UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE

SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 20072008  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

Title of each class
None

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......

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......

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......

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......

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.

856,836,280.


PART I

      Page
Item 1.    
  
Item 1.

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11

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Government Regulation

13

The Company Online

  14
Item 1A.    14
Item 1B.    16
Item 2.    16
Item 3.    16
Item 4.    16
PART II
Item 5.  
Item 5.  17
Item 6.    18
Item 7.    18
Item 7A.    2928
Item 8.    29
Item 9.    3433
Item 9A.    3433
Item 9B.    33
PART III
Item 10.  
Item 10.  3534
Item 11.    3837
Item 12.    4653
Item 13.    4754
Item 14.    4855
PART IV
Item 15.  
Item 15.  4956
Index to Financial Statements  F-1
Management’s Report on Internal Control over Financial Reporting  F-2
Auditors’ Report of Independent Registered Public Accounting Firm  F-2

All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated.

Note that numbers may not add due to rounding.

The following table sets forth (i) the rates of exchange for the Canadian dollar, expressed in U.S. dollars, in effect at the end of each of the periods indicated, (ii) the average of exchange rates in effect on the last day of each month during such periods, and (iii) the high and low exchange rates during such periods, in each case based on the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York.

                     
  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

ThisStatements in this report contains forward looking information on future production, project start upsregarding expectations, plans and future events or conditions are forward-looking statements. Actual future results, including demand growth and energy source mix; financing sources; the resolution of contingencies and uncertain tax positions; the effect of changes in prices and other market conditions; and environmental and capital spending. Actual resultsexpenditures could differ materially depending on a number of factors, such as a resultthe outcome of market conditions orcommercial negotiations; changes in law, government policy, operating conditions, costs, project schedules, operating performance,the supply of and demand for crude oil, and natural gas, commercial negotiationsand petroleum and petrochemical products; political or regulatory events; and other technicalfactors discussed in Item 1A of the company’s 2008 Form 10K and economic factors.
in the management’s discussion and analysis of financial condition and results of operations contained herein.

PART I

Item 1. Business.
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.

Financial Information by Operating Segments (under U.S. GAAP)
                     
  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 F-10.F-9. Total external sales include $4,894 million for 2005 and $3,584 million for 2004 and $2,851 million for 2003 for purchases/sales contracts with the same counterparty. Associated costs were included in “purchases of crude oil and products”. Effective January 1, 2006, these purchases/sales were recorded on a net basis. See note 1, Summary of significant Accounting Policies.
(2)(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)(3)Includes primarily interest charges on the debt obligations of the company, interest income on investments and incentive compensation expenses, and intersegment consolidating adjustments.expenses.
(4)(4)The identifiable assets in each operating segment represent the net book value of the tangible and intangible assets attributed to such segment. Net intangible assets representing unrecognized prior service costs associated with the recognition of the additional minimum pension liability in 2005 and prior years2004 have been reclassified from the operating segments to the corporate and other segment. Amounts reclassified into the corporate and other segment were $92 million for 2005 and $97 million in 2004, and $89 million for 2003.2004. This change has no impact on total identifiable assets at December 31 of 2005 and prior years.2004.

3


The company’s operations are conducted in three main segments: natural resources (“upstream”), petroleum products (“downstream”)Upstream, Downstream and chemicals. Natural resourcesChemical. Upstream operations include the exploration for, and production of, conventional crude oil, natural gas, upgraded crude oil and heavy oil. Petroleum productsDownstream operations consist of the transportation, refining and blending of crude oil and refined products and the distribution and marketing thereof. The chemicalsChemical operations consist of the manufacturing and marketing of various petrochemicals.

Upstream

Natural Resources

Petroleum and Natural Gas Production

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)(2)Net production is gross production less the mineral owners’ or governments’ share or both.
(3)(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 the Cold Lake production operations.
(4)(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 2004, conventional liquids production increased primarily due to increased natural gas liquids production from the Wizard Lake gas cap.

In 2005 and 2006 conventional production fell mainly due to the natural decline of the 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.

In 2008, Syncrude production declined primarily due to increased planned and unplanned maintenance activities, including continuing work to improve reliability performance.

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)(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


     In 2004 natural gas production increased primarily due to increased production from the Wizard Lake gas cap. In 2005, gross natural gas production increased due to increased production from the Nisku and Wizard Lake gas caps and the Medicine Hat gas field. In 2006, gas production decreased primarily due to natural decline. In 2007, the lower production volume was primarily due to decline in production from the gas cap at Wizard Lake.
In 2008, the most significant reason for lower production volume was the completion of the Wizard Lake blowdown.

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)(2)Unit production costs are sometimes referred to as lifting costs.

Canadian crude oil prices are mainly determined by international crude oil markets, which are volatile, and the impact of foreign exchange rates.

Canadian natural gas prices are determined by North American gas markets, which are also volatile, and the impact of foreign exchange rates. Natural gas prices throughout North America increased in the second half of 2005 due to supply disruptions from hurricane damage to facilities in the U.S. Gulf Coast.

     In 2004, average unit production costs decreased mainly due to higher production from the Wizard Lake gas cap.

In 2005, average unit production costs increased mainly due to higher costs of purchased natural gas at Cold Lake. In 2006, average production costs increased due to lower gas production and higher liquids royalties resulting in lower net liquids production. Liquids royalties were higher in the year due to increased realizations for Cold Lake production. In 2007, unit production costs were higher primarily as a result of lower gas and liquids volumes due to decline in production fromat Wizard Lake.

In 2008, unit production costs were higher, primarily as a result of lower gas and liquids volumes due to production decline at Wizard Lake, and higher spending to improve reliability at Cold Lake.

The company has interests in a large number of facilities related to the production of crude oil and natural gas. Among these facilities are 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.

plants at the Bonnie Glen field.

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)(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


recovered by using various methods of enhanced recovery. The company’s largest enhanced recovery projects are located at the West Pembina oil field.
The company produces natural gas from a large number of gas fields located in the Western Provinces, primarily in Alberta. The company also has a nine percent interest in a project to develop and produce natural gas reserves in the Sable Island area off the coast of the Province of Nova Scotia.

Cold Lake

The company holds about 192,000194,000 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.

techniques.

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.

expansion at Cold Lake that would add about 30,000 barrels a day of production before royalties.

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.

2004.

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.

     The company holds varying interests in heavy oil lands totaling about 168,000 leased net acres in the Athabasca area. The company, as part of an industry consortium

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.

Kearl Leases

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


Syncrude has an operating license issued by the Province of Alberta which is effective until 2035. This license permits Syncrude to mine oil sands and produce synthetic crude oil from approved development areas on oil sands leases. Syncrude holdsjoint-venture owners hold eight oil sands leases covering about 248,300250,000 acres in the Athabasca oil sands deposit. Issued by the Province of Alberta, the leases are automatically renewable as long as oil sands operations are ongoing or the leases are part of an approved development plan. Syncrude leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30 and 31 (containing no proven reserves) are included within a development plan approved by the Province of Alberta. There were no known previous commercial operations on these leases prior to the start-up of operations in 1978.
     As

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.

     In 2007, the Alberta government proposed changeswill begin transitioning to the genericnew oil sands royalty regime by paying additional royalties, the exact amount of which will depend on production levels from 2010 to 2015. Also, beginning in 2009. The Syncrude Joint Venture owners have a Crown AgreementJanuary 1, 2009, Syncrude’s royalty will be based on bitumen value with upgrading costs and revenues excluded from the Province of Alberta that codifies the royalty rates through December 31, 2015. The Syncrude Joint Venture owners are in discussions with the Alberta government to determine if an amended agreement can be negotiated that would transition Syncrude to the new generic royalty regime before 2016.
calculation.

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.

The final determination of the remission amount applicable to Syncrude operations up to 2003 is a matter currently being litigated with the Government of Canada.

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


eastern Canada or exported to the United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and a 160 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. Recycled water is the primary water source, and incremental raw water is drawn, under license, from the Athabasca River. The company’s 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities is about $3.4 billion.

In 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)(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)(3)Reflects the company’s 25 percent interest in production, less applicable royalties payable to the Province of Alberta.
Other Oil Sands Activity

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.

Alberta grid. Recycled water will be the primary water source, and incremental raw water will be drawn, under license, from the Athabasca River.

Other Oil Sands Activity

The company is continuing to evaluate about 69,000 net acres of other undeveloped oil sands acreage.

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Land Holdings

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.
(2)(3)Net acres exclude the interests of others.
(3)(4)Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and other Northwest Territories, Nunavut and Yukon regions.
(4)(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).

Exploration and Development

The company has been involved in the exploration for and development of petroleum and natural gas in the Western Provinces, in the Canada Lands and in the Atlantic Offshore.

     The company’s exploration strategy in the Western Provinces is to search for hydrocarbons on its existing land holdings and especially near established facilities. Higher risk areas are evaluated through shared ventures with other companies.

The following table sets forth the conventional and heavy oil net exploratory and development wells that were drilled or participated in by the company during the five years 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.

               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


well count in 2004. Weather related delays in 2005 resulted in a reduction in the number of wellswas drilled in the ongoing shallow gas development program.
Norman Wells.

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.

In 2007 and 2008, the company acquired interest in about 76,000 net acres in the natural gas prone Horn River area and commenced exploration drilling and evaluation of the Horn River acreage in late 2008. The company’s exploration strategy in other areas of the Western Provinces is to search for hydrocarbons on its existing land holdings especially near established facilities.

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.

2010.

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.

survey was conducted in 2008.

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.

     The company retains a 20 percent interest in

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.

Also in 2008, one exploration licence in which the company retainshad a 70 percent interest in one exploration licence for about 279,000 gross acres farther offshore in deeper water. In 2003, one exploratory wellwater was drilled on this licence, without commercial success.allowed to expire. The company is not planning further exploration in these areas.

In early 2004, the company acquired a 25 percent interest in eight deep water exploration licences offshore Newfoundland in the Orphan Basin for about 5,251,000 gross acres. In February 2005, the company reduced its interest to 15 percent through an agreement with another company. The 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

Labrador, which is scheduled to be allowed to expire in April 2009.


Downstream

Supply

Petroleum Products
Supply
To supply the requirements of its own refineries and condensate requirements for blending with crude bitumen, the company supplements its own production with substantial purchases from others.

The company purchases domestic crude oil at freely negotiated prices from a number of sources. Domestic purchases of crude oil are generally made under renewable contracts with 30 to 60 day cancellation terms.

Crude oil from foreign sources is purchased by the company at market prices mainly through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil throughout the world).

Refining

The company owns and operates four refineries. Two of these, the Sarnia refinery and the Strathcona refinery, have lubricating oil production facilities. The Strathcona refinery processes Canadian crude oil, and the Dartmouth, Sarnia and Nanticoke refineries process a combination of Canadian and foreign crude oil. In addition to crude oil, the company purchases finished products to supplement its refinery production.

In 2007,2008, 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)(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.

full capacity.

Distribution

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.

Marketing

The company markets more than 700 petroleum products throughout Canada under well known brand names, most notably Esso and Mobil, to all types of customers.

The company sells to the motoring public through Esso 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


The approximate daily volumes of net petroleum products (excluding purchases/sales contracts with the same counterparty) sold during the five years ended December 31, 2007,2008, are set out in the following table:
                     
  2007  2006  2005  2004  2003 
  (thousands of cubic metres a day) 
 
Gasolines  33.1   32.7   33.4   33.2   33.0 
Heating, Diesel and Jet Fuels  26.0   26.4   26.9   27.3   26.2 
Heavy Fuel Oils  5.2   5.1   6.0   5.9   5.4 
Lube Oils and Other Products  6.9   7.7   7.6   7.0   5.8 
   
Net petroleum product sales  71.2   71.9   73.9   73.4   70.4 
   

               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.

2007.

ChemicalsChemical

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 

               2008                  2007                  2006                  2005                  2004
   (thousands of tonnes a day)

Petrochemicals

  2.8  3.1  3.0  3.0  3.3

Research

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.

Environmental Protection

The company is concerned with and active in protecting the environment in connection with its various operations. The company works in cooperation with government agencies and industry associations to deal with existing, and to anticipate potential, environmental protection issues. In the past five years, the company has made capital 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


2004, costing about $650 million, reduced sulphur in motor gasolines, meeting a requirement of the Government of Canada. The second project completed in 2006 was to meet a new Government of Canada regulation requiring ultra-low sulphur on-road diesel fuel, which cost about $500 million in total. In 2007,2008, the company’s capital and other expenditures relating to environmental protection totaled approximately $135$620 million, which was spent primarily on emissions reductions at Syncrude and company owned facilities, remediation of idled facilities and operations, as well as on ultra-low sulphur off-road diesel fuel. Capital and other expenditures relating to environmental protection are expected to be about $200$750 million in 2008.
2009.

Human Resources

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.

Competition

The Canadian petroleum, natural gas and chemical industries are highly competitive. Competition exists in the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities and the refining, distribution and marketing of petroleum products and chemicals. The petroleum industry also competes with other industries in supplying energy, fuel and other needs of consumers.

Government Regulation

Petroleum and Natural Gas Rights

Most of the 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


and natural gas liquids vary depending on a number of parameters, including well production volumes, selling prices and the date of initial production.recovery methods. For information with respect to royalty rates for Norman Wells, Cold Lake, Syncrude and Syncrude,Kearl, see “Natural Resources“Upstream – Petroleum and Natural Gas Production”.

Investment Canada Act

The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. The acquisition of natural resource properties may, in certain circumstances, be considered to be a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval.

The Act also requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to 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 Online

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.

Item 1A.     Risk Factors.

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.

commodity prices.

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

14


changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for clean up costs and damages. The company cannot assure that the costs of complying with environmental legislation in the future will not have a material adverse effect on its financial condition or results of operations. The company anticipates that changes in environmental legislation may require, among other things, reductions in emissions to the air from its operations and result in increased capital expenditures. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on the company’s financial condition or results of operations.

Climate Change

In April 2007, the Government of Canada announced its intent to introduce a set of regulations to limit emissions of greenhouse gas and air pollutants from major industrial facilities in Canada, beginning in 2010, although the details of the regulations have not been finalized. Consequently, attempts to assess the impact on the company are premature. The company will continue to monitor the development of legal requirements in this area.

In the Province of Alberta, regulations governing greenhouse gas emissions from large industrial facilities came into effect July 1, 2007. 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.

15


Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.

Project Factors

The 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

     See Item 7A for a discussion of

During 2008, credit markets tightened, and the impact of market risks and other uncertainties.

global economy slowed. In 2009, the company does not expect to be dependent on credit markets to fund normal operations or investment plans.

Item 1B Unresolved Staff Comments.
Item 1BUnresolved Staff Comments.

Not applicable.

Item 2.   Properties.
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.

Item 3.   Legal Proceedings.
Item 3.Legal Proceedings.

Not applicable.

Item 4.   Submission of Matters to a Vote of Security Holders.
Item 4.Submission of Matters to a Vote of Security Holders.

Not applicable.

16


PART II

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. 30Sep. 30Dec. 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

(a) Adjusted to reflect(1)The company’s shares are listed on the May 2006 three-for-oneToronto Stock Exchange. The company’s shares also trade in the United States of America on the NYSE Alternext, formerly known as the American Stock Exchange. The symbol on these exchanges for the company’s common shares is IMO. Share prices were obtained from stock exchange records. U.S. dollar share split.price presented is based on consolidated U.S. market data.
     The company’s shares are listed on the Toronto Stock Exchange and are admitted to unlisted trading on the American Stock Exchange in New York. The symbol on these exchanges for the company’s common shares is IMO. Share prices were obtained from stock exchange records adjusted for the three-for-one share split.

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.

17


On June 23, 2008, the company announced by news release that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid and will continue its share repurchase program. The new program enables the company to repurchase up to a maximum of 44,194,961 common shares, including common shares purchased for the company’s employee savings plan, the company’s employee retirement plan and from Exxon Mobil Corporation during the period of June 25, 2008 to June 24, 2009. If not previously terminated, the program will end on June 24, 2009.

Issuer purchases of equity securities (1)
                       
 
 Period  (a) Total number  (b) Average price  (c) Total number of  (d) Maximum number 
    of shares  paid per share  shares purchased as  (or approximate dollar value) 
    (or units)  (or unit)  part of publicly  of shares that may yet be 
    purchased       announced plans or  purchased under the plans or 
              programs  programs 
 
October 2007
(October 1 - October 31)
   1,498,890   $48.00    1,498,890    30,445,586  
 
November 2007
(November 1 - November 30)
   6,656,699   $51.45    6,656,699    23,737,240  
 
December 2007
(December 1 - December 31)
   2,971,920   $51.70    2,971,920    20,714,852  
 
(1)The purchases were pursuant to a 12 month normal course share purchase program that was renewed on June 25, 2007 under which the company may purchase up to 46,459,967 of its outstanding common shares less any shares purchased by the employee savings plan and the company pension fund. If not previously terminated, the program will terminate on June 24, 2008.

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

Item 6. Selected Financial Data.
                     
  2007 2006 2005 2004 2003
  (millions of dollars)
Total operating revenues(a)
  25,069   24,505   27,797   22,408   19,094 
Net income  3,188   3,044   2,600   2,052   1,705 
Total assets  16,287   16,141   15,582   14,027   12,337 
Long term debt  38   359   863   367   859 
Other long term obligations  1,914   1,683   1,728   1,525   1,314 
  (dollars)
Net income/share – basic(b)
  3.43   3.12   2.54   1.92   1.53 
Net income/share – diluted(b)
  3.41   3.11   2.53   1.91   1.53 
Cash dividends/share(b)
  0.35   0.32   0.31   0.29   0.29 
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

(a) Total operating(1)Operating revenues include $4,894 million for 2005 and $3,584 million for 2004 and $2,851 million for 2003 for purchases/sales contracts with the same counterparty. Associated costs were included in “purchases of crude oil and products”. Effective January 1, 2006, these purchases/sales were recorded on a net basis. See note 1 (page F-7), Summary of Significant Accounting Policies.
 
(b)(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.
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.

18


Business environment and risk assessment

Long-term business outlook

Economic and population growth are expected to remain the primary drivers of energy demand, globally and in North America. The company expects the global economy to grow at an average rate of about three percent per year through 2030. The combination of population and economic growth should lead to an increase in demand for

primary energy at an average rate of 1.31.2 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.

Natural resources
areas and unconventional resources.

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.

Petroleum products

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.

Canadian wholesale prices in particular are largely determined by wholesale prices in adjacent U.S. regions. These prices and factors are continually monitored and provide input to operating decisions about which raw materials to buy, facilities to operate and products to make. However, there are no reliable indicators of future market factors that accurately predict changes in margins from period to period.

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.

Chemicals

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

19


Dartmouth with the refineries. The company also benefits from its integration within ExxonMobil’s North American chemicalschemical businesses, enabling Imperial to maintain a leadership position in its key market segments.

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.

Natural resources
lower overall downstream margins.

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).

     Average realizations forcompany’s heavy oil at Cold Lake, moved generally in line with that of the lighter crude oil. The price of Bow River, a benchmark for Canadian heavy oil, increased by about 56 percent in U.S. dollars were about five percent higher for2008 from 2007 and fell much below the year’s average by the end of the year. Also mainly because of a stronger Canadian dollar, the company’s average realizations for Cold Lake heavy oil were lower by about two percent in 2007.

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 
     Total gross production of crude oil and NGLs averaged 275,000 barrels a day, compared with 272,000 barrels in 2006 (2005 – 261,000).

           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 (2006139,000)152,000). IncreasedLower production was due to the cyclic nature of production at Cold Lake and increased volumes from the ongoing development drilling program.

     ProductionLake.

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 (2006214,000)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 (200653,000)65,000).

Gross production of conventional oil decreased to 29,00027,000 barrels a day from 31,00029,000 barrels in 2006 (20052007 (200638,000)31,000) as a result of natural decline in Western Canadian reservoirs and the impact of divested properties.

     Gross production of NGLs available for sale averaged 16,000 barrels a day in 2007, down from 24,000 barrels in 2006 (2005 – 31,000), mainly due to the declining NGL content of Wizard Lake gas production.

20

reservoirs.


Gross production of natural gas decreased to 458310 million cubic feet a day from 556458 million in 2006 (2005 — 5802007 (2006 – 556 million). LowerThe most significant reason for the lower production volumes were primarily due to decline,was the completion of production, as expected, in production from the Wizard Lake gas cap at Wizard Lake.
     In 2007, the company realized a gainblowdown.

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).

production from Wizard Lake.

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  

 (a)(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.
 (b)(2)Diluent is natural gas condensate or other light hydrocarbons added to the Cold Lake heavy oil to facilitate transportation to market by pipeline.
 (c)(3)Production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected.
     Operating

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.

     On May 1, 2007, the company confirmed and implemented a management services agreement with Syncrude Canada Ltd., under which Syncrude will be provided operational, technical and business management services from Imperial and Exxon Mobil Corporation.
Petroleum products
     Net income from petroleum products was a record $921 million, $297 million higher than 2006. Increased earnings wereEarnings decreased primarily due to improved refinery operations including lower refineryoverall downstream margins and unfavourable inventory effects totaling about $230 million. Earnings were also lower due to higher planned maintenance and project activities which contributedcosts of about $205$40 million and stronger industry refining and marketing margins totalinglower sales volumes of about $190$40 million. These positive factors were partially offset by a gain of $187 million from the negative impactsale of a stronger Canadian dollar of about $60 million and the absence of favourable tax effects of about $40 million.
company’s equity investment in Rainbow Pipe Line Co. Ltd.

Financial statistics

                     
  2007 2006 2005 2004 2003
  (millions of dollars)
Net income  921   624   694   556   462 
Operating revenues(a)
  21,535   20,783   24,017   19,169   16,004 
Sale of petroleum products
                     
  2007 2006 2005 2004 2003
  (millions of litres a day (b))
Gasolines  33.1   32.7   33.4   33.2   33.0 
Heating, diesel and jet fuels  26.0   26.4   26.9   27.3   26.2 
Heavy fuel oils  5.2   5.1   6.0   5.9   5.4 
Lube oils and other products  6.9   7.7   7.6   7.0   5.8 
   
Net petroleum product sales  71.2   71.9   73.9   73.4   70.4 
   
Total domestic sales of petroleum products(percent)
  94.8   95.1   95.3   93.0   93.3 
   

21


               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

Refinery utilization
                     
  2007 2006 2005 2004 2003
  (thousands of barrels a day (b))
Total refinery throughput (c)  442   442   466   467   450 
Refinery capacity at December 31  502   502   502   502   502 
Utilization of total refinery capacity(percent)
  88   88   93   93   90 

           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

 (a)(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 products”products��. Effective January 1, 2006, these purchases/sales were recorded on a net basis. See note 1, Summary of Significant Accounting Policies, on page F-7.
 (b)(2)Volumes a day are calculated by dividing total volumes for the year by the number of days in the year.
 (c)(3)Crude oil and feedstocks sent directly to atmospheric distillation units.
     One thousand litres are approximately 6.3 barrels.
     Margins

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.

2007.

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.

     The company’sfull capacity.

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.

     Operating

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.

Chemicals
costs.

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.

margins for intermediate products and lower sales volumes for both polyethylene and intermediate products.

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

 (a)(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).

(2006 – $1,703), contributing to higher margins for polyethylene products.

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.

     Operating

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.

higher energy prices.

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.


Liquidity and capital resources

Sources and uses of cash

         
  2007 2006
  (millions of dollars)
Cash provided by/(used in)        
Operating activities  3,626   3,587 
Investing activities  (620)  (965)
Financing activities  (3,956)  (2,125)
   
Increase/(decrease) in cash and cash equivalents  (950)  497 
   
Cash and cash equivalents at end of year  1,208   2,158 
   

               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.

requirements and to optimize returns on cash balances.

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.

increase.

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:

               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.

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     The Alberta Energy and Utilities Boardreceived and the Governmentproject is planned to advance in phases. Production from the first phase of Canada gave conditional regulatory approval in February 2007Kearl is expected to average approximately 110,000 barrels of bitumen a day before royalties, of which Imperial’s share would be about 78,000 barrels. Imperial’s share of proven reserves developed by the first phase is 807 million barrels and was added to the company’s proposedproven mined bitumen reserves in 2008.

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.

     In March, the company, on behalf of the Mackenzie gas project co-venturers, filed updated cost and schedule information on the proposed project with the National Energy Board and Joint Review Panel. The updated project costs are $3.5 billion for the gas-gathering system, $7.8 billion for the Mackenzie Valley Pipeline and $4.9 billion for the development of the anchor fields. Current projectplan. Other activities are focused on regulatory work, finalizing remaining benefits and access agreements and establishing an appropriate fiscal framework with the federal government. All the scheduled public hearings by the Joint Review Panel and the National Energy Board were concluded in late 2007. The regulatory process continues with a Joint Review Panel report expected in 2008 followed by a National Energy Board decisionalso included access road construction, site preparation and earthworks. Significant progress has also been made in early 2009.
     Drilling of an exploration well with co-venturers in the Orphan Basin off the East Coast of Newfoundland was concluded in April. Exploration costs related to the well were reflected in 2007 earnings. Results from the well will be used to plan future drilling in the area.
     During the year, the company, along with co-venturer ExxonMobil Canada, successfullytransportation system agreements.

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.

British Columbia’s natural gas prone Horn River area. Exploration drilling and evaluation commenced in 2008.

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.

at Horn River.

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:

               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

 (a)(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.

network.

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.

in major urban markets.

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:

             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.

increasing feedstock flexibility.

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.

systems.

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


890.4 million shares – representing about 4851 percent of the total outstanding at the start of the program – with resulting distributions to shareholders of $12.8over $15 billion.

The company declared dividends totaling 3538 cents a share in 2007,2008, up from 3235 cents in 2006 (20052007 (20063132 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.

     During the year, the company retired the entire $818 million of long-term loans and the remaining $404 million of its medium-term notes.

Total debt outstanding at the end of 2007,2008, 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 (20061817 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

 (a)(1)Current and long-term portions of debt (page F-5)F-4) and the company’s share of equity company debt, divided by debt and shareholders’ equity (page F-5)F-4).
 (b)(2)Net income (page F-3), debt-related interest before capitalization (page F-19, note 14)13) and income taxes (page F-3), divided by debt-related interest before capitalization.
 (c)(3)Cash flow from net income adjusted for other non-cash items (page F-4)F-6), current income tax expense (page F-11, note 5)4) and debt-related interest before capitalization (page F-19, note 14)13) divided by debt-related interest before capitalization.

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
note
reference

    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

 (a)(1)Includes capitalizedCapital lease obligations. Long-term debt amounts excludeobligations primarily relate to the company’s share of equity company debt.capital lease for marine services.
 (b)(2)Minimum commitments for operating leases, shown on an undiscounted basis, primarily cover office buildings, rail cars and service stations.
 (c)(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.
 (d)(4)Firm capital commitments related to capital projects, shown on an undiscounted basis. The largest commitmentcommitments outstanding at year-end 2007 was $1262008 were $98 million associated with the company’s off-shoreshare of exploration projects.
 (e)(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 20082009 and estimated benefit payments for unfunded plans in all years.
 (f)(6)Asset retirement obligations represent the discounted presentfair value of legal obligations associated with site restoration on the retirement of assets with determinable useful lives.
 (g)(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.

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Unrecognized tax benefits totaling $170$150 million have not been included in the company’s commitments table because the company does not expect there will be any cash impact from the final settlements as sufficient funds have been deposited with the Canada Revenue Agency. Further details on the unrecognized tax benefits can be found in note 54 to the financial statements on page F-11.

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.

     In 2007, the

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.

Recently issued Statementsby paying additional royalties, the exact amount of Financial Accounting Standards
Fair Value Measurements
     In September 2006, the Financial Accounting Standards Board (FASB) issued FASB Statement No. 157 (SFAS 157), “Fair Value Measurements.” SFAS 157 defines fair value, establishes a framework for measuring fair value when an entity is requiredwhich will depend on production levels from 2010 to use a fair value measure for recognition or disclosure purposes and expands the disclosures about fair value measurements. SFAS 157 must be adopted by the company no later than January 1, 2008 for all financial assets and liabilities that are measured at fair value and non financial assets and liabilities that are remeasured at fair value at least annually. SFAS 157 must be adopted no later than2015. Also, beginning January 1, 2009, for non financial assetsSyncrude’s royalty will be based on bitumen value with upgrading costs and liabilities that are not remeasured at fair value at least annually.revenues excluded from the calculation. The company does not expectimpacts of the adoption of SFAS 157 toamended agreement have a material impact onbeen incorporated in the company’s financial statements.
2008 synthetic crude oil reserves calculation.

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.

Estimates of mined bitumen reserves are based on 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 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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Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals and significant changes in long-term oil and gas price levels.

The year-end 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.

company.

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.

807 million barrels of mined bitumen reserves were added in 2008, reflecting the company’s share of reserves being developed in the first phase of the Kearl oil sands project.

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

27


prices used for any impairment tests will vary from the one used in the SFAS 69 disclosure and could be lower or higher for any given year.

Pension benefits

The 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.

2008.

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

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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Item 7A. Quantitative and Qualitative Disclosures about Market Risk.Risks.

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)

(1)

   millions of dollars after tax
Nine

Three dollars (U.S.) a barrel change in crude oil prices

  +(-)  330150
Sixty

Seventy cents a thousand cubic feet change in natural gas prices

  +(-)  6

One centdollar (U.S) a litrebarrel change in sales margins for total petroleum products

  +(-)  182140

One cent (U.S.) a pound change in sales margins for polyethylene

  +(-)  67
Ten

Eight cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar

  +(-)  400300

 
(a)(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 2007.2008. Each sensitivity calculation shows the impact on net income that results from a change in one factor, after tax and royalties and holding all other factors constant. While these sensitivities are applicable under current conditions, they may not apply proportionately to larger fluctuations.

The sensitivity of net income to changes in crude oil prices 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.

     The sensitivityvalue of net income to changes in the Canadian dollar versus the U.S. dollar decreased from 2006 year-end by about $4 million (after-tax) for each one-cent difference. This was primarily due tohas increased the impact of the widening price spread between lightU.S. dollar denominated crude oil and Cold Lake heavy oil.
petroleum products prices on the company’s revenues and earnings.

Item 8. Financial Statements and Supplementary Data.
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

29


assessment uses a 6six percent and 7seven percent bitumen grade cut-off for the North mine and Aurora mine respectively, a 90 percent overall extraction recovery, a 97 percent mining dilution factor and an 88 percent upgrading yield.
     In 2007, Net proved reserves are based on the Alberta government proposed changescompany’s best estimate of average royalty rates over the life of the project and incorporate amendments to the generic oil sands royalty regime beginning in 2009. The Syncrude Joint Venture owners have a Crown Agreement with the Province of Alberta that codifies theAgreement. Actual future royalty rates through December 31, 2015. The Syncrude Joint Venture owners are in discussionsmay vary with the Alberta government to determine if an amended agreement can be negotiated that would transition Syncrude to the new generic royalty regime before 2016.
production, price and costs.

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     
   

30


               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  

Property, plant and equipment
         
  2007   2006
  (millions of dollars)
Property costs (3)        
Proved  3,167   3,226
Unproved  148   139
Producing assets  6,706   6,392
Support facilities  180   184
Incomplete construction  579   595
   
Total cost  10,780   10,536
Accumulated depreciation and depletion  7,505   7,326
   
Net property, plant and equipment  3,275   3,210
   
(1)Sales to customers or intersegment sales do not include the sale of natural gas and natural gas liquids purchased for resale, as well as royalty payments. These items are reported gross in note 3 (page F-10)F-9) in “external sales”, “intersegment sales” and in “purchases of crude oil and products”.
(2)(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)(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)Proved developed and undeveloped reserves reported on this table represent net reserves. Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 14.73 pounds per square inch at 60°F.
(2)(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 are frominclude reserves attributable to the commercial phases of Cold Lake production operations.

The information above describes changes during the years and balances of proved oil and gas reserves at year-end 2005, 2006, 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.

31


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. We understand that the use of December 31 prices and costs is intended to provide a point in time measure to calculate reserves and to enhance comparability between companies.
     The U.S. Securities and Exchange Commission regulations preclude However, the company from showing in the Financial section of this document, however, the reserves that are calculated in a manner which is consistent with the basis that the company uses to make its investment decisions. The use of year-end prices for reserves estimation introduces short-term price volatility into the process, 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.
company.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in year-end prices and costs that are used in the determination of reserves. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity. The quantities shown in the revisions category under heavy oil proved reserves in 2005 and 2006 were due mainly to changes in year-end prices and costs that were used in the determination of reserves.

     In 2007, the Alberta government proposed increases to the royalty rates on oil and gas production beginning in 2009. The magnitude of the potential impact on future royalty rates will depend on the final form of enacted legislation and the future prices of oil and gas and cannot be reasonably estimated at this time. As a result, this proposed increase in royalty rates cannot be and has not been reflected in the net proved crude oil and natural gas reserves at December 31, 2007.

Net proved reserves are determined by deducting the estimated future share of mineral owners or governments or both. For conventional crude oil (excluding enhanced oil-recovery projects) and natural gas, net proved reserves are based on estimated future royalty rates representative of those existing as of the date the estimate is made. Actual 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.

32


Net proved developed reserves of crude oil and natural gas as of December 31 (1)
                     
  2007 2006 2005 2004 2003
Crude Oil(millions)
                    
Conventional                    
Barrels  82   71   81   111   121 
Heavy Oil                    
Barrels  483   501   368   232   398 
Total                    
Barrels  565   572   449   343   519 
Natural Gas(billions)
                    
Cubic feet  539   608   643   704   859 
(1)

           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.

Syncrude and Kearl.

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 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Item 9.Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.
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.

     Reference is made to page F-2 of this report forreporting and the report of the independent registered public accounting firm on the company’s internal control over financial reporting as of December 31, 2007.
2008.

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.

PART III

Item 10. Directors and Executive Officers of the Registrant.

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.

Last major
position or office with the
Name and current principalcompany or Exxon Mobil
occupation or employmentCorporationDirector sinceHoldings (3)(4)(5)
R.L. (Randy) Broiles
Senior vice-president, resources division, Imperial Oil Limited
Global planning manager,
ExxonMobil Production
Company
July 21, 2005Common shares of Imperial Oil Limited
Deferred share units of Imperial Oil Limited
Restricted stock units of Imperial Oil Limited
Shares of Exxon Mobil Corporation (6)

7,500

0

0

66,229
Krystyna T. Hoeg
Retired president and chief executive officer of Corby Distilleries Limited
Not currently a member of the boardCommon shares of Imperial Oil Limited
Deferred share units of Imperial Oil Limited
Restricted stock units of Imperial Oil Limited
Shares of Exxon Mobil Corporation

0

0

0

0
Bruce H. March
President, Imperial Oil Limited
Director, refining
Europe/Africa/Middle East,
ExxonMobil Petroleum &
Chemicals, Brussels, Belgium
January 1, 2008Common shares of Imperial Oil Limited
Deferred share units of Imperial Oil Limited
Restricted stock units of Imperial Oil Limited
Shares of Exxon Mobil Corporation (6)

5,000

0

0

70,929
J.M. (Jack) Mintz
Palmer Chair in Public Policy for the University of Calgary (1)(2)
April 21, 2005Common shares of Imperial Oil Limited
Deferred share units of Imperial Oil Limited
Restricted stock units of Imperial Oil Limited
Shares of Exxon Mobil Corporation

1,000

1,684

8,000

0

Name and current
 principal occupation or 
employment
 

 Last major position or office 
with the company or Exxon
Mobil Corporation

 

  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 
with the company or Exxon
Mobil Corporation

 

  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

 

 
Last major
position or office with the
Name and current principalcompany or Exxon Mobil
occupation or employmentCorporationDirector sinceHoldings (3)(4)(5)
R. (Roger) Phillips
Retired president and chief executive officer, IPSCO Inc.
(steel manufacturing) (1)(2)
April 23, 2002Common shares of Imperial Oil Limited
Deferred share units of Imperial Oil Limited
Restricted stock units of Imperial Oil Limited
Shares of Exxon Mobil Corporation

9,000

14,887

12,125

2,000
P.A. (Paul) Smith
Senior vice-president,
finance and administration,
and treasurer
Imperial Oil Limited (2)
Controller and senior vice-president, finance and administrationFebruary 1, 2002Common shares of Imperial Oil Limited
Deferred share units of Imperial Oil Limited
Restricted stock units of Imperial Oil Limited
Shares of Exxon Mobil Corporation

13,337

0

190,250

1,662
S.D. (Sheelagh) Whittaker
Retired managing director, Electronic Data Systems Limited (business and information technology services)
(1)(2)
April 19, 1996Common shares of Imperial Oil Limited
Deferred share units of Imperial Oil Limited
Restricted stock units of Imperial Oil Limited
Shares of Exxon Mobil Corporation

9,000

30,452

12,125

0
V.L. (Victor) Young
Corporate director of several corporations (1)(2)
April 23, 2002Common shares of Imperial Oil Limited
Deferred share units of Imperial Oil Limited
Restricted stock units of Imperial Oil Limited
Shares of Exxon Mobil Corporation

10,250

5,320

12,125

0
(1)Member of audit committee; member of executive resources committee; member of environment, health and safety committee; member of executive resources committee; and member of nominations and corporate governance committee.
(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 directorsdirectors.
(3)(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.
(4)(5)The company’s plans for deferred sharerestricted stock units and restricted stockdeferred share units for selected employees and nonemployee directors are described on page 43pages 40 through 42 and page 4450 through 51, respectively.
(5)(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 20072008 after the three-for-one share split in May 2006, plus three times the number of restricted stock units and deferred share units granted before the share split and still held by the director. The numbers for Exxon Mobil Corporation restricted stock include restricted stock and restricted stock units granted under its restricted stock plan which is similar to the company’s restricted stock unit plan.
(6) R.L. Broiles(7)B.H. March holds 17,72927,185 common shares and 48,50044,750 restricted shares and restricted stock units of Exxon Mobil Corporation. B.H. MarchR.C. Olsen holds 20,679105,854 common shares and 50,250161,700 restricted shares and restricted stock units of Exxon Mobil Corporation.

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.


Certain of the directors and nominees for election as directors hold positions as directors of other Canadian and U.S. reporting issuers as follows: Timothy J. Hearn - Royal Bank of Canada; Krystyna T. Hoeg - Sun Life Financial Inc., Shoppers Drug Mart Corporation, Canadian Pacific Railway Limited and Cineplex Galaxy Income Fund; Jack M. Mintz - Brookfield Asset Management Inc. and CHC Helicopter Corporation; Roger Phillips - Canadian Pacific Railway Company, Canadian Pacific Railway Limited, Cleveland-Cliffs Inc. and The Toronto-Dominion Bank; James F. Shepard - Canfor Corporation; and Victor L. Young - Bell Aliant Regional Communications Income Fund, BCE Inc. and Royal Bank of Canada.

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.

     The

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.

13, 2009.

Name and officeOffice held since    Age           
   Name and Office      Office held since
Timothy J. Hearn
chairman of the board
and chief executive officer
January 1, 2008
Bruce H. March
president
January 1, 2008
Paul A. Smith
senior vice-president,
finance and administration,
and treasurer

Sean R. Carleton

Controller

  February 1, 2008
    
Randy L. Broiles
senior vice-president, resources division50    
  July 1, 2005

Phil Dranse

Assistant treasurer

  August 1, 200855    

Marvin E. Lamb

Director, corporate tax

December 1, 200153    

Brian W. Livingston
vice-president,

Vice-president, general counsel and corporate secretary

  August 1, 200454    

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

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.

Young.

Audit committee financial expert

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

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


Item 11. Company Executives and Executive Compensation.
Composition

Named Executive Officers of the company’s compensation committee

Company

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. Whittaker
J.M. Mintz

     T.J. Hearn

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 - ChairJ.M. Mintz
V.L. Young - Vice-chairR.C. Olsen
K.T. HoegS.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.

     In establishing The decision-making process with respect to compensation forrequires judgment, taking into account business and individual performance and responsibility. Quantitative targets or formulas are not used to assess individual performance or determine the amount of compensation.

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.

leadership in the industry and serves the interests of shareholders in the long term. The company service of the named executive officers reflects this strategy. Their career service ranges from 27 to over 29 years.

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.

Cash Salary decisions also directly affect the level of retirement benefits since salary is included in the retirement-benefit calculation. Thus, the level of retirement benefits is also performance-based like other elements of compensation.

Annual Bonus

     Cash

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;

     In 2007,

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

Medium/Long-Term Incentive Compensation

50 percent earnings bonus units with a delayed payout based on cumulative earnings performance.

     A medium-term

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


improvement in the company’s business performance and shareholder value. Earnings bonus units are generally equal to and granted in tandem with cash bonusesbonuses.

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.

company before age 65, or engages in activity that is detrimental to the company.

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.

Grant level guidelines for the restricted stock unit program are generally held constant for long periods of time. The intent of the plan is not to frequently change the number of shares awarded for the same level of individual performance and classification or level of responsibility. The program is a share-denominated program, not a price-denominated program, to better align with the gains and losses experienced by shareholders. A change may be required as a result of periodic checks against the market every three to five years or as a result of any subdivision, consolidation, or reclassification of the shares of the company or other relevant change in the capitalization of the company. The company does not offset losses on prior grants with higher share awards in subsequent grants nor does the company re-price restricted stock units.

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.

In 2008, after an analysis of the competitive positioning of the company’s restricted stock unit program, the executive resources committee determined that some levels of restricted stock units would be increased to ensure appropriate on-going competitive positioning of the plan. In 2008, 748 employees were granted 1,750,795 restricted stock units, including 100 executives.

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.

     In 2007, 800 employees were The restricted stock unit plan has been amended for units granted in 2002 and future years by providing that the recipient may receive one common share of the company per unit or elect to receive the cash payment for the units to be exercised on the seventh anniversary of the grant date.

There are 7,928,818 common shares that may be issued in the future with respect to outstanding restricted stock units including 95 executives.

CEO compensation
     T.J. Hearn’s salary is currently assessed to be within the rangethat represent about 0.93 percent of the competitive target for the company’s chairman, presidentcurrently outstanding common shares. The company’s directors, officers and chief executive officer, namely, between the median and upper quartilevice-presidents as a group hold 15 percent of the competitive market. The target is consistent with the executive resources committee’s view that the chairman, president and chief executive officer’s salary should be above the average of salaries for chief executive officers of major Canadian companies, reflecting the company’s executive development philosophy and the significance placed on experience and judgment in leading a large, complex organization.
     In the case of T.J. Hearn, the committee’s approach to cash bonuses is based on the company’s financial and operating performance and on the committee’s assessment of T.J. Hearn’s effectiveness in leading the organization. The continuing progress being made in focusing the organization on advancing key strategic interests, safety, environmental performance, productivity, cost effectiveness and asset management were primary considerations in determining a cash bonus for the chairman, president and chief executive officer. T.J. Hearn’s 2007 cash bonus remained the same as his 2006 cash bonus, again to reflect his effectiveness in the position, the company’s record financial performance and comparisons to other leading Canadian employers.
     With respect to the company’s medium term incentive program, the committee similarly awarded Mr. Hearn the same earnings bonus unit award that he received in 2006 for the same reasons noted above for Mr. Hearn’s cash bonus award.
Directors’ compensation
     Directors’ fees are paid only to nonemployee directors. For 2007, nonemployee directors were paid an annual retainer of $35,000 and 2,000unexercised restricted stock units for their services as directors, plus an annual retainerthat give the recipient the right to receive common shares. The maximum number of $4,500 for each committee on which they served, an additional $5,000 for serving as chaircommon shares that any one person may receive from the exercise of a committee and $2,000 for each board and board committee meeting attended. The restricted stock units issued to nonemployee directors haveis 488,200 common shares, which is about 0.06 percent of the same features as thecurrently outstanding common shares. R.L. Broiles and C.W. Erickson hold ExxonMobil restricted stock units for selected key employees described on page 44.
     Starting in 1999, the nonemployee directors have been able to receive all or part of their directors’ fees in the form of deferred share units for nonemployee directors. The purpose of the deferred share unit plan for nonemployee directors is to provide them with additional motivation to promote sustained improvement in the 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. This plan is described on page 43.
     While serving as directors in 2007, the aggregate cash remuneration paid to nonemployee directors, as a group, was $384,875, and they received an additional 5,456 deferred share units, based on an aggregate of $265,625 of cash remuneration elected to be received as deferred share units. The nonemployee directors, as a group, received an additional 514 deferred share units granted as the equivalent to the cash dividend paid on company shares during 2007 for previously granted deferred share units. In addition, the nonemployee directors received 10,000B.H. March also holds ExxonMobil restricted stock units.

39


Senior executive compensation
Summary Compensation Table
     The following table shows the compensation for the chairman, president and chief executive officer; the controller and senior vice-president, finance and administration and the three other most highly compensated senior executives of the company who were serving as senior executives at the end of 2007. This information includes the dollar value of base salaries, cash bonus awards and units of other long-term incentive compensation and certain other compensation.
                                                     
 
         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


(1)R.L. Broiles has been on a loan assignment from Exxon Mobil Corporation since July 1, 2005. His compensation was paid to him directly by ExxonMobil Corporation in United States dollars, and is disclosed in United States dollars. Also, he received employee benefits under Exxon Mobil 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 him.
(2)Any part of bonus elected to be received as deferred share units is excluded.
(3)Amounts under “Other Annual Compensation”, except for R.L. Broiles, consist of dividend equivalent payments on restricted stock units, interest paid in respect of deferred payments of bonuses and earnings bonus units and any costs associated with the personal use of the company aircraft. There is no tax assistance from the company for taxes related to personal use of the company aircraft. In 2007, the dividend equivalent payments were $228,476 for T.J. Hearn, $64,476 for P.A. Smith, $38,285 for B.W. Livingston and $42,986 for J.F. Kyle. In 2007, the interest paid in respect of deferred payments of bonuses and earnings bonus units was $335,446 for T.J. Hearn, $6,010 for P.A. Smith, $21,989 for B.W. Livingston and $30,420 for J.F. Kyle. Also included is an earned benefits allowance. The earned benefits allowance in 2007 was $70,000 for T.J. Hearn, $45,000 for P.A. Smith, $15,000 for B.W. Livingston and $30,000 for J.F. Kyle. For R.L. Broiles, the U.S. dollar amounts are the net payments by Exxon Mobil Corporation on account of Canadian income taxes and other compensation for assignment outside of the United States. Each year while on assignment, R.L. Broiles paid to Exxon Mobil Corporation amounts that were approximate to the income taxes that would have been imposed if he was resident in his originating country of employment. For R.L. Broiles, the amount includes dividend equivalent payments on restricted stock from Exxon Mobil Corporation.
(4)The company has not granted stock options since 2002. The stock option plan is described on page 44.
(5)These values include the number of units granted under the company’s restricted stock unit plan and deferred share unit plan for selected executives described on pages 44 and 43 respectively. The number of restricted stock units and deferred share units for 2006 and 2007 are the number of units actually received. The numbers shown for restricted stock units and deferred share units for 2005 represent three times the number of restricted stock units and deferred share units received in those years before the three-for-one share split in May 2006. The values of the restricted stock units shown are the number of units multiplied by the closing price of the company’s shares on the date of grant. The closing price on the date of grant of the restricted stock units was $38.47 in 2005, $43.26 for 2006 and $49.73 for 2007 (all on a post-split basis). T.J. Hearn is the only senior executive who holds deferred share units and he received additional deferred shares from dividends on his existing deferred shares. The values of the deferred share units shown are the number of such additional deferred share units multiplied by the year-end closing price. R.L. Broiles participates in Exxon Mobil 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. Under that plan, R.L. Broiles was granted 11,000 restricted shares in 2007, whose value on the date of grant (November 28, 2007) was $967,120 U.S., based on a closing price of Exxon Mobil Corporation shares on the date of grant of $87.92 U.S.
(6)The table below shows the number and value of restricted stock units and deferred share units held as of December 31, 2007. The numbers for restricted stock units and deferred share units represent the total of the restricted stock units and deferred share units received in 2006 and 2007 after the three-for-one share split in May 2006, plus three times the number of restricted stock units and deferred share units received before the share split and still held by the employee. The closing price on December 31, 2007 was $54.62. R.L. Broiles participates in Exxon Mobil Corporation’s restricted stock plan, which is similar to the company’s restricted stock unit plan. Under that plan, R.L. Broiles holds 48,500 restricted shares whose value on December 31, 2007 was $4,543,965 U.S. based on a closing price for Exxon Mobil Corporation shares on December 31, 2007 of $93.69 U.S.
               
    Restricted Stock Units  Deferred Share Units 
 Name  Total (#)  Total ($)  Total (#)  Total ($) 
               
 T.J. Hearn  714,800  39,042,376  306  16,714 
 P.A. Smith  190,250  10,391,455  0  0 
 R.L. Broiles         
 B.W. Livingston  119,750  6,540,745  0  0 
 J.F. Kyle  126,500  6,909,430  0  0 
               
(7)Payouts were from 2006 earnings bonus units that reached maximum value of $1.75 per unit in 2007. That plan is described on page 44. R.L. Broiles participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the company’s earnings bonus unit plan.
(8)Amounts under “All Other Compensation”, except for R.L. Broiles, are the company’s contributions to the savings plan, which is a plan available to all employees. Under one of the options of that plan to which the senior executives subscribe, except for R.L. Broiles, the company matched employee contributions up to six percent of base salary per year; however, an employee may elect to receive an enhanced pension under the company’s pension plan by foregoing three percent of the company’s matching contributions. The plan is intended to be primarily for retirement savings, although employees may withdraw their contributions prior to retirement. For R.L. Broiles, the amount is Exxon Mobil Corporation’s contributions to its employee savings plan.
(9)“Total Compensation” for each of 2005, 2006 and 2007 consists of the total dollar value of Salary, Bonus, Other Annual Compensation, Shares or Units Subject to Resale Restrictions, LTIP Payouts and All Other Compensation for each such year.

41


Earnings Bonus Unit Plan – awards in most recently completed financial year
     The following table provides information on earnings bonus units granted in 2007 toand previous years, as well as the named senior executives. The earnings bonuscompany’s restricted stock units granted in 2008.

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 
 
(1)Payment will be made earlier when the cumulative net earnings per outstanding common share reach the maximum settlement value per unit prior to the fifth anniversary of the grant date.
(2)This is the maximum settlement value payable per earnings bonus unit granted in 2007.
(3)R.L. Broiles participates in Exxon Mobil Corporation’s earnings bonus unit plan which is similar to the company’s earnings bonus unit plan. In 2007, R.L Broiles was granted 31,800 units under that plan for which the maximum settlement value payable per earnings bonus unit is $5.00 U.S.
Aggregated option/SAR exercises during the most recently completed financial year and financial year end option/SAR values
     The following table provides information on the exercise in 2007 and the aggregate holdings at the end of 2007 of incentive share units (referred to in the table as “SARs”)was also amended by the named senior executives. The incentive share unit plan is described in more detail on page 43. The number of incentive share units in the table below is equalcompany to three timesprovide that the number of incentive share units held before the three-for-one share split in May 2006.
                     
 
               
    Securities  Aggregate  Unexercised  Value of 
    Acquired  Value  Options/SARs  Unexercised 
 Name  on Exercise  Realized  at Financial  in-the-Money 
    (#)  ($)  Year End  Options/SARs 
          (#)  at Financial 
                Year End 
                ($) 
          Exercisable  Unexercisable  Exercisable  Unexercisable 
             (1)     (1) 
 T.J. Hearn    2,711,250  0  0  0  0 
 P.A. Smith    596,100  120,000  0  5,115,900  0 
 R.L. Broiles             
 B.W. Livingston    0  0  0  0  0 
 J.F. Kyle    0  0  0  0  0 
 
(1)Unexercisable units are units for which the conditions for exercise have not been met.

42


     The following table provides information on the exercise in 2007 and the aggregate holdings at the end of 2007 of stock options by the named senior executives. The stock option plan is described in more detail on page 44.
                     
 
               
    Securities  Aggregate  Unexercised  Value of 
    Acquired  Value  Options/SARs  Unexercised 
 Name  on Exercise  Realized  at Financial  in-the-Money 
    (#) (1)  ($)  Year End  Options/SARs 
          (#) (1)  at Financial 
                Year End
($)
 
          Exercisable  Unexercisable  Exercisable  Unexercisable 
             (2)     (2) 
 T.J. Hearn  10,002  296,272  154,998  0  6,063,522  0 
 P.A. Smith      75,000  0  2,934,000  0 
 R.L. Broiles (3)             
 B.W. Livingston  15,000  512,255  30,000  0  1,173,600  0 
 J.F. Kyle  57,000  1,790,530  0  0  0  0 
 
(1)The number for the stock options represents three times the number of stock options granted in 2002 before the three-for-one share split in May 2006 and still held by the employee.
(2)Unexercisable units are units for which the conditions for exercise have not been met.
(3)At the end of 2007, R. L. Broiles held options to acquire 56,398 Exxon Mobil Corporationcommon shares of which all options were exercisable. The value of R.L. Broiles’ exercisable options was $ 2,976,628 U.S. at the end of 2007. In 2007, R.L. Broiles exercised 55,598 options and realized an aggregate value of $ 2,463,063 U.S..
Details of long-term and medium-term incentive compensation
     Consistent with the company’s compensation philosophy of being performance driven, long-term incentive compensation is granted to retain selected employees and reward them for high performance. The assessment of employee performance is conducted through the company’s appraisal program. The appraisal program is a disciplined annual program that assesses business performance measures relevant to eligible employees and involves ranking of employee performance using a consistent process throughout the organization at all levels. The number of units received by each employee is tied to the performance of the employee in achieving these business performance measures. The scope of the company program is determinedissuable under the plan to any insiders (as defined by the overall performanceToronto Stock Exchange) cannot exceed 10 percent of the issued and outstanding common shares, whether at any time or as issued in any one year. The Toronto Stock Exchange advised that this amendment did not require shareholder approval.

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.

     The company’s incentive share units give the recipient a rightper unit or elect to receive the cash equalpayment for all units to be exercised. The choice of which vesting period to use will be at the amount by which the market pricediscretion of the company’s common shares atcompany. Effective May 1, 2008, the time ofrestricted stock unit plan was further amended to set out which amendments in the future will require shareholder approval, and which amendments will only require director approval and to set an exercise exceedsprice based on the issue price of the units. These units were granted prior to 2002. The issue price of the units granted to executives was the closingweighted average price of the company’s shares on the Toronto Stock Exchangeexercise date and the four consecutive trading days immediately prior to the exercise date. Shareholder approval for these changes was received on May 1, 2008.

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
obligation
at start of
year

($) (5)

  

Compensatory
change

($) (6)

  

Non-compensatory
change

($) (7)

  

Accrued
obligation
at year end

($) (8)

    

At year

end (3)

 

  

At age
65 (4)

 

        

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
March
 31, 2008)

  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 CorporationProcter & Gamble Inc.
BCE Inc.General Electric CanadaRoyal Bank of Canada
BP Canada Energy CompanyHusky Energy Inc.Shell Canada Limited
Canadian Tire Corporation LimitedIBM Canada Ltd.Suncor Energy Inc.
Chevron Canada LimitedIrving Oil LimitedTalisman Energy Inc.
Canadian Natural Resources LimitedLafarge Canada Inc.TransCanada Corporation
ConocoPhillips CanadaNexen Inc.Vale Inco Limited
Canadian Pacific Railway LimitedNova 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.

     Starting

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
Compensation

($)

 

Pension
Value

($) (6)

 All Other
Compensation
($) (7)
 Total
Compensation
($) (8)
           

Annual
Incentive
Plans

(4)

 

Long-term
Incentive
Plans

(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
securities
underlying
unexercised
options

(#) (4)

     

 

Option
exercise
price

($)

     

 

Option
Expiration Date

     

 

Value of
unexercised
in-the-money
options

($)

     

 

Number of
shares or
units of
shares
that have
not vested

(#) (5)

     

 

Market or payout
value of share-
based awards
that have not
vested

($) (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 –
Value vested during the
year

($)

    

 

Share-based awards –
Value vested during
the year

($) (4)

    

 

Non-equity incentive plan
compensation – Value earned
during the year

($) (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

grant expires in 2011.


Stock Option Plan

     Starting in 2001, a medium-term incentive compensation plan was introduced, called the earnings bonus unit plan. This plan was made available to selected executives to promote individual contribution to sustained improvement in the company’s business performance and shareholder value. Each earnings bonus unit entitles the recipient to receive an amount equal to the company’s cumulative net earnings per common share as announced each quarter beginning after the grant. Payout occurs on the fifth anniversary of the grant or when the maximum settlement value per unit is reached, if earlier. If after five years the maximum settlement has not been reached, payout will be prorated.
Under the stock option plan adopted by the company in April 2002, a total of 9,630,600 options, on a post share split basis, were granted to selectselected key employees on April 30, 2002 for the purchase of the company’s common shares at an exercise price of $15.50 per share on a post share split basis. All of the options are exercisable. Any unexercised options expire afteron April 29, 2012. As of February 14, 2008,13, 2009, there have been 5,028,6455,336,415 common shares issued upon exercise of stock options and 4,601,9554,294,185 common shares are issuable upon future exercise of stock options. The common shares that were issued and those that may be issued in the future represent about 1.1 percent of the company’s currently outstanding common shares. The company’s directors, officers and vice-presidents as a group hold 6.8eight percent of the unexercised stock options.

The maximum number of common shares that any one person may receive from the exercise of stock options is 154,998150,000 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;

     In December 2002,

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.

     There are 7,074,314 common shares issuable upon future exercise of restricted stock units, which represent about 0.79 percentgrant of the company’s currently outstanding common shares. The company’s directors, officers and vice-presidents have available, as a group, 16 percent of the common shares issuable under outstanding restricted stock units. The maximum number of common shares that any one person may receivevesting periods are not accelerated upon separation or retirement from the exercise of outstanding restricted stock units is 488,200 common shares, which is about 0.05 percent of the currently outstanding common shares.
     Restricted stock units will be exercised only during employmentboard, except in the event of death, disability or retirement. Also,death. The restricted stock unit plan is described in more detail on pages 40 through 41. In 2008, each nonemployee director received an annual grant of 2,000 restricted stock units.

Components of Directors’ Compensation

Director 

Annual

Retainer for
Board
Membership

($)

 

Annual

Retainer for
Committee
Membership

($)

 

Annual

Retainer
for
Committee
Chair

($)

 

Restricted
Stock
Units

(RSU)

(#)

 Fee for Board and
Committee Meetings Not
Regularly Scheduled
 

Total
Cash

($) (1)

 

Total
Deferred
Share
Units

(DSU)

($) (2)

 

Total
Restricted
Stock
Units

($) (3)

 

Total
Compensation

($)

               

Number of
non-regularly
scheduled
meetings
attended

(#)

 

Fee

($2,000 x
number
of
meetings
attended)

($)

            

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

44

benchmark sample are as follows:


provide that on retirement the company shall determine whether the employee’s restricted stock units will not be forfeited. Effective August 2, 2006, the restricted stock unit plan was amended by the company to change the exercise price under the plan from a single day’s closing price to a five-day average and to change exercise dates under the plan from December 31 to December 4 with respect to restricted stock units granted in prior years. Shareholder approval for these changes was not required by the Toronto Stock Exchange.
Payments to Employees Who Retire
Pension Plan Table
                                 
 
 Remuneration for    
 determining      Estimated undiscounted payments on retirement 
 payments  at the age of 65 after years of service indicated below ($) (1) 
 on retirement    
                     
 ($)  20 Years  25 Years  30 Years  35 Years  40 Years  45 Years 
                     
 100,000   32,000    40,000    48,000    56,000    64,000    72,000  
 200,000   64,000    80,000    96,000    112,000    128,000    144,000  
 300,000   96,000    120,000    144,000    168,000    192,000    216,000  
 400,000   128,000    160,000    192,000    224,000    256,000    288,000  
 500,000   160,000    200,000    240,000    280,000    320,000    360,000  
 600,000   192,000    240,000    288,000    336,000    384,000    432,000  
 800,000   256,000    320,000    384,000    448,000    512,000    576,000  
 1,000,000   320,000    400,000    480,000    560,000    640,000    720,000  
 1,500,000   480,000    600,000    720,000    840,000    960,000    1,080,000  
 2,000,000   640,000    800,000    960,000    1,120,000    1,280,000    1,440,000  
 2,500,000   800,000    1,000,000    1,200,000    1,400,000    1,600,000    1,800,000  
 3,000,000   960,000    1,200,000    1,440,000    1,680,000    1,920,000    2,160,000  
 3,500,000   1,120,000    1,400,000    1,680,000    1,960,000    2,240,000    2,520,000  
 4,000,000   1,280,000    1,600,000    1,920,000    2,240,000    2,560,000    2,880,000  
 
(1)Comparator Companies – Non-Employee Directors

Alcan Inc.

 Payment calculations exclude the effectEnCana CorporationBank of integration with CPP/QPP and OAS.Nova Scotia

Bank of Montreal

George Weston LimitedSun Life Financial Inc.

BCE Inc.

Manulife Financial CorporationSuncor Energy Inc.

Bombardier Inc.

Nortel Networks CorporationTELUS Corporation

Canadian Imperial Bank of Commerce

Petro-CanadaThomson Reuters Corporation

Canadian National Railway Company

Power Financial CorporationThe Toronto Dominion Bank

Canadian Pacific Railway Limited

Royal Bank of CanadaTransCanada 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.

     The remuneration used to determine the payments on retirement to the individuals named in the summary compensation table on page 40 corresponds generally to the salary, bonus compensation and bonus compensation amount elected to be received as deferred share units in that table. The aggregate maximum settlement value that could be paid for earnings bonus units granted shown in the table on page 42 is also included in the employee’s “final three year average earnings” for the year of grant of such units. As of February 14, 2008, the number of completed years of service with Imperial Oil Limited used to determine payments on retirement was 41 for T.J. Hearn, 27 for P.A. Smith and 23 for B.W. Livingston. J.F. Kyle retired from the company on January 31, 2008 with 31 completed years of service.
     R.L. Broiles is not a member of the company’s pension plan, but is a member of Exxon Mobil Corporation’s pension plan. Under that plan, R.L. Broiles has 28 years of service and he will receive a pension payable in U.S. dollars. The remuneration used to determine the payment on retirement to him also corresponds generally to his salary extended on a full year basis and bonus compensation in the summary compensation table on page 40, which total may be applied to the pension plan table above but with the dollars in that table representing U.S. rather than Canadian dollars.

45

company.


 

Name

(1)

  

 

Fees

Earned
($) (3)

     

 

Share-
based
awards

($) (4)

     

 

Option-
based
awards

($)

     

 

Non-equity
incentive plan
compensation

($)

     

 

Pension
value

(#)

     

 

All other
compensation

($)

     

 

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  

Executive Pension Value Disclosure(1)(2)
                     
 
       Accrued  Annual Pension          
    Current 2007  Obligations at  Benefit Payable at  Age     Normal 
    Service Cost  Dec. 31, 2007  age 65  (at Dec. 31,  Credited  Retirement 
 Name  ($)(3)  (4)  (5)  2007)  Service  Age 
 T.J. Hearn  515,200  24,482,600  2,144,400  63  41  65 
 P.A. Smith  133,600  3,624,900  474,000  54  27  65 
 R.L. Broiles        50  28  65 
 B.W. Livingston  122,000  2,522,900  382,800  53  23  65 
 J.F. Kyle  90,100  3,535,400  298,800  64  31  65 
 
(1)Pension benefits reflected in these tables do not vest untilAs directors employed by the named executive officer reaches age 55. In the case ofcompany or Exxon Mobil Corporation, T.J. Hearn, B.H. March, R.L. Broiles, P.A. Smith and J.F. Kyle, their accrued pension to date is already vested.R.C. Olsen did not receive compensation for acting as directors.
 
(2)Amounts shown include pension benefits under Imperial Oil Limited’s registered pension plan and supplemental retirement plans, other than for R.L. Broiles, who participatesStarting in Exxon Mobil Corporation’s pension plan and supplemental pension plan. Under Exxon Mobil Corporation’s pension plan and supplemental pension plan, R.L. Broiles’ current 2007 service cost was $237,418 U.S.,1999, the accrued obligations at December 31, 2007 with respectnonemployee directors have been able to R.L. Broiles was $1,469,568 U.S. and his annual pension benefit payable at age 65 will be $450,425 U.S.receive all or part of their directors’ fees in the form of deferred share units.
 
(3)Represents all fees awarded, earned, paid or payable in cash for services as a director, including retainer fees, committee, chair and meeting fees.
 Service cost is(4)The values of the actuarialrestricted stock units and the deferred share units shown are the number of units multiplied by the closing price of the company’s shares on the date of grant. The dollar value of benefits earned under the pension benefit formula for the calendar year 2007. Amountsdeferred share units shown are consistent with disclosure in Note 6 of the 2007 Consolidated Financial Statements.
(4)Accrued obligation is the value of the projected benefit obligationportion of the annual retainer for pension earnedboard membership, annual retainer for servicecommittee membership, and annual retainer for committee chair, which the director elected to receive as deferred share units as noted on pages 50 and 51.

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
in-the-

money
options

($)

     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, 2007. The accrued obligation increases with age and2008.
(3)Value is significantly impacted by changes inbased on the discount rate. Amounts shown are consistent with disclosure in Note 6closing price of the 2007 Consolidated Financial Statements.company’s shares on December 31, 2008.

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.

(5)

Name

(1)

 Amounts

Option-based awards –

Value vested during the
year

($)

Share-based awards –
Value vested during
the year

($)

Non-equity incentive plan
compensation – Value
earned during the year

($)

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 this column are based2005 and vesting in 2008.
(3)For J.F. Shepard, the value includes deferred share units that vested as of his retirement date from the board on current compensation levelsMay 1, 2008.

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
acquired
since last
report

(February
15, 2008 to
February 13,
2009)

    

 

Total Holdings
(includes
common
shares,
deferred share
units and
restricted stock
units)

    

 

Minimum
Requirement

    

 

Minimum
Requirement
Achieved

    

 

Date Required to
Achieve Minimum
Requirement

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 assume accruedchief executive officer shall, within three years of service to age 65 for eachhis appointment as chairman and chief executive officer, acquire shares of the named executive officers.company, including common shares, deferred share units and restricted stock units, of a value of no less than five times his base salary. B.H. March has not yet achieved this requirement.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
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.

46

13, 2009.


Equity Compensation Plan Information

The following table provides information on the common shares of the company that may be issued as of the end of 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
outstanding options,
warrants and rights

(3)

    

Weighted-average  

exercise price of
outstanding
options warrants,
and rights

($) (4)

    

Number of securities

remaining available for future  

issuance under equity
compensation plans
(excluding securities reflected
in the first column)

(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 page 44.
pages 49 through 50.
 
(2)This is a restricted stock unit plan, which is described on page 44.pages 40 through 41.
 
(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 20072008 after the three-for-one share split in May 2006, plus three times the number of securities reserved for restricted stock units issued before the share split and still outstanding.
(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.

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.

     During 2003, the company borrowed $818 million from an affiliated company of Exxon Mobil Corporation under two long term loan agreements at interest equivalent to Canadian market rates. Interest on the loans in 2007 was $33 million. The average effective interest rate for the loans was 4.52 percent for 2007. These loans were repaid in 2007.

The amounts of purchases and sales by the company and its subsidiaries for other transactions in 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


R.C. Olsen is a non-independent member of the executive resources committee, environmental, health and safety committee and nominations and corporate governance committee. As an employee of ExxonMobil Production Company, R.C. Olsen is independent of the company’s management and is able to assist these committees by reflecting the perspective of the company’s shareholders.

Item 14. Principal Accountant Fees and Services.
Item 14.Principal Accountant Fees and Services.

Auditor Fees

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.

2008. Audit-related fees include other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities.
Tax fees are mainly tax services for employees on foreign loan assignments.
2008 was the final year of PwC providing tax services for the company’s employees on foreign loan assignment. The company did not engage the auditor for any other services.

The audit committee recommends the external auditor to be appointed by the shareholders, fixes its remuneration and oversees its work. The audit committee also approves the proposed current year audit program of the external auditor, assesses the results of the program after the end of the program period and approves in advance any non-audit services to be performed by the external auditor after considering the effect of such services on their independence.

All of the services rendered by the auditor to the company were approved by the audit committee.

48


PART IV

Item 15. Exhibits and Financial Statement Schedules.
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)).

(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)).

49

(14)


(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)).
(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. 0-121014)0-12014)).
(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

SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf on February 26, 200824, 2009 by the undersigned, thereunto duly authorized.

Imperial Oil LimitedIMPERIAL OIL LIMITED
By /s/ T.J. HearnBruce H. March
 (Timothy J. Hearn,Bruce H. March, Chairman of the Board,
President and Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 26, 200824, 2009 by the following persons on behalf of the registrant and in the capacities indicated.

Signature  Title
Signature

/s/ Bruce H. March

(Bruce H. March)

  Title

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

INDEX TO FINANCIAL STATEMENTS

   
Chairman of the Board and
/s/ T.J. HearnChief Executive Officer and Director
(Timothy J. Hearn)
 (Principal Executive Officer)
Senior Vice-President,
/s/ Paul A. SmithFinance and Administration, and Treasurer
(Paul A. Smith)
 and Director
(Principal Accounting Officer and
Principal Financial Officer)
/s/ R.L. BroilesDirector
(Randy L. Broiles)
/s/ B.H. MarchDirector
(Bruce H. March)
/s/ J.M. MintzDirector
(Jack M. Mintz)
/s/ Roger PhillipsDirector
(Roger Phillips)
/s/ J.F. ShepardDirector
(James F. Shepard)
/s/ Sheelagh D. WhittakerDirector
(Sheelagh D. Whittaker)
/s/ V.L. YoungDirector
(Victor L. Young)

52



MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

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.

2008.

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/ T.J. HearnBruce H. March  /s/ Paul A. Smith
T.J. Hearn
Bruce H. March
  
P.A.Paul A. Smith
Chairman, president and chief executive officer  Senior vice-president, finance and administration, and treasurer
(Principal (Principal accounting officer and principal financial officer)

AUDITORS’ REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

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 26, 2008

24, 2009

F-2


Consolidated statement of income
             
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 
 
(U.S. GAAP)

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, (20062006 - $1,274 million, 2005 - $1,278 million)).
(b)Operating revenues in 2005 included $4,894 million for purchases/sales contracts with the same counterparty. Associated costs were included in purchases of crude oil and products. Effective January 1, 2006, these purchases/sales were recorded on a net basis with no resulting impact on net income, (note 1).
(c)Operating revenues include amounts from related parties of $2,150 million (2007 - $1,772 million, (20062006 - $1,955 million, 2005 - $1,346 million), (note 16)15).
(d)(c)Purchases of crude oil and products include amounts from related parties of $4,729 million (2007 - $3,331 million, (20062006 - $3,937 million, 2005 - $3,887 million), (note 16)15).
(e)(d)Production and manufacturing expenses include amounts to related parties of $161 million (2007 - $194 million, (20062006 - $156 million, 2005 - $102 million), (note 16).
(f)Financing costs include amounts to related parties of $32 million (2006 - $33 million, 2005 - $22 million), (note 16)15).

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 andSenior vice-president,
chief executive officerfinance and administration, and treasurer

Consolidated statement of shareholders’ equity(U.S. GAAP)

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.

Consolidated statement of cash flows

             
millions of Canadian dollars         
Inflow/(outflow)         
For the years ended December 31 2007  2006  2005 
 
Operating activities
            
Net income  3,188   3,044   2,600 
Adjustments for non-cash items:            
Depreciation and depletion  780   831   895 
(Gain)/loss on asset sales, after tax  (156)  (96)  (233)
Deferred income taxes and other  16   254   (116)
Changes in operating assets and liabilities:            
Accounts receivable  (261)  203   (414)
Inventories and prepaids  13   (97)  (67)
Income taxes payable  (77)  (225)  304 
Accounts payable  250   (86)  644 
All other items - net(a)
  (127)  (241)  (162)
 
Cash from operating activities
  3,626   3,587   3,451 
 
             
Investing activities
            
Additions to property, plant and equipment and intangibles  (899)  (1,177)  (1,432)
Proceeds from asset sales  279   212   440 
 
Cash from (used in) investing activities
  (620)  (965)  (992)
 
             
Financing activities
            
Short-term debt - net  (65)  72   18 
Repayment of long-term debt  (1,726)  (74)  (21)
Long-term debt issued  500       
Issuance of common shares under stock option plan  12   10   38 
Common shares purchased(note 12)
  (2,358)  (1,818)  (1,795)
Dividends paid  (319)  (315)  (317)
 
Cash from (used in) financing activities
  (3,956)  (2,125)  (2,077)
 
             
Increase (decrease) in cash
  (950)  497   382 
Cash at beginning of year
  2,158   1,661   1,279 
 
Cash at end of year(b)
  1,208   2,158   1,661 
 
(U.S. GAAP)

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, (20062006 - $395 million, 2005 - $350 million).
(b)Cash is composed of cash in bank and cash equivalents at cost. Cash equivalents are all highly liquid securities with maturity of three months or less when purchased.

The information on pages F-7 through F-20 is an integral part of these consolidated financial statements.

F-4statements


Consolidated balance sheet
         
millions of Canadian dollars      
At December 31 2007  2006 
 
Assets
        
Current assets        
Cash  1,208   2,158 
Accounts receivable, less estimated doubtful amounts  2,132   1,871 
Inventories of crude oil and products(note 13)
  566   556 
Materials, supplies and prepaid expenses  128   151 
Deferred income tax assets(note 5)
  660   573 
 
Total current assets  4,694   5,309 
Long-term receivables, investments and other long-term assets  766   104 
Property, plant and equipment, less accumulated depreciation and depletion(note 3)
  10,561   10,457 
Goodwill(note 3)
  204   204 
Other intangible assets, net  62   67 
 
Total assets(note 3)
  16,287   16,141 
 
         
Liabilities
        
Current liabilities        
Short-term debt  105   171 
Accounts payable and accrued liabilities(a)
  3,335   3,080 
Income taxes payable  1,498   1,190 
Current portion of long-term debt(b)
  3   907 
 
Total current liabilities  4,941   5,348 
Long-term debt(note 4)(c)
  38   359 
Other long-term obligations(note 7)
  1,914   1,683 
Deferred income tax liabilities(note 5)
  1,471   1,345 
 
Total liabilities
  8,364   8,735 
 
         
Commitments and contingent liabilities(note 11)
        
         
Shareholders’ equity
        
Common shares at stated value(note 12)(d)
  1,600   1,677 
Earnings reinvested  7,071   6,462 
Accumulated other comprehensive income  (748)  (733)
 
Total shareholders’ equity
  7,923   7,406 
 
         
Total liabilities and shareholders’ equity
  16,287   16,141 
 
(a)Accounts payable and accrued liabilities include amounts to related parties of $260 million (2006 - $151 million), (note 16).
(b)Current portion of long-term debt in 2006 included $500 million to related parties. There is no current portion of long-term debt to related parties in 2007, (note 4).
(c)Long-term debt in 2006 included $318 million to related parties. There is no long-term debt to related parties in 2007, (note 4).
(d)Number of common shares outstanding was 903 million (2006 - 953 million), (note 12).
The information on pages F-7 through F-20 is an integral part of these consolidated financial statements.
Approved by the directors
/s/ T.J. Hearn/s/ Paul A. Smith
Chairman, andSenior vice-president,
chief executive officerfinance and administration, and treasurer

F-5


Consolidated statement of shareholders’ equity
             
millions of Canadian dollars         
At December 31 2007  2006  2005 
 
Common shares at stated value(note 12)
            
At beginning of year  1,677   1,747   1,801 
Issued under the stock option plan  12   10   38 
Share purchases at stated value  (89)  (80)  (92)
 
At end of year  1,600   1,677   1,747 
 
             
Earnings reinvested
            
At beginning of year  6,462   5,466   4,889 
Cumulative effect of accounting change(note 2)
  14       
Net income for the year  3,188   3,044   2,600 
Share purchases in excess of stated value  (2,269)  (1,737)  (1,703)
Dividends  (324)  (311)  (320)
 
At end of year  7,071   6,462   5,466 
 
             
Accumulated other comprehensive income
            
At beginning of year  (733)  (580)  (368)
Post-retirement benefits liability adjustment(note 6)
  (87)  (733)   
Amortization of post-retirement benefits liability adjustment included in net periodic benefit cost  72       
Minimum pension liability adjustment(note 6)
     580   (212)
 
At end of year  (748)  (733)  (580)
 
             
Shareholders’ equity at end of year
  7,923   7,406   6,633 
 
             
Comprehensive income for the year
            
Net income for the year  3,188   3,044   2,600 
Post-retirement benefits liability adjustment(note 18)
  (15)      
Minimum pension liability adjustment(note 18)
     334   (212)
 
Total comprehensive income for the year
  3,173   3,378   2,388 
 
The information on pages F-7 through F-20 is an integral part of these consolidated financial statements.

F-6


Notes to consolidated financial statements

The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Imperial Oil Limited.

The 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.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 2007 presentation. All amounts are in Canadian dollars unless otherwise indicated.
1.Summary of significant accounting policies
Principles of consolidation
The consolidated financial statements include the accounts of Imperial Oil Limited and its subsidiaries. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic, operating, investing and financing policies. Significant subsidiaries included in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum Inc. All of the above companies are wholly owned. A significant portion of the company’s activities in natural resources is conducted jointly with other companies. The accounts reflect the company’s share of undivided interest in such activities, including its 25 percent interest in the Syncrude joint venture and its nine percent interest in the Sable offshore energy project.
Inventories
Inventories are recorded at the lower of cost or net realizable value. The cost of crude oil and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected over the alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period.
Inventory costs include expenditures and other charges, including depreciation, directly or indirectly incurred in bringing the inventory to its existing condition and final storage prior to delivery to a customer. Selling and general expenses are reported as period costs and excluded from inventory costs.
Investments
The principal investments in companies other than subsidiaries are accounted for using the equity method. They are recorded at the original cost of the investment plus 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 were charged to expense. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The company uses this accounting policy instead of the full-cost method because it provides a more timely accounting of the success or failure of the 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.

F-7

Principles of consolidation


The company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign-currency exchange rates. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products sold under contract are based on corporate plan assumptions developed annually by major contracts and also for investment evaluation purposes.
In general, impairment analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.
Acquisition costs for the 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 assets begins at the time when production commences on a regular basis. Assets under construction are not depreciated. Investments in extraction facilities, which separate the crude from sand, as well as the upgrading facilities, are depreciated on a unit-of-production method based on proven developed reserves. Investments in mining and transportation systems are generally depreciated on a straight-line basis over a 15-year life.
Oil sands assets held and used by the company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts are not recoverable. The impairment evaluation for oil sands assets is based on a comparison of undiscounted cash flows to book carrying value.
Gains or losses on assets sold are included in “investment and other income” in the consolidated statement of income.
(a) Oil sands are a semi-solid material composed of bitumen, sand, water and clays, and are recovered through surface mining methods. Currently, the company’s oil sands production volumes and reserves are the company’s share of production volumes and reserves in the Syncrude joint venture.
Interest capitalization
Interest costs relating to major capital projects under construction are capitalized as part of property, plant and equipment. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use.
Goodwill and other intangible assets
Goodwill is not subject to amortization. Goodwill is tested for impairment annually or more frequently if events or circumstances indicate it might be impaired. Impairment losses are recognized in current period earnings. The evaluation for impairment of goodwill is based on a comparison of the carrying values of goodwill and associated operating assets with the estimated present value of net cash flows from those operating assets.
Intangible assets with determinable useful lives are amortized over the estimated service lives of the assets. Computer software development costs are amortized over a maximum of 15 years and customer lists are amortized over a maximum of 10 years. The amortization is included in “depreciation and depletion” in the consolidated statement of income.
Asset retirement obligations and other environmental liabilities
Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. These obligations primarily relate to soil remediation and decommissioning and removal costs of oil and gas wells and related facilities. The obligations are initially measured at fair value and discounted to present value. A corresponding amount equal to that of the initial obligation is added to the capitalized costs of the related asset. Over time the discounted asset retirement obligation amount will be accreted for the change in its present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets.
No asset retirement obligations are set up for those manufacturing, distribution and marketing facilities with an indeterminate useful life. Asset retirement obligations for these facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites have indeterminate lives based on plans for continued operations, and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations. Provision for environmental liabilities of these assets is made when it is probable that obligations have been incurred and the amount can be reasonably estimated. These liabilities are not discounted. Asset retirement obligations and other provisions for environmental liabilities are determined based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location.
Foreign-currency translation
Monetary assets and liabilities in foreign currencies have been translated at the rates of exchange prevailing on December 31. Any exchange gains or losses are recognized in income.
Financial instruments
The fair values of cash, accounts receivable and current liabilities approximate recorded amounts because of the short period to receipt or payment of cash. The fair value of the company’s long-term debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered to the company for debt of the same duration to maturity. The fair values of the 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 and does not sell forward any part of production from any business segment.
Revenues
Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and other items are recorded when the products are delivered. Delivery occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured. The company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the company provide the customer with a right of return.
Revenues include amounts billed to customers for shipping and handling. Shipping and handling costs incurred up to the point of final storage prior to delivery to a customer are included in “purchases of crude oil and products” in the consolidated statement of income. Delivery costs from final storage to customer are recorded as a marketing expense in “selling and general” expenses.

F-8


Notes to consolidated financial statements (continued)
include the accounts of Imperial Oil Limited and its subsidiaries. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic, operating, investing and financing policies. Significant subsidiaries included in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum Inc. All of the above companies are wholly owned. A significant portion of the company’s Upstream activities is conducted jointly with other companies. The accounts reflect the company’s share of undivided interest in such activities, including its 25 percent interest in the Syncrude joint venture and its nine percent interest in the Sable offshore energy project.

Inventories

Inventories are recorded at the lower of cost or 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.Effective January 1, 2006, the company adopted the Emerging Issues Task Force (EITF) consensus on Issue No. 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold. In prior periods, the company recorded certain crude oil, natural gas, petroleum product and chemical sales and purchases contemporaneously negotiated with the same counterparty as revenues and purchases. As a result of the EITF consensus, beginning in 2006, the company’s accounts “operating revenues” and “purchases of crude oil and products” on the consolidated statement of income have been reduced by associated amounts with no impact on net income. All operating segments were affected by this change, with the largest impact in the petroleum products segment.
Share-based compensation
The company awards share-based compensation to employees in the form of restricted stock units. Compensation expense is measured each reporting period based on the 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 9 to the consolidated financial statements for further details.
Consumer taxes
Taxes levied on the consumer and collected by the company are excluded from the consolidated statement of income. These are primarily provincial taxes on motor fuels and the federal goods and services tax.
2.Accounting change for uncertainty in income taxesfair value measurement

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.Effective January 1, 2007, the company adopted the FASB Interpretation No. 48 (FIN 48), “Accounting for Uncertainty in Income Taxes”. FIN 48 is an interpretation of FASB Statement No. 109, “Accounting for Income Taxes” and prescribes a comprehensive model for recognizing, measuring, presenting and disclosing in the financial statements uncertain tax positions that the company has taken or expects to take in its income tax returns. Upon the adoption of FIN 48, the company recognized a transition gain of $14 million in shareholders’ equity, reflected as cumulative effect of accounting change in the consolidated statement of shareholders’ equity. The gain reflected the recognition of several refund claims with associated interest, partly offset by increased income tax reserves. FIN 48 also resulted in a reclassification of amounts previously reported net on the balance sheet. The balance sheet reclassification resulted in a $534 million increase to long-term receivables, investments and other long-term assets; a $363 million increase to income taxes payable; a $142 million increase to other long-term obligations; and a $15 million increase to deferred tax liabilities. See note 5, Income taxes, for additional disclosures.
3.Business segments
The company operates its business in Canada. The natural resources, petroleum products and chemicals functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment and the structure of the company’s internal organization. The natural resources segment is organized and operates to explore for and ultimately produce crude oil and its equivalent, and natural gas. The petroleum products segment is organized and operates to refine crude oil into petroleum products and the distribution and marketing of these products. The chemicals segment is organized and operates to manufacture and market hydrocarbon-based chemicals and chemical products. The above segmentation has been the long-standing practice of the company and is broadly understood across the petroleum and petrochemical industries.
These functions have been defined as the operating segments of the company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the company’s chief operating decision maker to make decisions about resources to be allocated to each segment and assess its performance; and (c) for which discrete financial information is available.
Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash, long-term debt and liabilities associated with incentive compensation and post-retirement benefits liability adjustment. Net income in this segment primarily includes financing costs, interest income and incentive compensation expenses.
Segment accounting policies are the same as those described in the summary of significant accounting policies. Natural resources, petroleum products and chemicals expenses include amounts allocated from the “corporate and other” segment. The allocation is based on a combination of fee for service, proportional segment expenses and a three-year average of capital expenditures. Transfers of assets between segments are recorded at book amounts. Intersegment sales are made essentially at prevailing market prices. Assets and liabilities that are not identifiable by segment are allocated.

F-9

The company operates its business in Canada. The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment and the structure of the company’s internal organization. The Upstream segment is organized and operates to explore for and ultimately produce crude oil and its equivalent, and natural gas. The Downstream segment is organized and operates to refine crude oil into petroleum products and the distribution and marketing of these products. The Chemical segment is organized and operates to manufacture and market hydrocarbon-based chemicals and chemical products. The above segmentation has been the long-standing practice of the company and is broadly understood across the petroleum and petrochemical industries.


These functions have been defined as the operating segments of the company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the company’s chief operating decision maker to make decisions about resources to be allocated to each segment and assess its performance; and (c) for which discrete financial information is available.

Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash, long-term debt and liabilities associated with incentive compensation and post-retirement benefits liability adjustment. Net income in this segment primarily includes financing costs, interest income and 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

Notes to consolidated financial statements (continued)
 (a)A significant portion of activities in the natural resourcesUpstream segment is conducted jointly with other companies. The segment includes the company’s share of undivided interest in such activities as follows:
             
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 $318$314 million in 2007 (20062008 (2007-$318 million, 2006 - $316 million, 2005 - $310 million)).
 (d)Includes property, plant and equipment under construction of $951$1,523 million (2006 - $782(2007-$951 million).
 (e)All goodwill has been assigned to the petroleum productsDownstream segment. There have been no goodwill acquisitions, impairment losses or write-offs due to sales in the past three years.
4.  Long-term debt
             
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)At 2006 year-end, the company had $818 million long-term variable-rate loans from an affiliated company of Exxon Mobil Corporation at interest equivalent to Canadian market rates. $500 million of these long-term loans was due in 2007 and included in current liabilities and $318 million was due on January 19, 2008 and included as long-term debt at 2006 year-end.
(b)In the second and third quarter of 2007, two variable-rate loans totaling $500 million matured and were replaced with two long-term variable-rate loans totaling $500 million from an affiliated company of Exxon Mobil Corporation at interest equivalent to Canadian market rates. Both loans were due in 2009. In the fourth quarter of 2007, the company retired the entire $818 million of long-term loans.
(c)The average effective rate for long-term loans was 4.5 percent for 2007.
(d)These obligations primarily relate to the capital lease for marine services, which are provided by the lessor commencing in 2004 for a period of 10 years, extendable for an additional five years. The average imputed rate was 10.9 percent in 2007 (2006 - 10.7 percent).
(e)Principal payments on capital leases of approximately $4 million a year are due in each of the next five years.
(f)These amounts exclude that portion of long-term debt, totaling $3 million (2006 – $907 million), which matures within one year and is included in current liabilities.
5.  Income taxes
             
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 
       
(a)The provisions for deferred income taxes in 20072008 include net (charges)/credits for the effect of changes in tax laws and rates of $90$1 million (2006 - $81(2007 -$90 million, 2005 - nil)2006 -$81 million).
 (b)Cash outflow from income taxes, plus investment credits earned, was $1,101 million in 2008 (2007 – $1,395 million, in 2007 (20062006 – $1,000 million,2005 – $1,024 million).

F-11


Income taxes (charged)/credited directly to shareholders’ equity were:
             
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 
     
(a) Tax losses can be carried forward indefinitely.

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 dollars2007
January 1 balance142
Additions for prior years’ tax positions28
December 31 balance
170
benefits:

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.

6. Employee retirement benefits

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
post-retirement

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    -     -     -

Notes to consolidated financial statements (continued)
                         
              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 
             
Costs for defined contribution plans, primarily the employee savings plan, were $31$33 million in 2007 (2006 – $302008 (2007 - -$31 million, 2005 –2006 - $30 million).

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.

2011.

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.

last 10- and 20- year periods ending December 31, 2008.

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
2009

  

        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


Notes to consolidated financial statements (continued)
A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below:
         
  Pension benefits 
millions of dollars 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.

plans.

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)
 

F-15


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)

7.6.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)(a)Total recorded employee retirement benefit obligations also include $59$45 million in current liabilities (2006(2007$51$59 million).
(b)(b)Total asset retirement obligations and other environmental liabilities also include $74$83 million in current liabilities (2006(2007$97$74 million).
The following table summarizes the activity in the liability for asset retirement obligations:
         
millions of dollars 2007  2006 
 
January 1 balance  422   367 
Additions  71   61 
Accretion  25   22 
Settlement  (30)  (28)
 
December 31 balance  488   422 
 

8.Derivatives and financial instruments
     The company did not enter into any energy derivatives, foreign-exchange forward contracts or currency and interest-rate swapsfollowing table summarizes the activity in the past three years. The company maintains a system of controls that includes a policy covering the authorization, reportingliability for asset retirement obligations:

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 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.

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.

9.8.Share-based incentive compensation programs
Share-based incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contribution to sustained improvement in the company’s future business performance and shareholder value.
Incentive share units, deferred share units and restricted stock units
Incentive share units have value if the market price of the 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.
The deferred share unit plan is made available to selected executives and nonemployee directors. The selected executives can elect to receive all or part of their performance bonus compensation in units and the nonemployee directors can elect to receive all or part of their directors’ fees in units. The number of units granted to executives is determined by dividing the amount of the bonus elected to be received as deferred share units by the average of the closing prices of the company’s shares on the Toronto Stock Exchange for the five consecutive trading days immediately prior to the date that the bonus would have been paid. The number of units granted to a nonemployee director is determined at the end of each calendar quarter by dividing the amount of director’s fees for the calendar quarter that the nonemployee director elected to receive as deferred share units by the average closing price of the company’s shares for the five consecutive trading days immediately prior to the last day of the calendar quarter. Additional units are granted based on the cash dividend payable on the company’s  shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient, as adjusted for any share splits.
Deferred share units cannot be exercised until after termination of employment with the company or resignation as a director and must be exercised no later than December 31 of the year following termination or resignation. On the exercise date, the cash value to be received for the units is determined based on the average closing price of the 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. 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 one exception. The restricted stock unit program was amended for units granted in 2002 and future years by providing that the recipient may receive one common share of the company per unit or elect to receive the cash payment for the units to be exercised in the seventh year following the grant date.
In accordance with the Financial Accounting Standards Board’s (FASB) revised statement of Financial Accounting Standards No.123 (SFAS 123R), “Share-based Payment”, 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

F-16

Share-based incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contribution to sustained improvement in the company’s future business performance and shareholder value.


Incentive share units, deferred share units and restricted stock units

Incentive share units have value if the market price of the 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.

NotesThe deferred share unit plan is made available to consolidated financial statements (continued)
selected executives and nonemployee directors. The selected executives can elect to receive all or part of their performance bonus compensation in units, and the nonemployee directors can elect to receive all or part of their directors’ fees in units. The number of units granted to executives is determined by dividing the amount of the bonus elected to be received as deferred share units by the average of the closing prices of the company’s shares on the Toronto Stock Exchange for the five consecutive trading days immediately prior to the date that the bonus would have been paid. The number of units granted to a nonemployee director is determined at the end of each calendar quarter by dividing the amount of director’s fees for the calendar quarter that the nonemployee director elected to receive as deferred share units by the average closing price of the company’s shares for the five consecutive trading days immediately prior to the last day of the calendar quarter. Additional units are granted based on the cash dividend payable on the company’s shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient, as adjusted for any share splits.

Deferred share units cannot be exercised until after termination of employment with the company or resignation as a director and must be exercised no later than December 31 of the year following termination or resignation. On the exercise date, the cash value to be received for the units is determined based on the average closing price of the 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 85090 52610 219 851

Granted

-10 9371 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 01586 37110 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.

2008.

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.

2008.

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 
 

10.9.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

 Investment and other income includes gains and losses on asset sales as follows:
             
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)2005 included a gain of $251 million ($163 million, after tax) from the sale of the wholly owned Redwater and interests in the North Pembina fields.
(b)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.

F-17


11. (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

 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.
In 2007, the Alberta government proposed changes to the oil and gas and generic oil sands royalty regime beginning in 2009. The company believes that this proposal could have an adverse effect on future company investments in Alberta and the company’s future financial results. The magnitude of the potential impact will depend on the final form of enacted legislation and the future prices of oil and gas and cannot be reasonably estimated at this time. The Syncrude Joint Venture owners have a Crown Agreement with the Province of Alberta that codifies the royalty rates through December 31, 2015. The Syncrude Joint Venture owners are in discussions with the Alberta government to determine if an amended agreement can be negotiated that would transition Syncrude to the new generic oil sands royalty regime before 2016.
The company was contingently liable at December 31, 2007 for a maximum of $83 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing associates upon expiry of the associate agreement or the resignation of the associate. The company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future 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 2008  2009  2010  2011  2012  After 2012  Total 
 
Unconditional purchase obligations(a)  99   96   64   64   121   38   482 
 
(a)Undiscounted obligations of $482$420 million mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $117 million (2007 - $94 million, (20062006 - - $100 million,2005 - $104 million). The present value of these commitments, excluding imputed interest of $84$66 million, totaled $398$354 million.

12.11.Common shares
         
  As at  As at 
thousands of shares Dec. 31 2007  Dec. 31 2006 
 
Authorized  1,100,000   1,100,000 
 
Effective May 23, 2006, the issued common shares of the company were split on a three-for-one basis and the number of authorized shares was increased from 450 million to 1,100 million. The prior period number of shares outstanding and shares purchased, as well as net income and dividends per share, have been adjusted to reflect the three-for-one split.
From 1995 to 2006, the company purchased shares under twelve 12-month normal course share purchase programs, as well as an auction tender. On June 25, 2007, another 12-month normal course share purchase program was implemented with an allowable purchase of 46.5 million shares (five percent of the total at June 22, 2007), less any shares purchased by the employee savings plan and company pension fund. The results of these activities are shown below.
         
  Purchased shares  Millions of 
Year (thousands)  dollars 
 
1995 to 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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Notes to consolidated financial statements (continued)
The following table provides the calculation of basic and diluted earnings per share:
             
  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 
 
13.Miscellaneous financial information
In 2007, net income included an after-tax gain of $25 million (2006 – $14 million gain, 2005 – $5 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, 2007 by $1,953 million (2006 – $1,509 million). Inventories of crude oil and products at year-end consisted of the following:
         
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 
 
Research and development costs in 2007 were $89 million (2006 – $73 million, 2005 – $68 million) before investment tax credits earned on these expenditures of $6 million (2006 – $7 million, 2005 – $10 million). Research and development costs are included in expenses due to the uncertainty of future benefits.
Cash flow from operating activities included dividends of $22 million received from equity investments in 2007 (2006 – $18 million, 2005 – $21 million).
14.Financing costs
             
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 
 
(a)thousands of shares  

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 62310 453

2007

50 5162 358

2008

44 2952 210

Cumulative purchases to date

890 43415 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 20072008 were $6 million (2007 - $80 million, (20062006 - $71 million, 2005 - $45 million). The weighted average interest rate on short-term borrowings in 20072008 was 5.13.5 percent (2006 – 4.1(2007 - 5.1 percent).

15.14.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

 At December 31, 2007, the company held non-cancelable operating leases covering office buildings, rail cars, service stations and other properties with minimum undiscounted lease commitments totaling $232 million as indicated in the following table:
                             
  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 20072008 was $79$149 million (2006(2007 - $79$98 million, 20052006 - $83$101 million) which included minimum rental expenditures of $67$140 million (2006(2007 - $66$86 million, 20052006 - $63$88 million). Related rental income was not material.

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.

16.15.Transactions with related parties

Revenues and expenses of the company also include the results of transactions with Exxon Mobil Corporation and affiliated companies (ExxonMobil) in the normal course of operations. These were conducted on terms as favourable as they would have been with unrelated parties and primarily consisted of the purchase and sale of crude oil, 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)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 natural resources activities conducted jointly in Canada. The company has existing agreements with affiliates of Exxon Mobil Corporation to provide computer and customer support services to the company and to share common business and operational support services that allow the companies to consolidate duplicate work and systems. The company has a contractual agreement with an affiliate of Exxon Mobil Corporation in Canada to systems;
(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 reserves. During 2007, the company entered into agreements with Exxon Mobil Corporation and one of its affiliated companies that reserves;
(c)provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil.ExxonMobil;
 (d)Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.
As at December 31, 2007, the company had outstanding loans of $33 million (2006 - $33 million)share new upstream opportunities on an up 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.
17.Net payments/payables to governmentsequal basis.
             
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 
 
(a)The abbreviations refer to the federal goods and services tax, the Quebec sales tax and the federal/provincial harmonized sales tax, respectively. The HST is applicable in the provinces of Nova Scotia, New Brunswick and Newfoundland and Labrador.
18.Additional SFAS 158 adoption disclosure
In its 2006 financial statements, the company reported the adjustment related to the adoption of SFAS 158. Based on further regulatory guidance, this adjustment should have been reported as an adjustment to ending 2006 accumulated other comprehensive income. The amount reported by the company as 2006 comprehensive income (nonowner changes in equity) was $2,891 million. Excluding the negative $487 million SFAS 158 adoption adjustment (which was separately disclosed in note 6 to the 2006 consolidated financial statements, Employee retirement benefits), the amount would have been $3,378 million. The company has accordingly revised the presentation of 2006 comprehensive income (nonowner changes in equity) in its 2007 financial statements.

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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