ) | (61 | ) | (25 | ) | ||||||||||||||
Benefits paid (a) | (331 | ) | (287 | ) | (24 | ) | (19 | ) | ||||||||||||||
Projected benefit obligation at December 31 | 4 136 | 4 685 | 372 | 426 | ||||||||||||||||||
Accumulated benefit obligation at December 31 | 3 719 | 4 208 | ||||||||||||||||||||
Change in plan assets | ||||||||||||||||||||||
Fair value at January 1 | 4 098 | 4 089 | ||||||||||||||||||||
Actual return/(loss) on plan assets | (699 | ) | 93 | |||||||||||||||||||
Company contributions | 165 | 163 | ||||||||||||||||||||
Benefits paid (b) | (252 | ) | (247 | ) | ||||||||||||||||||
Fair value at December 31 | 3 312 | 4 098 | ||||||||||||||||||||
Plan assets in excess of/(less than) projected benefit obligation at December 31 | ||||||||||||||||||||||
Funded plans | (488 | ) | (213 | ) | - | - | ||||||||||||||||
Unfunded plans | (336 | ) | (374 | ) | (372 | ) | (426 | ) | ||||||||||||||
Total (c) | (824 | ) | (587 | ) | (372 | ) | (426 | ) |
(a) | Benefit payments for funded and unfunded plans. |
(b) | Benefit payments for funded plans only. |
(c) | Fair value of assets less projected benefit obligation shown above. |
Effective December 31, 2006, the company adopted 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)”, 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 comprehensive income.
Pension benefits | Other post-retirement benefits | |||||||||||||||||||||
millions of dollars | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | ||||||||||||||||
Amounts recorded in the consolidated balance sheet consist of: | ||||||||||||||||||||||
Current liabilities | (22) | (34) | (23) | (25) | ||||||||||||||||||
Other long-term obligations | (802) | (553) | (349) | (401) | ||||||||||||||||||
Total recorded | (824) | (587) | (372) | (426) | ||||||||||||||||||
Amounts recorded in accumulated other comprehensive income consist of: | ||||||||||||||||||||||
Net actuarial loss/(gain) | 1 331 | 977 | (25) | 42 | ||||||||||||||||||
Prior service cost | 77 | 95 | - | - | ||||||||||||||||||
Total recorded in accumulated other comprehensive income, before tax | 1 408 | 1 072 | (25) | 42 | ||||||||||||||||||
Assumptions used to determine net periodic benefit cost for years ended December 31 (percent) | ||||||||||||||||||||||
Discount rate | 5.75 | 5.25 | 5.00 | 5.75 | 5.25 | 5.00 | ||||||||||||||||
Long-term rate of compensation increase | 3.50 | 3.50 | 3.50 | 3.50 | 3.50 | 3.50 | ||||||||||||||||
Long-term rate of return on funded assets | 8.00 | 8.00 | 8.25 | - | - | - |
Other post-retirement | ||||||||||||||||||||||||
Pension Benefits | benefits | |||||||||||||||||||||||
2007 | 2006 | 2007 | 2006 | |||||||||||||||||||||
Assumptions used to determine benefit obligations at December 31 (percent) | ||||||||||||||||||||||||
Discount rate | 5.75 | 5.25 | 5.75 | 5.25 | ||||||||||||||||||||
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 | 4,716 | 4,784 | 441 | 458 | ||||||||||||||||||||
Current service cost | 100 | 100 | 6 | 8 | ||||||||||||||||||||
Interest cost | 246 | 238 | 23 | 23 | ||||||||||||||||||||
Amendments | 41 | – | – | (2) | ||||||||||||||||||||
Actuarial loss/(gain) | (131) | (122) | (25) | (19) | ||||||||||||||||||||
Benefits paid (a) | (287) | (284) | (19) | (27) | ||||||||||||||||||||
Projected benefit obligation at December 31 | 4,685 | 4,716 | 426 | 441 | ||||||||||||||||||||
Accumulated benefit obligation at December 31 | 4,208 | 4,207 | ||||||||||||||||||||||
Change in plan assets | ||||||||||||||||||||||||
Fair value at January 1 | 4,089 | 3,419 | ||||||||||||||||||||||
Actual return on plan assets | 93 | 514 | ||||||||||||||||||||||
Company contributions | 163 | 395 | ||||||||||||||||||||||
Benefits paid (b) | (247) | (239) | ||||||||||||||||||||||
Fair value at December 31 | 4,098 | 4,089 | ||||||||||||||||||||||
Plan assets in excess of/(less than) projected benefit obligation at December 31 | ||||||||||||||||||||||||
Funded plans | (213) | (294) | – | – | ||||||||||||||||||||
Unfunded plans | (374) | (333) | (426) | (441) | ||||||||||||||||||||
Total (c) | (587) | (627) | (426) | (441) | ||||||||||||||||||||
(a) Benefit payments for funded and unfunded plans. (b) Benefit payments for funded plans only. (c) Fair value of assets less projected benefit obligation shown above. | ||||||||||||||||||||||||
Effective December 31, 2006, the company adopted 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)”, 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 comprehensive income. | ||||||||||||||||||||||||
Pension Benefits | Other post-retirement benefits | |||||||||||||||||||||||
millions of dollars | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | ||||||||||||||||||
Amounts recorded in the consolidated | ||||||||||||||||||||||||
balance sheet consist of: | ||||||||||||||||||||||||
Current liabilities | (34) | (28) | (25) | (23) | ||||||||||||||||||||
Other long-term obligations | (553) | (599) | (401) | (418) | ||||||||||||||||||||
Total recorded | (587) | (627) | (426) | (441) | ||||||||||||||||||||
Amounts recorded in accumulated other | ||||||||||||||||||||||||
comprehensive income consist of: | ||||||||||||||||||||||||
Net actuarial loss/(gain) | 977 | 947 | 42 | 73 | ||||||||||||||||||||
Prior service cost | 95 | 74 | – | – | ||||||||||||||||||||
Total recorded in accumulated other comprehensive income, before tax | 1,072 | 1,021 | 42 | 73 | ||||||||||||||||||||
Assumptions used to determine net periodic benefit | ||||||||||||||||||||||||
benefit cost for years ended December 31 (percent) | ||||||||||||||||||||||||
Discount rate | 5.25 | 5.00 | 5.75 | 5.25 | 5.00 | 5.75 | ||||||||||||||||||
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 | 8.00 | 8.25 | 8.25 | – | – | – | ||||||||||||||||||
Pension benefits | Other post- retirement benefits | |||||||||||||
millions of dollars | 2008 | 2007 | 2006 | 2008 | 2007 | 2006 | ||||||||
Components of net periodic benefit cost | ||||||||||||||
Current service cost | 94 | 100 | 100 | 6 | 6 | 8 | ||||||||
Interest cost | 271 | 246 | 238 | 25 | 23 | 23 | ||||||||
Expected return on plan assets | (330) | (329) | (299) | - | - | - | ||||||||
Amortization of prior service cost | 19 | 20 | 20 | - | - | - | ||||||||
Recognized actuarial loss/(gain) | 91 | 76 | 114 | 6 | 6 | 8 | ||||||||
Net periodic benefit cost | 145 | 113 | 173 | 37 | 35 | 39 | ||||||||
Changes in amounts recorded in accumulated other comprehensive income | ||||||||||||||
Net actuarial loss/(gain) | 446 | 105 | 72 | (61) | (25) | 73 | ||||||||
Amortization of net actuarial (loss)/gain included in net periodic benefit cost | (91) | (76) | - | (5) | (6) | - | ||||||||
Prior service cost | - | 41 | 74 | - | - | - | ||||||||
Amortization of prior service cost included in net periodic benefit cost | (19) | (20) | - | - | - | - | ||||||||
Total recorded in accumulated other comprehensive income | 336 | 50 | 146 | (66) | (31) | 73 | ||||||||
Total recorded in net periodic benefit cost and accumulated other comprehensive income, before tax | 481 | 163 | 319 | (29) | 4 | 112 |
F-13
Pension Benefits | Other post-retirement benefits | |||||||||||||||||||||||
millions of dollars | 2007 | 2006 | 2005 | 2007 | 2006 | 2005 | ||||||||||||||||||
Components of net periodic benefit cost | ||||||||||||||||||||||||
Current service cost | 100 | 100 | 86 | 6 | 8 | 7 | ||||||||||||||||||
Interest cost | 246 | 238 | 239 | 23 | 23 | 24 | ||||||||||||||||||
Expected return on plan assets | (329) | (299) | (257) | – | – | – | ||||||||||||||||||
Amortization of prior service cost | 20 | 20 | 25 | – | – | – | ||||||||||||||||||
Recognized actuarial loss/(gain) | 76 | 114 | 83 | 6 | 8 | 7 | ||||||||||||||||||
Net periodic benefit cost | 113 | 173 | 176 | 35 | 39 | 38 | ||||||||||||||||||
Changes in amounts recorded in | ||||||||||||||||||||||||
accumulated other comprehensive income | ||||||||||||||||||||||||
Net actuarial loss/(gain) | 105 | 72 | 317 | (25) | 73 | – | ||||||||||||||||||
Amortization of net actuarial loss/(gain) included in net periodic benefit cost | (76) | – | – | (6) | – | – | ||||||||||||||||||
Prior service cost | 41 | 74 | – | – | – | – | ||||||||||||||||||
Amortization of prior service cost included in net periodic benefit cost | (20) | – | – | – | – | – | ||||||||||||||||||
Total recorded in accumulated other comprehensive income | 50 | 146 | 317 | (31) | 73 | – | ||||||||||||||||||
Total recorded in net periodic benefit cost and other accumulated other comprehensive income, before tax | 163 | 319 | 493 | 4 | 112 | 38 | ||||||||||||||||||
A summary of the change in accumulated other comprehensive income is shown in the table below:
Total pension and other | ||||||||||||||||||||||||
post-retirement benefits | ||||||||||||||||||||||||
millions of dollars | 2007 | 2006 | 2005 | |||||||||||||||||||||
(Charge)/credit to accumulated other comprehensive income, before tax | (19) | (219) | (317) | |||||||||||||||||||||
Deferred income tax (charge)/credit (note 5) | 4 | 66 | 105 | |||||||||||||||||||||
(Charge)/credit to accumulated other comprehensive income, after tax | (15) | (153) | (212) | |||||||||||||||||||||
Total pension and other post-retirement benefits | ||||||
millions of dollars | 2008 | 2007 | 2006 | |||
(Charge)/credit to accumulated other comprehensive income, before tax | (270) | (19) | (219) | |||
Deferred income tax (charge)/credit (note 4) | 71 | 4 | 66 | |||
(Charge)/credit to accumulated other comprehensive income, after tax | (199) | (15) | (153) |
The preceding data in this note conforms 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 8.506.50 percent in 20082009 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 20072008 long-term expected return of 8.00 percent used in the calculations of pension expense compares to an actual rate of return of 5.00 percent and 8.31 percent over the past decade of 8.29 percent.
The company’s pension plan asset allocation at December 31, 20062007 and 2007,2008, and target allocation for 20082009 are as follows:
Target | Percentage of plan assets at | |||||||||||
allocation | December 31 | |||||||||||
Asset category (percent) | 2008 | 2007 | 2006 | |||||||||
Equity securities | 50 – 75 | 61 | 64 | |||||||||
Debt securities | 25 – 50 | 38 | 36 | |||||||||
Other | 0 – 10 | 1 | – | |||||||||
Target allocation | Percentage of plan assets at December 31 | |||||
Asset category (percent) | 2008 | 2007 | ||||
Equity securities | 50-75 | 63 | 61 | |||
Debt securities | 25-50 | 36 | 38 | |||
Other | 0-10 | 1 | 1 |
The company’s 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.
F-14
Pension benefits | ||||||||
millions of dollars | 2007 | 2006 | ||||||
For funded pension plans with accumulated benefit obligations in excess of plan assets: | ||||||||
Projected benefit obligation | 398 | 375 | ||||||
Accumulated benefit obligation | 318 | 308 | ||||||
Fair value of plan assets | 254 | 239 | ||||||
Accumulated benefit obligation less fair value of plan assets | 64 | 69 | ||||||
For unfunded plans covered by book reserves: | ||||||||
Projected benefit obligation | 373 | 333 | ||||||
Accumulated benefit obligation | 347 | 314 | ||||||
Estimated 2008 amortization from accumulated | Other post- | |||||||
other comprehensive income | Pension | retirement | ||||||
millions of dollars | benefits | benefits | ||||||
Net actuarial loss/(gain) (a) | 81 | 4 | ||||||
Prior service cost (b) | 18 | – | ||||||
Pension benefits | ||||
millions of dollars | 2008 | 2007 | ||
For funded pension plans with accumulated benefit obligations in excess of plan assets: | ||||
Projected benefit obligation | 3 800 | 398 | ||
Accumulated benefit obligation | 3 420 | 318 | ||
Fair value of plan assets | 3 312 | 254 | ||
Accumulated benefit obligation less fair value of plan assets | 108 | 64 | ||
For unfunded plans covered by book reserves: | ||||
Projected benefit obligation | 336 | 373 | ||
Accumulated benefit obligation | 299 | 347 |
Estimated 2009 amortization from accumulated
other comprehensive income
millions of dollars | Pension benefits | Other post-retirement benefits | ||
Net actuarial loss/(gain) (a) | 110 | (1) | ||
Prior service cost (b) | 17 | - |
(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 and SFAS 106. |
Cash flows
Benefit payments expected in:
Other post- | ||||||||
Pension | retirement | |||||||
millions of dollars | benefits | benefits | ||||||
2008 | 261 | 24 | ||||||
2009 | 265 | 24 | ||||||
2010 | 268 | 24 | ||||||
2011 | 273 | 24 | ||||||
2012 | 279 | 25 | ||||||
2013 - 2017 | 1,505 | 126 | ||||||
millions of dollars | Pension benefits | Other post-retirement benefits | ||
2009 | 274 | 25 | ||
2010 | 277 | 25 | ||
2011 | 282 | 25 | ||
2012 | 288 | 25 | ||
2013 | 296 | 25 | ||
2014 - 2018 | 1 623 | 128 |
In 2008,2009, the company expects to make cash contributions of about $170$200 million to its pension plan.
Sensitivities
A one percent change in the assumptions at which retirement liabilities could be effectively settled is as follows:
One | One | |||||||
Increase/(decrease) | percent | percent | ||||||
millions of dollars | increase | decrease | ||||||
Rate of return on plan assets: | ||||||||
Effect on net benefit cost, before tax | (40 | ) | 40 | |||||
Discount rate: | ||||||||
Effect on net benefit cost, before tax | (60 | ) | 70 | |||||
Effect on benefit obligation | (555 | ) | 680 | |||||
Rate of pay increases: | ||||||||
Effect on net benefit cost, before tax | 45 | (35 | ) | |||||
Effect on benefit obligation | 160 | (140 | ) | |||||
Increase/(decrease) millions of dollars | One percent increase | One percent decrease | ||
Rate of return on plan assets: | ||||
Effect on net benefit cost, before tax | (40) | 40 | ||
Discount rate: | ||||
Effect on net benefit cost, before tax | (55) | 65 | ||
Effect on benefit obligation | (440) | 530 | ||
Rate of pay increases: | ||||
Effect on net benefit cost, before tax | 35 | (30) | ||
Effect on benefit obligation | 115 | (105) |
A one percent change in the assumed health-care cost trend rate would have the following effects:
One | One | |||||||
Increase/(decrease) | percent | percent | ||||||
millions of dollars | increase | decrease | ||||||
Effect on service and interest cost components | 4 | (3 | ) | |||||
Effect on benefit obligation | 44 | (35 | ) | |||||
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Increase/(decrease) millions of dollars | One percent increase | One percent decrease | |||
Effect on service and interest cost components | 4 | (3 | ) | ||
Effect on benefit obligation | 31 | (26 | ) |
Other long-term obligations |
millions of dollars | 2008 | 2007 | ||
Employee retirement benefits (note 5) (a) | 1 151 | 954 | ||
Asset retirement obligations and other environmental liabilities (b) | 728 | 522 | ||
Share-based incentive compensation liabilities (note 8) | 203 | 210 | ||
Other obligations | 216 | 228 | ||
Total other long-term obligations | 2 298 | 1 914 |
millions of dollars | 2007 | 2006 | ||||||
Employee retirement benefits (note 6)(a) | 954 | 1,017 | ||||||
Asset retirement obligations and other environmental liabilities (b) | 522 | 438 | ||||||
Share-based incentive compensation liabilities (note 9) | 210 | 128 | ||||||
Other obligations | 228 | 100 | ||||||
Total other long-term obligations | 1,914 | 1,683 | ||||||
(a) | Total recorded employee retirement benefit obligations also include |
(b) | Total asset retirement obligations and other environmental liabilities also include |
millions of dollars | 2007 | 2006 | ||||||
January 1 balance | 422 | 367 | ||||||
Additions | 71 | 61 | ||||||
Accretion | 25 | 22 | ||||||
Settlement | (30 | ) | (28 | ) | ||||
December 31 balance | 488 | 422 | ||||||
The |
millions of dollars | 2008 | 2007 | ||
January 1 balance | 488 | 422 | ||
Additions | 232 | 71 | ||
Accretion | 29 | 25 | ||
Settlement | (38) | (30) | ||
December 31 balance | 711 | 488 |
7. | Derivatives and | |
The company did not enter into any energy derivatives, foreign-exchange forward contracts or currency and interest-rate swaps 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 company’s 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 company’s financial instruments and the recorded book value.
Share-based incentive compensation programs | ||
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Incentive share units have value if the market price of the company’s 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 company’s 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 ten years from issuance. The units may expire earlier if employment is terminated other than by retirement, death or disability.
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 company’s 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 company’s 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. The company may also issue units where fifty percent of the units are exercisable five years following the grant date and the remainder are exercisable on the later of ten years following the grant date or the retirement date of the recipient. 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 company’s 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 a factor of three.
All units require settlement by cash payments with the following exceptions. The restricted stock unit program was amended for units granted in 2002 and subsequent 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. For units where fifty percent are exercisable five years following the grant date and the remainder exercisable on the later of ten years following the grant date or the retirement date of the recipient, the recipient may receive one common share of the company per unit or elect to receive cash payment for all units to be exercised.
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 company’s stock. Under this method, compensation expense related to the units of
these programs is measured each reporting period based on the company’s current stock price and is recorded in the consolidated statement of income over the requisite service period of each award. All incentive share units have vested as of December 31, 2004.
The following table summarizes information about these units for the year ended December 31, 2007:2008:
Incentive share units | Deferred share units | Restricted stock units | ||||
Outstanding at January 1, 2008 | 6 758 850 | 90 526 | 10 219 851 | |||
Granted | - | 10 937 | 1 760 795 | |||
Exercised | (1 249 335) | (15 092) | (1 328 233) | |||
Cancelled or adjusted | 1 500 | - | (55 850) | |||
Outstanding at December 31, 2008 | 5 511 015 | 86 371 | 10 596 563 |
Incentive | Deferred | Restricted | ||||||||||
share units | share units | stock units | ||||||||||
Outstanding at January 1, 2007 | 9,071,250 | 84,448 | 9,996,390 | |||||||||
Granted | – | 6,078 | 1,713,488 | |||||||||
Exercised | (2,316,300) | – | (1,471,847) | |||||||||
Cancelled or adjusted | 3,900 | – | (18,180) | |||||||||
Outstanding at December 31, 2007 | 6,758,850 | 90,526 | 10,219,851 | |||||||||
There was a $33 million favourable adjustment to previously recorded compensation expenses for these programs in the year ended December 31, 2008. The compensation expense charged against income for these programs was $202 million and $133 million for the years ended December 31, 2007 and $238 million2006, respectively. Income tax expense associated with the favourable adjustment to compensation expense for the year ended December 31, 2007, 2006,2008 was $5 million, and 2005, respectively. Totalthe income tax benefit recognized in income related to this compensation expense for these programs was $67 million $45 million and $127$45 million for the yearyears ended December 31, 2007 2006 and 2005,2006, respectively. Cash payments of $115 million, $159 million $162 million and $169$162 million for these programs were made in 2008, 2007 and 2006, and 2005, respectively.
As of December 31, 2007,2008, there was $294$201 million of total before-tax unrecognized compensation expensesexpense related to nonvested restricted stock units based on the company’s 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, 2007.
Incentive stock options
In April 2002, incentive stock options were granted for the purchase of the company’s common shares. For units exercised subsequent to the company’s May 2006 three-for-one split, the company has indicated that it will give the option holders the right to purchase three shares for each original stock option granted. The exercise price is $15.50 per share (adjusted to reflect the three-for-one share split). Up to 50 percentAll options have vested as 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.December 31, 2008. 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 the yearyears ended December 31, 2008, 2007 2006 and 2005. Cash received from stock option exercises for the year ended December 31, 2007 was $12 million.2006. The aggregate intrinsic value of stock options exercised was $17 million, $25 million $18 million and $43$18 million in the yearyears ended December 31, 2008, 2007 2006 and 2005,2006, respectively, and for the balance of outstanding stock options is $185$109 million as at December 31, 2007.
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. Purchase may be discontinued at any time without prior notice.
The following table summarizes information about stock options for the year ended December 31, 2007:2008:
2008 | ||||||
Units | Exercise price (dollars) | Remaining contractual term (years) | ||||
Incentive stock options | ||||||
Outstanding at January 1 | 4 728 780 | 15.50 | ||||
Granted | - | |||||
Exercised | (434 145) | 15.50 | ||||
Cancelled or adjusted | - | |||||
Outstanding at December 31 | 4 294 635 | 15.50 | 3.3 |
2007 | ||||||||||||
Units | Exercise | Remaining | ||||||||||
price | contractual | |||||||||||
(dollars) | term (years) | |||||||||||
Incentive stock options | ||||||||||||
Outstanding at January 1, 2007 | 5,527,665 | 15.50 | ||||||||||
Granted | – | |||||||||||
Exercised | (791,385) | 15.50 | ||||||||||
Cancelled or adjusted | (7,500) | |||||||||||
Outstanding at December 31, 2007 | 4,728,780 | 15.50 | 4.3 | |||||||||
Investment and other income |
Investment and other income includes gains and losses on asset sales as follows:
millions of dollars | 2008 | 2007 | 2006 | |||
Proceeds from asset sales | 272 | 279 | 212 | |||
Book value of assets sold | 31 | 64 | 78 | |||
Gain/(loss) on asset sales, before tax(a)(b) | 241 | 215 | 134 | |||
Gain/(loss) on asset sales, after tax(a)(b) | 209 | 156 | 96 |
millions of dollars | 2007 | 2006 | 2005 | |||||||||
Proceeds from asset sales | 279 | 212 | 440 | |||||||||
Book value of assets sold | 64 | 78 | 96 | |||||||||
Gain/(loss) on asset sales, before tax(a)(b) | 215 | 134 | 344 | |||||||||
Gain/(loss) on asset sales, after tax(a)(b) | 156 | 96 | 233 | |||||||||
(a) | ||
2007 included a gain of $200 million ($142 million, after tax) from the sale of the company’s interests in a natural gas producing property in British Columbia and in the Willesden Green producing property. |
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(b) | 2008 included a gain of $219 million ($187 million, after tax) from the sale of the company’s equity investment in Rainbow Pipe Line Co. Ltd. |
10. | Litigation and other contingencies |
A variety of claims have been made against Imperial Oil Limited and its subsidiaries in a number of lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel, to assess the need for accounting recognition or disclosure of these contingencies. The company accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The company does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavourable outcome is reasonably possible and which are significant, the company discloses the nature of the contingency and, where feasible, an estimate of the possible loss. 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 company’s operations or financial condition.
The Alberta government enacted changes to the oil and gas and generic oil sands royalty regime effective 2009. The impacts of the changes have been incorporated in the company’s 2008 oil and gas reserves and mined bitumen reserves calculation, where appropriate. In November 2008, Imperial, along with the other Syncrude joint-venture owners, signed an agreement with the Government of Alberta to amend the existing Syncrude Crown Agreement. Under the amended agreement, beginning January 1, 2010, Syncrude will begin transitioning to the new oil sands royalty regime by paying additional royalties, the exact amount of which will depend on production levels from 2010 to 2015. Also, beginning January 1, 2009, Syncrude’s royalty will be based on bitumen value with upgrading costs and revenues excluded from the calculation. The impacts of the amended agreement have been incorporated in the 2008 synthetic crude oil reserves calculation.
The company was contingently liable at December 31, 2008 for a maximum of $79 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.
Additionally, the company has other commitments arising in the normal course of business for operating and capital needs, all of which are expected to be fulfilled with no adverse consequences material to the company’s operations or financial condition. Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are non-cancelable or cancelable only under certain conditions and that third parties have used to secure financing for the facilities that will provide the contracted goods and services.
Payments due by period | ||||||||||||||
millions of dollars | 2009 | 2010 | 2011 | 2012 | 2013 | After 2013 | Total | |||||||
Unconditional purchase obligations (a) | 127 | 63 | 74 | 43 | 82 | 31 | 420 |
Payments due by period | ||||||||||||||||||||||||||||
millions of dollars | 2008 | 2009 | 2010 | 2011 | 2012 | After 2012 | Total | |||||||||||||||||||||
Unconditional purchase obligations(a) | 99 | 96 | 64 | 64 | 121 | 38 | 482 | |||||||||||||||||||||
(a) | Undiscounted obligations of |
Common shares |
As at | As at | |||||||
thousands of shares | Dec. 31 2007 | Dec. 31 2006 | ||||||
Authorized | 1,100,000 | 1,100,000 | ||||||
Purchased shares | Millions of | |||||||
Year | (thousands) | dollars | ||||||
1995 to 2005 | 750,109 | 8,635 | ||||||
2006 | 45,514 | 1,818 | ||||||
2007 | 50,516 | 2,358 | ||||||
Cumulative purchases to date | 846,139 | 12,811 | ||||||
Exxon Mobil Corporation’s 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 company’s common share activities are summarized below: | ||||||||
Thousands of shares | Millions of dollars | |||||||
Balance as at January 1, 2005 | 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 | ||||||
Issued for cash under the stock option plan | 791 | 12 | ||||||
Purchases | (50,516) | (89) | ||||||
Balance as at December 31, 2007 | 903,263 | 1,600 | ||||||
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2007 | 2006 | 2005 | ||||||||||
Net income per common share - basic | ||||||||||||
Net income (millions of dollars) | 3,188 | 3,044 | 2,600 | |||||||||
Weighted average number of common shares outstanding (thousands of shares) | 928,527 | 975,128 | 1,024,119 | |||||||||
Net income per common share (dollars) | 3.43 | 3.12 | 2.54 | |||||||||
Net income per common share - diluted | ||||||||||||
Net income (millions of dollars) | 3,188 | 3,044 | 2,600 | |||||||||
Weighted average number of common shares outstanding (thousands of shares) | 928,527 | 975,128 | 1,024,119 | |||||||||
Effect of employee stock-based awards (thousands of shares) | 5,811 | 4,460 | 4,179 | |||||||||
Weighted average number of common shares outstanding, assuming dilution (thousands of shares) | 934,338 | 979,588 | 1,028,298 | |||||||||
Net income per common share (dollars) | 3.41 | 3.11 | 2.53 | |||||||||
million of dollars | 2007 | 2006 | ||||||
Crude oil | 211 | 211 | ||||||
Petroleum products | 298 | 277 | ||||||
Chemical products | 43 | 54 | ||||||
Natural gas and other | 14 | 14 | ||||||
Total inventories of crude oil and products | 566 | 556 | ||||||
millions of dollars | 2007 | 2006 | 2005 | |||||||||
Debt-related interest | 62 | 63 | 45 | |||||||||
Capitalized interest | (36) | (48) | (41) | |||||||||
Net interest expense | 26 | 15 | 4 | |||||||||
Other interest | 10 | 13 | 4 | |||||||||
Total financing costs (a) | 36 | 28 | 8 | |||||||||
As at Dec. 31 2008 | As at Dec. 31 2007 | |||
Authorized | 1 100 000 | 1 100 000 |
From 1995 to 2007, the company purchased shares under twelve 12-month normal course share purchase programs, as well as an auction tender. On June 25, 2008, a 12-month share repurchase program was implemented with an allowable purchase of about 44 million shares (five percent of the total at June 16, 2008), less shares purchased from Exxon Mobil Corporation and shares purchased by the employee savings plan and company pension fund. The results of these activities are shown below.
Year | Purchased shares (thousands) | Millions of dollars | ||
1995 to 2006 | 795 623 | 10 453 | ||
2007 | 50 516 | 2 358 | ||
2008 | 44 295 | 2 210 | ||
Cumulative purchases to date | 890 434 | 15 021 |
Exxon Mobil Corporation’s 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 earnings reinvested.
The company’s common share activities are summarized below:
Thousands of shares | Millions of dollars | |||
Balance as at January 1, 2006 | 997 875 | 1 747 | ||
Issued for cash under the stock option plan | 627 | 10 | ||
Purchases at stated value | (45 514) | (80) | ||
Balance as at December 31, 2006 | 952 988 | 1 677 | ||
Issued for cash under the stock option plan | 791 | 12 | ||
Purchases at stated value | (50 516) | (89) | ||
Balance as at December 31, 2007 | 903 263 | 1 600 | ||
Issued for cash under the stock option plan | 434 | 7 | ||
Purchases at stated value | (44 295) | (79) | ||
Balance as at December 31, 2008 | 859 402 | 1 528 |
The following table provides the calculation of basic and diluted earnings per share:
2008 | 2007 | 2006 | ||||
Net income per common share - basic | ||||||
Net income (millions of dollars) | 3 878 | 3 188 | 3 044 | |||
Weighted average number of common shares outstanding (thousands of shares) | 882 604 | 928 527 | 975 128 | |||
Net income per common share (dollars) | 4.39 | 3.43 | 3.12 | |||
Net income per common share - diluted | ||||||
Net income (millions of dollars) | 3 878 | 3 188 | 3 044 | |||
Weighted average number of common shares outstanding (thousands of shares) | 882 604 | 928 527 | 975 128 | |||
Effect of employee share-based awards (thousands of shares) | 6 418 | 5 811 | 4 460 | |||
Weighted average number of common shares outstanding, assuming dilution (thousands of shares) | 889 022 | 934 338 | 979 588 | |||
Net income per common share (dollars) | 4.36 | 3.41 | 3.11 |
12. | Miscellaneous financial information |
In 2008, net income included an after-tax gain of $27 million (2007 - $25 million gain, 2006 - $14 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, 2008 by $994 million (2007 - $1,953 million). Inventories of crude oil and products at year-end consisted of the following:
millions of dollars | 2008 | 2007 | ||||
Crude oil | 328 | 211 | ||||
Petroleum products | 268 | 298 | ||||
Chemical products | 65 | 43 | ||||
Natural gas and other | 12 | 14 | ||||
Total inventories of crude oil and products | 673 | 566 |
Research and development costs in 2008 were $83 million (2007 – $89 million, 2006 – $73 million) before investment tax credits earned on these expenditures of $9 million (2007 – $9 million, 2006 – $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 $11 million received from equity investments in 2008 (2007 – $22 million, 2006 – $18 million).
13. | Financing costs |
millions of dollars | 2008 | 2007 | 2006 | |||
Debt-related interest | 8 | 62 | 63 | |||
Capitalized interest | (8) | (36) | (48) | |||
Net interest expense | - | 26 | 15 | |||
Other interest | - | 10 | 13 | |||
Total financing costs (a) | - | 36 | 28 |
(a) | Cash interest payments in |
Leased facilities and capitalized lease obligations | ||
At December 31, 2008, the company held non-cancelable operating leases covering office buildings, rail cars, service stations and other properties with minimum undiscounted lease commitments totaling $432 million as indicated in the following table:
Payments due by period | ||||||||||||||
millions of dollars | 2009 | 2010 | 2011 | 2012 | 2013 | After 2013 | Total | |||||||
Lease payments under minimum commitments (a) | 64 | 53 | 55 | 53 | 49 | 158 | 432 |
Payments due by period | ||||||||||||||||||||||||||||
After | ||||||||||||||||||||||||||||
millions of dollars | 2008 | 2009 | 2010 | 2011 | 2012 | 2012 | Total | |||||||||||||||||||||
Lease payments under minimum commitments (a) | 55 | 52 | 45 | 26 | 15 | 39 | 232 | |||||||||||||||||||||
(a) | Total rental expense incurred for operating leases in |
Capitalized lease 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 11.0 percent in 2008 (2007 - 10.9 percent). Total capitalized lease obligations also include $4 million in current liabilities (2007 - $4 million).
Principal payments on capital leases of approximately $4 million a year are due in each of the next five years.
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, natural gas, 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 company’s participation in a number of upstream activities conducted jointly in Canada.
The company has existing agreements with ExxonMobil to:
(a) |
(b) | operate the Western Canada production properties owned by ExxonMobil. This contractual agreement is designed to |
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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 the company and ExxonMobil. The company and ExxonMobil retain ownership of their respective assets, and there is no impact on operations or |
(c) | provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by | |
(d) | ||
millions of dollars | 2007 | 2006 | 2005 | |||||||||
Current income tax expense (note 5) | 1,163 | 776 | 1,361 | |||||||||
Federal excise tax | 1,307 | 1,274 | 1,278 | |||||||||
Property taxes included in expenses | 112 | 100 | 99 | |||||||||
Payroll and other taxes included in expenses | 56 | 46 | 52 | |||||||||
GST/QST/HST collected (a) | 2,573 | 2,715 | 2,703 | |||||||||
GST/QST/HST input tax credits (a) | (2,095) | (2,293) | (2,344) | |||||||||
Other consumer taxes collected for governments | 1,707 | 1,667 | 1,613 | |||||||||
Crown royalties | 1,016 | 904 | 620 | |||||||||
Total paid or payable to governments | 5,839 | 5,189 | 5,382 | |||||||||
Less investment tax credits and other receipts | 9 | 11 | 9 | |||||||||
Net paid or payable to governments | 5,830 | 5,178 | 5,373 | |||||||||
Net paid or payable to: | ||||||||||||
Federal government | 2,682 | 2,352 | 2,736 | |||||||||
Provincial governments | 3,036 | 2,726 | 2,538 | |||||||||
Local governments | 112 | 100 | 99 | |||||||||
Net paid or payable to governments | 5,830 | 5,178 | 5,373 | |||||||||
Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.
As at December 31, 2008, the company had outstanding loans of $35 million (2007 - $33 million) to Montreal Pipe Line Limited, in which the company has an equity interest, for financing of the equity company’s capital expenditure programs and working capital requirements.
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