Total average daily
oil-equivalent
basis productionThe company’s total average daily production expressed in an
oil-equivalent
basis is set forth below, with natural gas converted to anoil-equivalent
basis at six million cubic feet per one thousand barrels.| thousands of barrels per day (a) | 2019 | 2018 | 2017 | |||||||||
Total production oil-equivalent basis: | ||||||||||||
- gross (b) | 398 | 383 | 375 | |||||||||
- net (c) | 357 | 343 | 335 | |||||||||
| thousands of barrels per day (a) | 2020 | 2019 | 2018 | |||||||||
Total production oil-equivalent basis: | ||||||||||||
- gross (b) | 398 | 398 | 383 | |||||||||
- net (c) | 384 | 357 | 343 | |||||||||
| (a) | Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. |
| (b) | Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both. |
| (c) | Net production is gross production less the mineral owners’ or governments’ share or both. |
Average unit sales price
The company’s average unit sales price and average unit production costs by product type for the three years ended December 31, 20192020 were as follows.
| Canadian dollars per barrel | 2019 | 2018 | 2017 | |||||||||
Bitumen | 50.02 | 37.56 | 39.13 | |||||||||
Synthetic oil | 74.47 | 70.66 | 67.58 | |||||||||
Liquids (a) | 42.91 | 40.20 | 38.49 | |||||||||
Canadian dollars per thousand cubic feet | ||||||||||||
Natural gas | 2.05 | 2.43 | 2.58 | |||||||||
| Canadian dollars per barrel | 2020 | 2019 | 2018 | |||||||||
Bitumen | 25.69 | 50.02 | 37.56 | |||||||||
Synthetic oil | 49.76 | 74.47 | 70.66 | |||||||||
Liquids (a) | 27.40 | 42.91 | 40.20 | |||||||||
Canadian dollars per thousand cubic feet | ||||||||||||
Natural gas | 1.90 | 2.05 | 2.43 | |||||||||
| (a) | Liquids include crude oil, condensate and NGLs. |
In 2020, Imperial’s average Canadian dollar realizations for bitumen decreased primarily due to a decrease in Western Canada Select. The company’s average Canadian dollar realizations for synthetic crude decreased generally in line with West Texas Intermediate, adjusted for changes in exchange rates and transportation costs.
In 2019, Imperial’s average Canadian dollar realizations for bitumen increased, supported primarily by an increase in Western Canada Select and lower diluent costs. The company’s average Canadian dollar realizations for synthetic crude increased relative to West Texas Intermediate, primarily due to the narrowing of the western Canadian light crude differential.
Average unit production costs
| Canadian dollars per barrel | 2019 | 2018 | 2017 | |||||||||
Bitumen | 31.53 | 29.39 | 26.81 | |||||||||
Synthetic oil | 54.44 | 60.34 | 58.96 | |||||||||
Total oil-equivalent basis(a) | 34.82 | 35.28 | 32.96 | |||||||||
| Canadian dollars per barrel | 2020 | 2019 | 2018 | |||||||||
Bitumen | 25.73 | 31.53 | 29.39 | |||||||||
Synthetic oil | 45.51 | 54.44 | 60.34 | |||||||||
Total oil-equivalent basis(a) | 28.73 | 34.82 | 35.28 | |||||||||
| (a) | Includes liquids, bitumen, synthetic oil and natural gas. |
In 2020, bitumen unit production costs were lower, primarily driven by higher Kearl production due to improved reliability and reduced downtime related to the addition of supplemental crushing facilities in 2020, and cost saving activities in response to market conditions.
In 2020, synthetic oil unit production costs were lower, primarily driven by cost saving activities in response to market conditions.
In 2019, bitumen unit production costs were higher, primarily driven by Kearl costs associated with improving reliability and mine performance, and increased mine material movement.
In 2019, synthetic oil unit production costs were lower, primarily driven by higher production due to the absence of the site-wide power disruption at Syncrude in 2018 and lower maintenance costs.
Drilling and other exploratory and development activities
The company has been involved in the exploration for and development of crude oil and natural gas in Canada only.
Wells drilled
The following table sets forth the net exploratory and development wells that were drilled or participated in by the company during the three years ended December 31, 2019.2020.
| wells | 2019 | 2018 | 2017 | 2020 | 2019 | 2018 | ||||||||||||||||||
Net productive exploratory | - | - | - | - | - | - | ||||||||||||||||||
Net dry exploratory | - | - | - | - | - | - | ||||||||||||||||||
Net productive development | 28 | 19 | 5 | 29 | 28 | 19 | ||||||||||||||||||
Net dry development | - | 1 | - | - | - | 1 | ||||||||||||||||||
Total | 28 | 20 | 5 | 29 | 28 | 20 | ||||||||||||||||||
In 2020, wells drilled to add productive capacity include 28 development wells at Cold Lake and 1 well associated with the Montney and Duvernay unconventional assets.
In 2019, wells drilled to add productive capacity include 14 development wells at Cold Lake and 14 wells associated with the Montney and Duvernay unconventional assets.
In 2018, wells drilled to add productive capacity include 10 development wells at Cold Lake and 9 wells associated with the Montney and Duvernay unconventional assets.
Wells drilling
At December 31, 2019,2020, the company was participating in the drilling of the following exploratory and development wells within the Montney and Duvernay unconventional assets. All wells were located in Canada.
| 2019 | ||||||||
| wells | Gross | Net | ||||||
Total | 12 | 6 | ||||||
2020 | ||||||||
wells | Gross | Net | ||||||
Total | 18 | 9 | ||||||
Exploratory and development activities regarding oil and gas resources
Cold Lake
To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically. AdditionalIn 2020, additional wells were drilled on existing phases in 2019.phases. In 2020,2021, a development drilling program is planned within the approved development area to add productive capacity.
The company also conducts experimental pilot operations to improve recovery of bitumen from wells by means of new drilling, production or recovery techniques.
Aspen, Cold Lake expansion and other oil sands activities
The company filed a regulatory application for a new
in-situ
oil sands project at Aspen in December 2013, using steam-assisted gravity drainage (SAGD) technology to develop the project in three phases producing about 45,000 barrels per day before royalties, per phase. In 2015, the company amended the regulatory application to develop the Aspen project using solvent-assisted, steam-assisted gravity drainage(SA-SAGD)
technology. The technology significantly improves capital efficiency and lowers greenhouse gas intensity versus the existing SAGD technologies. The project is proposed to be executed in two phases producing about 75,000 barrels per day before royalties, per phase.11
In October 2018, regulatory approval for the Aspenbut italthough major investment remains on hold. Aspen remains an important development project for Imperial.
in-situ
project was received from the Alberta Energy Regulator. The first phase of the project was approved by the company’s board and appropriated for $2.6 billion. Construction began late in the fourth quarter of 2018. In March 2019, the company slowed the pace of development given market uncertainty stemming from the Government of Alberta’s temporary mandatory production curtailment regulations and other industry competitiveness challenges. Aspen’s project pace will be continuously evaluated, In March 2016, Imperial filed a regulatory application for an expansion project at Cold Lake to develop the Grand Rapids interval usingproject.project with a slower pace.
SA-SAGD
technology. The project is proposed to produce 50,000 barrels per day, before royalties. In August 2018, regulatory approval for the expansion project at Cold Lake was received from the Alberta Energy Regulator. The company continues to progress the Work progresses on technical evaluations to support potential Clarke Creek, Corner, Clyden and Chard
in-situ
development regulatory applications.The company also has interests in other oil sands leases in the Athabasca region of northern Alberta. Evaluation wells completed on these leased areas established the presence of bitumen. The company continues to evaluate these leases to determine their potential for future development.
Montney and Duvernay
The company is continuing to evaluate, develop and produce resourceshas ramped down development drilling in its Montney and Duvernay unconventional assets in the western provinces. Imperial has
re-assessed
the long-term development plans of its unconventional portfolio in Alberta and no longer plans to further develop a significant portion of this portfolio. The assets that will not be developed arenon-core,
non-producing,
undeveloped assets. This decision is consistent with Imperial’s strategy of focusing its upstream resources and efforts on its key oil sands assets as well as on only the most attractive portions of its unconventional portfolio. The decision resulted in anon-cash,
after-tax
impairment charge of $1,171 million in 2020, thereby reducing the carrying value of those assets to fair value. The company retains its interest in these resources. Imperial continues to produce from its developed acreage.Beaufort Sea
In 2007, the company acquired a 50 percent interest in an exploration licence in the Beaufort Sea. As part of the evaluation, a
3-D
seismic survey was conducted in 2008 and the company has since carried out data collection programs to support environmental studies and safe exploration drilling operations.In 2010, the company executed an agreement to cross-convey interests with another company to acquire a 25 percent interest in an additional Beaufort Sea exploration licence. As a result of that agreement, the company operates both licences and its interest in the original licence was reduced to 25 percent.
In 2013, the company and its joint venture partners filed a project description, initiating the formal regulatory review of the project.
In 2016, the Federal Government of Canada declared Arctic waters off limits to new offshore oil and gas licences for five years subject to review at the end of that period. Existing licences were not impacted.
In June 2019, the Federal Government approved selective changes to theto provide an indefinite prohibition and freeze of the existing licences through the completion of the Beaufort Sea Regional Environmental Assessmentactively focusing onmaintaining community engagement and participation in the
Canada Petroleum Resources Act
(BR-SEA)
review. The Federal Government continues to consult with stakeholders as part of theBR-SEA
to address regional social, environmental, economic and spill response impacts of natural resource development in the Arctic. The company continues to hold the licences while BR-SEA
process.Exploratory and development activities regarding oil and gas resources extracted by mining methods
The company continues to evaluate other undeveloped, mineable oil sands acreage in the Athabasca region.
Present activities
Review of principal ongoing activities
Kearl
Kearl is a joint venture established to recover shallow deposits of oil sands using
open-pit
mining methods to extract the crude bitumen, which is processed through extraction and froth treatment trains. The company holds a 70.96 percent participating interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. The product, a blend of bitumen and diluent, is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation by pipeline and rail.During 2019,2020, the company’s share of Kearl’s net bitumen production was about 140,000155,000 barrels per day and gross production was about 145,000158,000 barrels per day.
Kearl’s supplemental crushing facilities started operations in late 2019, withare expected tohave further improveimproved reliability, reducereduced planned downtime, lowerlowered unit costs and enabled the asset to achieve higher volumes. As disclosed in the company’s 2019 Form240,000255,000 barrels per day of total gross production in 2021 (about 181,000 barrels Imperial’s share).
ramp-up
of all units through early 2020. These facilities 10-K,
the original production target in 2020 for Kearl was 240,000 barrels per day (about 170,000 barrels Imperial’s share). As a result of market conditions, the company adjusted planned maintenance and turnaround activity, and revised its full-year guidance for Kearl total gross production to 220,000 barrels per day (about 156,000 barrels Imperial’s share). In 2020, Kearl achieved record annual total gross production of 222,000 barrels per day (158,000 barrels Imperial’s share). Imperial continues to progress initiatives to enable the asset to achieve As a result of low prices during 2020, (Imperial’s gross share wouldunder the SEC definition of proved reserves, certain quantities of bitumen that qualified as proved reserves in prior years did not qualify as proved reserves atabout 170,000 barrels per day).affected by the downward revision of reported proved reserves as disclosed under the U.S. SEC definition.
year-end
2020. Amounts no longer qualifying as proved reserves include 2.2 billion barrels of bitumen at Kearl. Among the factors that could result in portions of these amounts being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, a further decline in costs, and / or operating efficiencies. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributed to Imperial. The company does not expect its operations to be Cold Lake
Cold Lake is an
in-situ
heavy oil bitumen operation. The product, a blend of bitumen and diluent, is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties.During 2019,2020, net bitumen production at Cold Lake was about 114,000124,000 barrels per day and gross production was about 140,000132,000 barrels per day.
As a result of low prices during 2020, under the SEC definition of proved reserves, certain quantities of bitumen that qualified as proved reserves in prior years did not qualify as proved reserves at
year-end
2020. Amounts no longer qualifying as proved reserves include 0.6 billion barrels of bitumen at Cold Lake. Among the factors that could result in portions of these amounts being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, a further decline in costs, and / or operating efficiencies. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributed to Imperial. The company does not expect its operations to be affected by the downward revision of reported proved reserves as disclosed under the U.S. SEC definition.13
Syncrude
Syncrude is a joint venture established to recover shallow deposits of oil sands using
open-pit
mining methods to extract crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. The company holds a 25 percent participating interest in the joint venture. The produced synthetic crude oil is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties.In 2019,2020, the company’s share of Syncrude’s net production of synthetic crude oil was about 65,00068,000 barrels per day and gross production was about 73,00069,000 barrels per day.
The Province of Alberta, in its capacity as lessor of Kearl, Cold Lake, and Syncrude oil sands leases, is entitled to a royalty on production. Royalties are subject to the oil sands royalty regulations which are based upon a sliding scale determined largely by the price of crude oil.
The company has no material commitments to provide a fixed and determinable quantity of oil or gas under existing contracts and agreements.
Oil and gas properties, wells, operations and acreage
Production wells
The company’s production of liquids, bitumen and natural gas is derived from wells located exclusively in Canada. The total number of wells capable of production, in which the company had interests at December 31, 20192020 and December 31, 2018,2019, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.
| Year ended December 31, 2019 | Year ended December 31, 2018 | |||||||||||||||||||||||||||||||
| Crude oil | Natural gas | Crude oil | Natural gas | |||||||||||||||||||||||||||||
| wells | Gross (a) | Net (b) | Gross (a) | Net (b) | Gross (a) | Net (b) | Gross (a) | Net (b) | ||||||||||||||||||||||||
Total (c) | 4,646 | 4,603 | 2,801 | 911 | 4,760 | 4,655 | 3,459 | 1,164 | ||||||||||||||||||||||||
Year ended December 31, 2020 | Year ended December 31, 2019 | |||||||||||||||||||||||||||||||
| Crude oil | Natural gas | Crude oil | Natural gas | |||||||||||||||||||||||||||||
| wells | Gross (a) | Net (b) | Gross (a) | Net (b) | Gross (a) | Net (b) | Gross (a) | Net (b) | ||||||||||||||||||||||||
Total (c) | 4,660 | 4,610 | 2,767 | 898 | 4,646 | 4,603 | 2,801 | 911 | ||||||||||||||||||||||||
| (a) | Gross wells are wells in which the company owns a working interest. |
| (b) | Net wells are the sum of the fractional working interest owned by the company in gross wells, rounded to the nearest whole number. |
| (c) | Multiple completion wells are permanently equipped to produce separately from two or more distinctly different geological formations. At year-end |
Land holdings
At December 31, 20192020 and December 31, 2018,2019, the company held the following oil and gas rights, and bitumen and synthetic oil leases, all of which are located in Canada, specifically in the western provinces, in the Canada lands and in the Atlantic offshore.
| Developed | Undeveloped | Total | ||||||||||||||||||||||||
| thousands of acres | 2019 | 2018 | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||||||
Western provinces (a) : | ||||||||||||||||||||||||||
Liquids and gas | - gross (b) | 1,056 | 1,497 | 771 | 807 | 1,827 | 2,304 | |||||||||||||||||||
| - net (c) | 516 | 721 | 432 | 446 | 948 | 1,167 | ||||||||||||||||||||
Bitumen | - gross (b) | 197 | 197 | 601 | 595 | 798 | 792 | |||||||||||||||||||
| - net (c) | 182 | 182 | 269 | 292 | 451 | 474 | ||||||||||||||||||||
Synthetic oil | - gross (b) | 118 | 118 | 136 | 136 | 254 | 254 | |||||||||||||||||||
| - net (c) | 29 | 29 | 34 | 34 | 63 | 63 | ||||||||||||||||||||
Canada lands (d): | ||||||||||||||||||||||||||
Liquids and gas | - gross (b) | 4 | 4 | 1,831 | 1,831 | 1,835 | 1,835 | |||||||||||||||||||
| - net (c) | 2 | 2 | 498 | 498 | 500 | 500 | ||||||||||||||||||||
Atlantic offshore: | ||||||||||||||||||||||||||
Liquids and gas | - gross (b) | 65 | 65 | 267 | 286 | 332 | 351 | |||||||||||||||||||
| - net (c) | 6 | 6 | 36 | 45 | 42 | 51 | ||||||||||||||||||||
Total (e): | - gross (b) | 1,440 | 1,881 | 3,606 | 3,655 | 5,046 | 5,536 | |||||||||||||||||||
| - net (c) | 735 | 940 | 1,269 | 1,315 | 2,004 | 2,255 | ||||||||||||||||||||
| Developed | Undeveloped | Total | ||||||||||||||||||||||||
| thousands of acres | 2020 | 2019 | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||||||
Western provinces (a) : | ||||||||||||||||||||||||||
Liquids and gas | - gross (b) | 1,043 | 1,056 | 697 | 771 | 1,740 | 1,827 | |||||||||||||||||||
| - net (c) | 510 | 516 | 388 | 432 | 898 | 948 | ||||||||||||||||||||
Bitumen | - gross (b) | 197 | 197 | 594 | 601 | 791 | 798 | |||||||||||||||||||
| - net (c) | 182 | 182 | 265 | 269 | 447 | 451 | ||||||||||||||||||||
Synthetic oil | - gross (b) | 119 | 118 | 100 | 136 | 219 | 254 | |||||||||||||||||||
| - net (c) | 30 | 29 | 25 | 34 | 55 | 63 | ||||||||||||||||||||
Canada lands (d) : | ||||||||||||||||||||||||||
Liquids and gas | - gross (b) | 2 | 4 | 1,803 | 1,831 | 1,805 | 1,835 | |||||||||||||||||||
| - net (c) | 2 | 2 | 495 | 498 | 497 | 500 | ||||||||||||||||||||
Atlantic offshore: | ||||||||||||||||||||||||||
Liquids and gas | - gross (b) | 65 | 65 | 267 | 267 | 332 | 332 | |||||||||||||||||||
| - net (c) | 6 | 6 | 36 | 36 | 42 | 42 | ||||||||||||||||||||
Total (e) : | - gross (b) | 1,426 | 1,440 | 3,461 | 3,606 | 4,887 | 5,046 | |||||||||||||||||||
| - net (c) | 730 | 735 | 1,209 | 1,269 | 1,939 | 2,004 | ||||||||||||||||||||
| (a) | Western provinces include British Columbia and Alberta. |
| (b) | Gross acres include the interests of others. |
| (c) | Net acres exclude the interests of others. |
| (d) | Canada lands include the Arctic Islands, Beaufort Sea / Mackenzie Delta, and other Northwest Territories and Yukon |
| (e) | 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). |
15
Western provinces
The company’s bitumen leases include about 171,000 net acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company also has about 69,00068,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company has interests in other bitumen oil sands leases in the Athabasca areas totalling about 177,000174,000 net acres, which include about 62,000 net acres of oil sands leases in the Clyden area, about 34,000 net acres of oil sands leases in the Aspen area, about 30,000 net acres of oil sands leases in the Corner area, and about 18,000 net acres in the Chard area. In August 2019, Imperial acquired a 50 percent ownershiparea and about 29,000 net acres in the Clarke Creek area, totalling about 29,000 net acres of additional oil sands leases.area. The 177,000174,000 net acres are suitable for
in-situ
recovery techniques.The company’s share of Syncrude joint venture leases covering about 63,00055,000 net acres accounts for the entire synthetic oil acreage.
Oil sands leases have an exploration period of 15 years and are continued beyond that point by meeting the minimum level of evaluation, by payment of escalating rentals or by production. The majority of the acreage in Cold Lake, Kearl and Syncrude is continued by production.
The company holds interests in an additional 948,000898,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas. In 2019,gas, including about 387,000 net acres associated with the company divested mature conventional properties totalling 214,000 net acres.company’s unconventional portfolio in Alberta. Imperial has
re-assessed
the long-term development of its unconventional portfolio and no longer plans to further develop a significant portion of this portfolio.Crude oil and natural gas leases and licences from the western provinces have exploration periods ranging from two to 15 years and are continued beyond that point by proven production capability.
Canada lands
Land holdings in Canada lands primarily include exploration licence (EL) acreage in the Beaufort Sea of about 252,000 net acres and significant discovery licence (SDL) acreage in the Mackenzie Delta and
Beaufort Sea areas of about 183,000 net acres.
Exploration licences on Canada lands have a finite term. If a significant discovery is made, a SDL may be granted that holds the acreage under the SDL indefinitely, subject to certain conditions.
The company’s net acreage in Canada lands is either continued by production or held through ELs and SDLs.
Atlantic offshore
Exploration licences on Atlantic offshore have a finite term. The Atlantic offshore acreage is continued by production licences or held by SDLs.
Downstream
The company supplements its own production of crude oil, condensate and petroleum products with substantial purchases from a number of other sources at negotiated market prices. Purchases are made under both spot and term contracts from domestic and foreign sources, including ExxonMobil.
Imperial currently transports the company’s crude oil production and third partythird-party crude oil required to supply refineries by contracted pipelines, common carrier pipelines and rail. To mitigate uncertainty associated with the timing of industry pipeline projects and pipeline capacity constraints, the company has developed rail infrastructure. The Edmonton rail terminal has total capacity to ship up to 210,000 barrels per day of crude oil. In 2019, shipments through the Edmonton rail terminal averaged 51,000 barrels per day.
The company owns and operates three refineries, which process predominantly Canadian crude oil. The company purchases finished products to supplement its refinery production.
The approximate average daily volumes of refinery throughput during the three years ended December 31, 2019,2020, and the daily rated capacities of the refineries as at December 31, 2019,2020, were as follows.
| Refinery throughput (a) | Rated capacities (b) | |||||||||||||||
| Year ended December 31 | at December 31 | |||||||||||||||
| thousands of barrels per day | 2019 | 2018 | 2017 | 2019 | ||||||||||||
Strathcona, Alberta | 183 | 173 | 185 | 191 | ||||||||||||
Sarnia, Ontario | 86 | 109 | 103 | 119 | ||||||||||||
Nanticoke, Ontario | 84 | 110 | 95 | 113 | ||||||||||||
Total | 353 | 392 | 383 | 423 | ||||||||||||
| Refinery throughput (a) | Rated capacities (b) | |||||||||||||||
| Year ended December 31 | at December 31 | |||||||||||||||
| thousands of barrels per day | 2020 | 2019 | 2018 | 2020 | ||||||||||||
Strathcona, Alberta | 170 | 183 | 173 | 196 | ||||||||||||
Sarnia, Ontario | 86 | 86 | 109 | 119 | ||||||||||||
Nanticoke, Ontario | 84 | 84 | 110 | 113 | ||||||||||||
Total | 340 | 353 | 392 | 428 | ||||||||||||
| (a) | Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units. |
| (b) | 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 averaged 340,000 barrels per day in 2020, compared to 353,000 barrels per day in 2019. Capacity utilization was 80 percent, compared to 83 percent in 2019. Lower throughput was driven by reduced demand due to the
COVID-19
pandemic, partially offset by lower refinery turnaround activity and reliability events, including impacts from the Sarnia fractionation tower incident which occurred in April 2019.Refinery throughput averaged 353,000 barrels per day in 2019, compared to 392,000 barrels per day in 2018. Capacity utilization was 83 percent, compared to 93 percent in 2018. Reduced throughput was mainly due to higher planned turnaround activities and impacts from the Sarnia fractionation tower incident which occurred in April 2019.
The company maintains a nationwide distribution system, to move petroleum products to market by pipeline, tanker, rail and road transport. The company owns and operates fuel terminals across the country, as well as natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of one crude oil and two products pipeline companies.
Marketing
The company markets petroleum products throughout Canada under well-known brand names, most notably Esso and Mobil, to all types of customers.
Imperial supplies petroleum products to the motoring public through Esso and Mobil-branded sites and independent marketers. At the end of 2019,2020, there were about 2,3002,400 sites operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate sites in alignment with Esso and Mobil brand standards.
Imperial also sells petroleum products, including fuel, asphalt and lubricants, to large industrial and transportation customers, independent marketers, resellers, as well as other refiners. The company serves agriculture, residential heating and commercial markets through branded fuel and lubricant resellers.
The approximate daily volumes of net petroleum products (excluding purchases / sales contracts with the same counterparty) sold during the three years ended December 31, 2019,2020, are set out in the following table.
| thousands of barrels per day | 2019 | 2018 | 2017 | 2020 | 2019 | 2018 | ||||||||||||||||||
Gasolines | 249 | 255 | 257 | 215 | 249 | 255 | ||||||||||||||||||
Heating, diesel and jet fuels | 167 | 183 | 177 | 146 | 167 | 183 | ||||||||||||||||||
Heavy fuel oils | 21 | 26 | 18 | 20 | 21 | 26 | ||||||||||||||||||
Lube oils and other products | 38 | 40 | 40 | 40 | 38 | 40 | ||||||||||||||||||
Net petroleum product sales | 475 | 504 | 492 | 421 | 475 | 504 | ||||||||||||||||||
In 2020, lower sales were primarily driven by reduced demand due to the
COVID-19
pandemic.In 2019, lower sales volumes were mainly due to lower refinery throughput.
The company’s Chemical operations manufacture and market benzene, aromatic and aliphatic solvents, plasticizer intermediates and polyethylene resin. Its petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the company’s petroleum refinery.
The company’s total petrochemical sales volumes during the three years ended December 31, 2019,2020, were as follows.
| thousands of tonnes | 2019 | 2018 | 2017 | 2020 | 2019 | 2018 | ||||||||||||||||||
Total petrochemical sales | 732 | 807 | 774 | 749 | 732 | 807 | ||||||||||||||||||
In 2020, sales volumes increased primarily due to higher sales of intermediates.
In 2019, sales volumes decreased primarily due to lower aromatics and intermediates sales.
18
Human capital resources
Imperial operates in a complex, competitive and changing business environment where decisions and risks play out over time horizons that are often decades in length. This long-term orientation underpins the company’s philosophy on talent development.
Talent development begins with recruiting exceptional candidates and continues with individually planned experiences and training designed to facilitate broad development and a deep understanding of our business across the business cycle. The company’s compensation is market competitive, long-term oriented, and highly differentiated by individual performance. In addition, benefits and workplace programs support the company’s talent management approach, and are designed to attract and retain employees for a long-term career. Overall, this multifaceted approach has resulted in strong employee retention.
Imperial views diversity as an opportunity. The company encourages and respects diversity of thought, ideas, and perspective in its workforce. The company considers diversity though all stages of employment including recruitment, training and development of its employees. Imperial’s goal is to reflect the mix and diversity of the communities where it operates, and it continues to focus on diverse representation at all levels of the organization.
The company regards protectingnumber of regular employees was about 5,800 at the environment in connection with its various operationsend of 2020 (2019 - 6,000, 2018 - 5,700). Regular employees are defined as a priority. The company works in cooperation with government agencies, industry associationsexecutive, management, professional, technical and communities to address existing, and to anticipate potential, environmental protection issues. In the past five years,wage employees who work full-time or part-time for the company has made capital and operating expenditures of about $3.9 billion on environmental protection and facilities. In 2019,are covered by the company’s environmental capitalbenefit plans and operating expenditures totalled approximately $0.8 billion, which was spent primarily on activities to protect the air, land and water, including remediation projects. Capital and operating expenditures relating to environmental protection are expected to be about $1.0 billion in 2020.programs.
| career employees (a) | 2019 | 2018 | 2017 | |||||||||
Total | 6,000 | 5,700 | 5,400 | |||||||||
The Canadian energy and petrochemical 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 energy and petrochemical industries also compete with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers.
Government regulationregulations
Petroleum, natural gas and oil sands rights
Most of the company’s petroleum, natural gas and oil sands rights were acquired from governments, either federal or provincial. These rights, in the form of leases or licences, are generally acquired for cash or work commitments. A lease or licence entitles the holder to explore for petroleum, natural gas and/and / or oil sands on the leased lands for a specified period.
In western provinces, the lease holder can produce the petroleum or natural gas discovered on the leased lands and retains the rights based on continued production. Oil sands leases are retained by meeting the minimum level of evaluation, payment of rentals, or by production.
The holder of a licence relating to Canada lands and the Atlantic offshore can apply for a SDL if a discovery is made. If granted, the SDL holds the lands indefinitely subject to certain conditions. The holder may then apply for a production licence in order to produce petroleum or natural gas from the licenced land.
Project approval
Approvals and licences from relevant provincial or federal
governmental or regulatory bodies are required for the company to carry out, or make modifications to, its oil and gas activities. The project approval process for major projects can involve, among other things, environmental assessments (including relevant mitigation measures), stakeholder and Indigenous consultation and input regarding project concerns, and public hearings. Approval may be subject to various conditions and commitments arising through these processes.
In 2019, the Canadian government implemented a new environmental assessment framework in Canada under the, which may impact the manner in which large energy projects are approved. Changes from the previous environmental assessment legislation include broader consideration for social, health, and gender-based impacts, the impact on Canada’s climate change commitments, reliance on strategic and regional assessments and adjusted regulatory review timelines.
Impact Assessment Act
Environmental protection
The company regards protecting the environment in connection with its various operations as a priority. The company is subject to extensive environmental regulations in Canada that apply to all phases of exploration, development, operation, and final closure. These requirements cover the management and monitoring of potential environmental impacts during active operations, including practices for land disturbance, wildlife protection, specifications for equipment operation and material storage and limitations on discharges to the environment. It also includes conducting environmental surveys and collecting continuous operational measurements and sampling to confirm that environmental practices are adequately protecting the environment. These regulations also specify the actions and requirements for final reclamation, abandonment and closure of facilities. The company works in cooperation with government agencies, industry associations and communities to address existing, and to anticipate potential, environmental protection issues. The company also maintains extensive operating procedures, processes and emergency response plans to address environmental risks at its operations.
As discussed in Item 1A. Risk factors in this report, compliance with existing and potential future government regulations, including environmental regulations, may have material effects on the capital expenditures, earnings, and competitive position of the company. Imperial takes new and ongoing measures throughout its operations each year to prevent and minimize the impact of its operations on air, land and water. These include significant investments in refining infrastructure and technology to manufacture clean fuels, continued evaluation and implementation of new technologies to reduce greenhouse gas emissions, adherence to federal and provincial greenhouse gas emissions reduction and reporting programs, enhanced water and land management, and expenditures for asset retirement obligations. In the past five years, the company has made capital and operating expenditures of about $3.3 billion on environmental protection and facilities. In 2020, the company’s environmental capital and operating expenditures totalled approximately $0.6 billion, which was spent primarily on activities to protect the air, land and water, including remediation projects. Capital and operating expenditures relating to environmental protection are expected to be about $1.1 billion in 2021.
20
Crude oil
Production
The maximum allowable gross production of crude oil from wells in Canada is subject to limitations by various regulatory authorities on the basis of engineering and conservation principles.
Additionally, in December 2018, the Government of Alberta introduced temporary mandatory production curtailment regulations, which took effect on January 1, 2019. These regulations enable the government to impose production limits on large producers in Alberta. Mandatory production curtailments decreased as 2019 progressed,were eliminated effective December 2020, but continuethe regulatory authority to be imposed on larger producers.impose curtailments remains in place. The duration of these regulations is uncertain.
Exports
Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require the prior approval of the Canada Energy Regulator (CER) and the Government of Canada. Export contracts of less than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require an order from the CER.
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 Imperial’s 20192020 gas production rates.
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.
gas. Exports of natural gas from Canada require approval by the CER and the Government of Canada. The Government of Canada allows the export of natural gas by CER 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 on crude oil, natural gas and natural gas liquids vary depending on a number of parameters, including well production volumes, selling prices and recovery methods. For information with respect to royalties for Kearl, Cold Lake and Syncrude, see “Upstream” section entitled “Present activities” under Item 1 on page 11.13.
21
Investment Canada Act
TheTherequires 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 a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval.
Investment Canada Act
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. The Government of Canada is also authorized to take any measures that it considers advisable to protect national security, including the outright prohibition of a foreign investment in Canada.
By virtue of the majority stock ownership of the company by ExxonMobil, the company is considered to be an entity which is not controlled by Canadians.
Competition Act
The Competition Bureau ensuresseeks to ensure that Canadian businesses and consumers prosper in a competitive and innovative marketplace. The Competition Bureau is responsible for the administration and enforcement of the(the Act). A merger transaction, whether or not notifiable, is subject to examination by the Commissioner of the Competition Bureau to determine whether the merger will have, or is likely to have, the effect of preventing or lessening substantially competition in a definable market. The assessment of the competitive effects of a merger is made with reference to the factors identified under the Act.
Competition Act
An Advance Ruling Certificate (ARC) may be issued by the Commissioner to a party or parties to a proposed merger transaction who want to be assured that the transaction will not give rise to proceedings under section 92 of the Act. Section 102 of the Act provides that an ARC may be issued when the Commissioner is satisfied that there would not be sufficient grounds on which to apply to the Competition Tribunal for an order against a proposed merger. The issuance of an ARC is discretionary. An ARC cannot be issued for a transaction that has been completed, nor does an ARC ensure approval of the transaction by any agency other than the Competition Bureau.
The company’s websitecontains a variety of corporate and investor information, which is available free of charge, including the company’s annual report on Form
www.imperialoil.ca
10-K,
quarterly reports on Form10-Q
and current reports on Form8-K
and amendments to these reports. These reports are made available as soon as reasonably practicable after they are filed or furnished to the SEC. The SEC’s website, www.sec.gov, contains reports, proxy and information statements, interactive data files, and other information regarding issuers that are submitted and posted electronically with the SEC.Item 1A. | Risk factors |
Imperial’s financial and operating results are subject to a variety of risks inherent in oil, gas and petrochemical businesses. Many of these risk factors are not within Imperial’s control and could adversely affect Imperial’s business, financial and operating results, or financial position. These risk factors include:
Supply and demand
The oil, gas, fuels and petrochemical businesses are fundamentally commodity businesses. This means the company’s operations and earnings may be significantly affected by changes in oil, natural gas and petrochemical prices, and by changes in margins on refined products and petrochemicals. Crude oil, natural gas, petrochemical and petroleum product prices and margins depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity. Commodity prices have been volatile, and the company expects that volatility to continue. Any material decline in crude oil prices could have a material adverse effect on Imperial’s Upstream operations, financial position, proved reserves and the amount spent to develop reserves. On the other hand, a material increase in crude oil prices could have a material adverse effect on Imperial’s Downstream margins, depending on the market conditions for refined products.
The demand for energy and petrochemicals is generally linked closely with broad-based economic activities and levels of prosperity. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on the company’s results. Other factors that may affect the demand for crude oil, gas, fuels and petrochemicals, and therefore could impact Imperial’s results include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for our products, including lower demand for gasoline, impacting Downstream results in the winter; increased competitiveness of, or government policy support for, alternative energy sources; new product quality regulations; technological changes or consumer preferences that alter fuel choices, such as technological advances in energy storage that make wind and solar more competitive for power generation or increasedgeneration; changes in consumer preferences for the company’s products, including consumer demand for alternative fueled or electric transportation;transportation or alternatives to plastic products; broad-based changes in personal income levels; and security or public health concerns.issues and responses such as epidemics and pandemics.
Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity relative to demand tend to reduce margins on affected products. Crude oil, gas and petrochemical supply levels can also be affected by factors that reduce available supplies, such as adherence by member countries or others to Organization of the Petroleum Exporting Countries (OPEC) production quotas, government policies that restrict oil and gas production or increase associated costs, including the Government of Alberta curtailment regulations, the occurrence of wars, hostile actions, natural disasters, disruptions in competitors’ operations, or unexpected pipeline or rail constraints that may disrupt supplies. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.
The market price for western Canadian heavy crude oil is typically lower than light and medium grades of oil, principally due to the higher transportation and refining costs. Western Canadian crude oil may also be subject to limits on transportation capacity to markets. Future crude price differentials between western Canadian crude oil relative to prices in the U.S. Gulf Coast are uncertain and changes in the heavy or light crude oil differentials could have a material adverse effect on the company’s business. Increased differentials in 2018 also led the Government of Alberta to imposeenact temporary mandatory production curtailment regulations in 2019. These regulations enable the government to impose production limits on large producers in Alberta such as Imperial. Although mandatory production curtailment decreased throughout 2019 it continuesand 2020, and was eliminated in December 2020, the regulatory authority to be imposed on larger producersimpose curtailments remains in place and there is the potential for curtailment to beuncertain.uncertain, and could have an adverse effect on the company’s business. A significant portion of the company’s production is bitumen, which is blended with diluent for transportation and marketability of heavy crude oil. Increases to diluent prices, relative to heavy crude oil prices, could also have an adverse effect on the company’s business.
re-imposed
and increased. The duration of these regulations is Government and political factors
Imperial’s results can be adversely impacted by political, legal or regulatory developments affecting operations and markets. Changes in government policy or regulations, changes in law or interpretation of settled law, third partythird-party opposition to company or infrastructure projects, and duration of regulatory reviews could impact Imperial’s existing operations and planned projects. This includes actions by regulators or other political actors to delay or deny necessary licenses and permits or restrict the operation of third-party infrastructure that the company relies on, such as pipelines to transport the company’s upstream production to market or that supply feedstock to the company’s refineries. Additionally, changes in environmental regulations, assessment processes or other laws and increasing and expanding stakeholder consultation (including Indigenous stakeholders), may increase the cost of compliance or reduce or delay available business opportunities and adversely impact the company’s results.
Other government and political factors that could adversely affect the company’s financial results include increases in taxes or government royalty rates (including retroactive claims) and changes in trade policies and agreements. Further, the adoption of regulations mandating efficiency standards, and the use of alternative fuels or uncompetitive fuel components could affect the company’s operations. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies. Governments and others are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources, and the success of these initiatives may decrease demand for the company’s products.
Governments may establish regulations with respect to the control of the company’s production, such as when increased price differentials in 2018 led the Government of Alberta to impose temporary mandatory production curtailment regulations effective 2019. Although mandatory production curtailment decreased throughout 2019, it continues to be imposed on larger producers. The duration of these regulations is uncertain,as discussed in the Supply and could have an adverse effect on the company’s business.demand section above. Government intervention in free markets may introduce unintended consequences such as market volatility and uncertainty, misallocation of resources, and erosion of investor confidence.
Environmental risks
All phases of the Upstream, Downstream and Chemical businesses are subject to environmental regulation pursuant to a variety of Canadian federal, provincial, territorial 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 into the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Changes to these requirements such as the International Maritime Organization (IMO) 2020 global Sulphur limits for marine fuel oil, could adversely affect the company’s results by impacting commodity prices, increasing costs and reducing revenues.
Environmental legislation also requires that wells, facility sites and other properties associated with the company’s operations be operated, maintained, monitored, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. This includes the requirement for specific approvals for many areas of interaction with the environment, such as land use, air quality, water use, biodiversity protection and waste, including mine tailings management. The failure to operate as anticipated and adhere to conditions, the delay or denial of approvals and changes to conditions or regulations could impact the company’s ability to operate its projects and facilities and adversely affect the company’s results.
24
The implementation of, and compliance with, policies and regulations related to air, water and land, such as Alberta’s Lower Athabasca Regional Plan and Wetland Policy applicable to the company’s oil sands assets, could restrict development in current and future areas of operation. The company also depends on water obtained under licences for withdrawal, storage, reuse and discharge in both its Upstream and Downstream businesses, including future projects and expansions. Water use may be limited by regulatory requirements, seasonal fluctuations, competing demands, environmental sensitivities, increasingly stringent water management standards, and changes to conditions or availability of licences, which may restrict and adversely affect the company’s operations. Additionally, a number of air quality regulations and frameworks are being developed at the federal and provincial levels, and when implemented could impact existing and planned projects through increased capital and operating expenses including retrofits to existing equipment, and could adversely impact the company’s operations and financial results.
Federal and provincial legislation aimed at protecting sensitive, threatened or endangered wildlife, such as woodland caribou and species of migratory birds, may also increase restoration and offset costs and impact the company’s projects. If it is determined that such wildlife and their habitat are not sufficiently protected, governments or other parties may take actions to limit the pace or ability to develop in areas of Imperial’s current and future projects.
The company’s mining operations are subject to tailings management regulations that establish approval, monitoring, reporting and performance criteria for tailings ponds and management plans. Further, the absence or evolving nature of policies and regulations for the timing and closure of tailings ponds, including the approved technologies and methods for closure (such as the use of end pit lakes and water capped tailings), and dam safety directives, regulations, guides and abandonment requirements could have a material impact on conditions for approvals and ultimate mine closure costs. Additionally, successful management and closure requires the release of water to the environment, and although an Alberta water release policy and federal oil sands effluent regulations are being developed, the timing and impact of these regulations is uncertain and the absence of effective regulation could negatively impact the company’s operations and financial results.
In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. In 2019, the Government of Canada implemented a new environmental assessment framework under the, which expands assessment considerations beyond the environment to include social, health, economic, and gender-based impacts and the impact on Canada’s climate change commitments. It also includes a reliance on strategic and regional assessments and adjusted regulatory review timelines. The impact of this legislation is not yet known,fully apparent, but it may impact the cost, manner, duration and ability to advance large energy projects.
Impact Assessment Act
Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the cessation of operations, imposition of fines and penalties and liability for
clean-up
costs and damages.The costs of complying with environmental legislation in the future could have a material adverse effect on the company’s financial condition or results of operations. The company anticipates that changes in environmental legislation may require, among other things, reductions in emissions from its operations to the air and water and may result in increased capital expenditures. Changes in environmental legislation (including, but not limited to, application of regulations related to air, water, land, biodiversity and waste, including mine tailings) may increase the cost of compliance or reduce or delay available business opportunities. 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.
There are operational risks inherent in oil and gas exploration and production activities, as well as the potential to incur substantial financial liabilities, if the company does not manage those risks are not effectively managed.effectively. The ability to insure such risks is limited by the capacity of the applicable insurance markets, which may not be sufficient to cover the likely cost of a major adverse operating event. Accordingly, the company’s primary focus is on prevention, including through its rigorous operations integrity management system. The company’s future results will depend on the continued effectiveness of these efforts.
25
Climate change and greenhouse gas restrictions
The Government of Canada has adopted the Paris Agreement on climate change, and set a goal to reduce greenhouse gas emissions economy-wide by 30 percent below 2005 levels by 2030. To implement these goals, the Government of Canada adopted the(GGPPA), which sets a federal backstop carbon price Canada-wide through a carbon levy applied to fossil fuels ($20 per tonne starting in 2019 and increasing by $10 per tonne annually to $50 per tonne in 2022), and an output-based pricing system for large industrial emitters. Under the GGPPA, provinces are required to either adopt the GGPPA, or obtain equivalency by adopting a price-based system or cap and trade system. In December 2020, the Government of Canada proposed to increase the carbon price by $15 per year starting in 2023, rising to $170 per tonne in 2030. Further, in 2020 the Government of Canada proposed legislation to formalize Canada’s target to achieve
Greenhouse Gas Pollution Pricing Act
net-zero
emissions by 2050 and establish interim emissions reductions targets at five year intervals.The Government of Alberta has obtained federal equivalency for its Technology Innovation and Emissions Reduction Regulation (TIER) that came into effect in 2020 and applies to facilities with CO2 emissions in excess of 100,000 tonnes per year. TIER is designed to reduce emissions by putting a price on 10 percent of a facility’s emissions in 2020, increasing by 1 percent per year, with pricing for 2020 set at $30 per tonne. Further, the Albertasets a limit of 100 megatonnes of CO2 per year of emissions in the oil sands sector, but oil sands emissions remain below the limit and it is not yet possible to predict the impact of this act on the company’s future oil sands operations in Alberta. With respect to other provinces, with Ontario cancelling the cap and trade program in 2018, the company’s operations in Ontario are subject to the federal carbon levy and output based pricing system. British Columbia has carbon pricing in place for all emissions, with pricing currently at $40 per tonne and rising by $5 per tonne in April, 2020 and again2021. Increases in April, 2021. Although current regulations around carbon emissions pricing are not anticipated to have a materialcould adversely impact on the company’s operations inand financial results unless the near term, uncertainty regarding future regulations make it difficult to predict potential future impact on the company.
company can adapt its operations.Oil Sands Emissions Limit Act
There are also various low carbon fuel standards being developed or applicable to the company.company’s products. The Government of Canada is progressing draft regulations for the Clean Fuel Standard, which if implemented wouldwill require the reduction in carbon intensity of liquid fuels supplied in Canada starting in 2022 and gaseous and solid fuels starting in 2023.2022. The standard is expected to build upon the existing federal renewable fuels regulations that require fuel producers and importers to have a specified amount of renewable fuel in gasoline and diesel. Similarly, British Columbia introduced a Low Carbon Fuel Standard in 2013, which increased to a 10 percent carbon intensity reduction requirement by 2020. The British Columbia government has announced a draft policy to reduce the carbon intensity of fuels by a further 20 percent by 2030. Compliance can be achieved by either blending renewable fuels with low carbon intensity or by purchasing credits. Changes to these standards could adversely impact the company’s operations and financial results.
Impact Assessment Act
International accords and underlying regional and national regulations covering climate change and greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. Such laws and policies could make Imperial’s products more expensive and less competitive, reduce or delay available business opportunities, reduce demand for hydrocarbons, and shift hydrocarbon demand toward lower greenhouse gas emission energy sources. Current and pending greenhouse gas regulations or policies may also increase compliance and abatement costs including taxes and levies, increase abandonment and reclamation obligations, lengthen project evaluation and implementation times, impact reserves evaluations and affect operations. Increased costs may not be recoverable in the market place, could negatively affect our returns and could reduce the global competitiveness of the company’s crude oil, natural gas and refined products. Governments may also impose restrictions on production of oil and gas to the extent they view such measures as a viable approach for pursuing national and global energy and climate policies. Concern over the risks of climate change may lead governments to make laws applicable to the energy industry progressively more stringent over time.
26
Political and other actors and their agents are also increasingly seeking to advance climate change objectives indirectly, such as by seeking to reduce the availability of or increase the cost for financing and investment in the oil and gas sector and taking actions intended to promote changes in business strategy for oil and gas companies.
Currency
Prices for commodities produced by the company are commonly benchmarked in U.S. dollars. The majority of Imperial’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the value of the Canadian dollar strengthens, the company’s reported earnings will be negatively affected. The company does not currently make use of derivative instruments to offset exposures associated with foreign currency.
Other business risks
Imperial is reliant on a number of key chemicals, catalysts and third partythird-party service providers, including input and output commodity transportation (pipelines, rail, trucking, marine) and utilities providing services, including electricity and water, to various company operations. The lack of availability, and capacity andor proximity ofwith respect to pipeline facilities and railcars could negatively impact Imperial’s ability to produce at capacity levels. Transportation disruptions, including those caused by events unrelated to the company’s operations, could adversely affect the company’s price realizations, refining operations and sales volumes,volumes. This includes outages of key third-party infrastructure, such as well as potentiallypipelines servicing the company’s oil sands assets or pipelines supplying feedstock to its refineries, which could impact the company’s ability to operate its assets or limit the ability to deliver production and products to market. A third partythird-party utilities outage could have an adverse impact on the company’s operations and ability to produce.
The company also enters into contractual relationships with suppliers, partners and other counterparties to procure and sell goods and services, and the company’s operations, market position and financial condition may be adversely impacted if these counterparties do not fulfil their obligations. Imperial may also be adversely affected by the outcome of litigation resulting from its operations or by government enforcement proceedings alleging
non-compliance
with applicable laws or regulations. Litigation is subject to uncertainty and success is not guaranteed, and the company may incur significant expenses and devote significant resources in defending litigation.Management effectiveness
In addition to external economic and political factors, Imperial’s future business results also depend on the company’s ability to manage successfully those factors that are at least in part within its control. The extent to which Imperial manages these factors will impact its performance relative to competition. For projects in which the company is not the operator, Imperial depends on the management effectiveness of one or more
co-venturers
whom the company does not control.Project management
The nature of the company’s Upstream, Downstream and Chemical businesses depend on complex, long-term, and capital intensive projects that require a high degree of project management expertise to maximize efficiency. This includes development, engineering, construction, commissioning and ongoing operational activities and expertise. The company’s results are affected by its ability to develop and operate projects and facilities as planned and 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 regulations; the ability to model and optimize reservoir performance; 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 company’s ability to respond effectively to unforeseen technical difficulties that could delay project startup
start-up
or cause unscheduled downtime.27
Operational efficiency
An important component of Imperial’s competitive performance, especially given the commodity based nature of Imperial’s business, is the ability to operate efficiently, including the company’s ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technological improvements, cost control, productivity enhancements and regular reappraisal of the company’s asset portfolio. The company’s operations and results also depend on key personnel and subject matter expertise, the recruitment, development and retention of high caliber employees, and the availability of skilled labour.
Research and development and technical change
Imperial relies upon the research and development organizations of the company and ExxonMobil, with whom the company conducts shared research. Innovation and technology are important to maintain the company’s competitive position, especially in light of the technological nature of Imperial’s business and the need for continuous efficiency improvement. The company’s research and development organizations must be able to adapt to a changing market and policy environment, including developing technologies to help reduce greenhouse gas emissions intensity. To remain competitive, the company must also continuously adapt and capture the benefits of new technologies including growing the company’s capabilities to utilize digital data technologies to gain new business insights. There are risks associated with projects that rely on new technology, including that the results of implementing the new technology may differ from simulated, piloted or expected results. The failure to develop and adopt new technology may have an adverse impact on the company’s operations, ability to meet regulatory requirements and operational commitments and targets (including environmental sustainability and reduction of greenhouse gas emissions), and financial results.
Safety, business controls and environmental risk management
The scope and nature of the company’s operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, pipeline ruptures and crude oil spills. Imperial’s operations are also subject to the additional hazards of pollution, releases of toxic gas and environmental hazards and risks, such as severe weather, and geological events. The company’s results depend on management’s ability to minimize these inherent risks, to effectively control business activities and to minimize the potential for human error. Imperial applies rigorous management systems, including a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. The company also maintains a disciplined framework of internal controls and applies a controls management system for monitoring compliance with this framework. The company’s upstream and downstream operations may experience loss of production, slowdowns or shutdowns and increased costs due to the failure of interdependent systems, and substantial liabilities and other adverse impacts could result if the company’s management systems and controls do not function as intended.
Cybersecurity
Imperial is regularly subject to attempted cybersecurity disruptions from a variety of threat actors, including state-sponsored actors. Imperial’s defensive preparedness includes multi-layered technological capabilities for prevention and detection of cybersecurity disruptions;
non-technological
measures such as threat information sharing with governmental and industry groups; internal training and awareness campaigns including routine testing of employee awareness via mock threats; and an emphasis on resiliency including business response and recovery.If the measures the company is taking to protect against cybersecurity disruptions prove to be insufficient or if the company’s proprietary data is otherwise not protected, the company as well as its customers, employees or third parties could be adversely affected. Cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost or stolen; result in employee, customer or third partythird-party information being compromised; or otherwise disrupt the company’s business operations. Imperial could incur significant costs to remedy the effects of a major cybersecurity disruption, in addition to costs in connection with resulting regulatory actions, litigation or reputational harm.
28
Preparedness
The company’s operations may be disrupted by severe weather events, natural disasters, human error, and similar events. Imperial’s ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of its rigorous disaster preparedness and response planning, as well as business continuity planning.
COVID-19
As a result oforders and travel restrictions that have had a significant impact on demand for the company’s products. While these effects are expected to be temporary, the resurgence of cases of
COVID-19,
governments in many countries, including Canada, have mandated quarantines, closures,stay-at-home
COVID-19
has led to a highly uncertain business environment. Although there has been some movement towardpre-pandemic
activity levels, the duration of the business disruptions internationally and related financial impact cannot be reasonably estimated at this time and continued or new restrictions could continue to impact the demand for petroleum products.Imperial’s future business results, including cash flows and financing needs, will be affected by the extent and duration of these conditions and the effectiveness of responsive actions that the company and others take, including our actions to reduce capital and operating expenses and government actions to address the
COVID-19
pandemic. The impact ofCOVID-19
could also have an effect on the financial markets and result in an increase to the cost of capital due to risk. The company’s results will also be affected by any resulting negative impacts on national and global economies and markets from a prolonged decrease of economic activity.The company has had positive
COVID-19
cases, but these cases have not had a material impact on its operations or business. The company has initiated numerous emergency response and business continuity plans, and a substantial portion of the company’s workforce has implemented remote working arrangements. However, if the company’s mitigation and response efforts prove insufficient, then large outbreaks of epidemics, pandemics or other health crises such asCOVID-19
at operating sites, particularly in remote locations and where work camps are utilized, could materially impact the company’s personnel and its operations, reducing productivity and increasing costs.The company could also be impacted by disruption to supply chains, methods of distribution and key third-party service providers, which could impact the ability to produce or sell its products, as well as increase the costs associated with its operations and decrease revenues and margins.
The
COVID-19
pandemic continues to evolve, with changing case numbers and the potential for additional public health restrictions. Although vaccines are being developed and approved for use, their availability and effectiveness is uncertain, especially in light of the emergence of new mutations of the virus. The impact of the pandemic remains difficult to predict.Reputation
Imperial’s reputation is an important corporate asset. An operating incident, significant cybersecurity disruption, change in consumer views concerning the company’s products, or other adverse events, such as those described in Item 1A, may have a negative impact on Imperial’s reputation, which in turn could make it more difficult for the company to compete successfully for new opportunities or obtain necessary regulatory approvals, or could reduce consumer demand for the company’s branded products. Imperial’s reputation may also be harmed by events which negatively affect the image of the industry as a whole, including public and investor perception of Alberta oil sands in relation to greenhouse gas emissions and environmental impact.
Reserves
The company’s future production and cash flows from bitumen, synthetic oil, liquids and natural gas reserves are highly dependent upon the company’s success in exploiting its current reserves. To maintain production and cash flows, the company must continue to replace produced reserves as they are depleted, which can be accomplished through exploration discovery of new resources, appraisal and investments in developing discovered resources, or acquisition of reserves. 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 grow oil and natural gas reserves will be adversely impacted. 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.
Estimates of economically recoverable oil and natural gas reserves and future net cash flows involve many uncertainties, including factors beyond the company’s control. Key factors with uncertainty include: geological and engineering estimates, including that additional information obtained through seismic and drilling programs, reservoir analysis and production and operational history may result in revisions to reserves; the assumed effects of regulation or changes to regulation by government agencies, including royalty frameworks and environmental regulations (such as the regulation of greenhouse gas emissions, which could impose significant compliance costs on the company, require new technology, or impact the economic viability of certain projects); future commodity prices, where low commodity prices may affect reserves development; abandonment and reclamation costs, including reclamation and tailings requirements for mining operations; and operating costs. Actual production, revenues, taxes and royalties, development costs, abandonment and reclamation costs, and operating expenditures with respect to reserves will likely vary from such estimates, and such variances could be material.
Unresolved staff comments |
None.
Legal proceedings |
Imperial has elected to use a $1 million threshold for disclosing environmental proceedings.
30
Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities |
Market information
The company’s common shares are listed and trade on the Toronto Stock Exchange in Canada, and have unlisted trading privileges and trade on the NYSE American LLC in the United States. The symbol for the company’s common shares on these exchanges is IMO.
As of February 12, 202016, 2021 there were 10,22110,094 holders of record of common shares of the company.
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
non-resident
withholding tax of 15 percent, but may vary from one tax convention to another.The withholding tax is reduced to 5 percent on dividends paid to a corporation resident in the U.S. that owns at least 10 percent of the voting shares of the company.
The company is a qualified foreign corporation for purposes of the reduced U.S. capital gains tax rates, 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
non-residents
not carrying on business in Canada, as long as the shareholder does not, in any given 60 month period, own 25 percent or more of the shares of the company.Canada has approved several positions with respect to the, which may impact the taxability of dividends and capital gains in Canada if the shareholder’s country of residence has also approved these same positions of the MLI.
Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting (“MLI”)
Between October 1, 20192020 and December 31, 2019,2020, pursuant to the company’s restricted stock unit plan, 6506,975 shares were issued to employees or former employees outside the U.S. in reliance on Regulation S under the Securities Act.
Securities authorized for issuance under equity compensation plans
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101.113. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the section under the “Company executives and executive compensation”:
Entitled “Performance graph” within the “Compensation discussion and analysis” section on page |
Entitled “Equity compensation plan information”, within the “Compensation discussion and analysis”, on page |
Issuer purchases of equity securities
Total number of shares purchased | Average price paid per share (Canadian dollars) | Total number of shares purchased as part of publicly announced plans or programs | Maximum number of shares that may yet be purchased under the plans or programs (a) | |||||||||||
October 2019 | ||||||||||||||
| (October 1 - October 31) | 3,431,196 | 32.81 | 3,431,196 | 24,954,195 | ||||||||||
November 2019 | ||||||||||||||
| (November 1 - November 30) | 3,275,232 | 33.89 | 3,275,232 | 21,678,963 | ||||||||||
December 2019 | ||||||||||||||
| (December 1 - December 31) | 2,340,102 | 33.25 | 2,340,102 | 19,338,861 (b) | ||||||||||
| Total number of shares purchased | Average price paid per share (Canadian dollars) | Total number of shares purchased as part of publicly announced plans or programs | Maximum number of shares that may yet be purchased under the plans or programs (a) | |||||||||||||
October 2020 | ||||||||||||||||
(October 1 - October 31) | - | - | - | 50,000 | ||||||||||||
November 2020 | ||||||||||||||||
(November 1 - November 30) | - | - | - | 50,000 | ||||||||||||
December 2020 | ||||||||||||||||
(December 1 - December 31) | 6,975 | 24.34 | 6,975 | 43,025 | ||||||||||||
| (a) | On June |
The company will continue to evaluate its share purchase program in the context of its overall capital activities.
Selected financial data |
| millions of Canadian dollars | 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||
Revenues | 22,284 | 34,002 | 34,964 | 29,125 | 25,049 | |||||||||||||||
Net income (loss) | (1,857 | ) | 2,200 | 2,314 | 490 | 2,165 | ||||||||||||||
Total assets at year-end | 38,031 | 42,187 | 41,456 | 41,601 | 41,654 | |||||||||||||||
Long-term debt at year-end | 4,957 | 4,961 | 4,978 | 5,005 | 5,032 | |||||||||||||||
Total debt at year-end | 5,184 | 5,190 | 5,180 | 5,207 | 5,234 | |||||||||||||||
Other long-term obligations at year-end | 4,100 | 3,637 | 2,943 | 3,780 | 3,656 | |||||||||||||||
Canadian dollars | ||||||||||||||||||||
Net income (loss) per common share - basic | (2.53 | ) | 2.88 | 2.87 | 0.58 | 2.55 | ||||||||||||||
Net income (loss) per common share - diluted | (2.53 | ) | 2.88 | 2.86 | 0.58 | 2.55 | ||||||||||||||
Dividends per common share - declared | 0.88 | 0.85 | 0.73 | 0.63 | 0.59 | |||||||||||||||
| millions of Canadian dollars | 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||
| Revenues | 34,002 | 34,964 | 29,125 | 25,049 | 26,756 | |||||||||||||||
| Net income (loss) | 2,200 | 2,314 | 490 | 2,165 | 1,122 | |||||||||||||||
Total assets at year-end | 42,187 | 41,456 | 41,601 | 41,654 | 43,170 | |||||||||||||||
Long-term debt at year-end | 4,961 | 4,978 | 5,005 | 5,032 | 6,564 | |||||||||||||||
Total debt at year-end | 5,190 | 5,180 | 5,207 | 5,234 | 8,516 | |||||||||||||||
Other long-term obligations at year-end | 3,637 | 2,943 | 3,780 | 3,656 | 3,597 | |||||||||||||||
| Canadian dollars | ||||||||||||||||||||
| Net income (loss) per common share - basic | 2.88 | 2.87 | 0.58 | 2.55 | 1.32 | |||||||||||||||
| Net income (loss) per common share - diluted | 2.88 | 2.86 | 0.58 | 2.55 | 1.32 | |||||||||||||||
| Dividends per common share - declared | 0.85 | 0.73 | 0.63 | 0.59 | 0.54 | |||||||||||||||
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.
Management’s discussion and analysis of financial condition and results of operations |
Reference is made to the section entitled “Management’s discussion and analysis of financial condition and results of operations” in the “Financial section”, starting on page 4045 of this report.
Quantitative and qualitative disclosures about market risk |
Reference is made to the section entitled “Market risks and other uncertainties” in the “Financial section”, starting on page 5461 of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.
32
Financial statements and supplementary data |
Reference is made to the table of contents in the “Financial section” on page 3641 of this report:
| ● | Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP (PwC) dated February |
| ● | “Supplemental information on oil and gas exploration and production activities” (unaudited) starting on page |
| ● | “Quarterly financial data” on page |
Changes in and disagreements with accountants on accounting and financial disclosure |
None.
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, 2019.2020. 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 SEC’s rules and forms.
Reference is made to page 6169 of this report for “Management’s report on internal control over financial reporting” and page 6270 for the “Report of independent registered public accounting firm” on the company’s internal control over financial reporting as of December 31, 2019.2020.
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.
Other information |
None.
33
Directors, executive officers and corporate governance |
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101.113. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
The company currently has seven directors. The articles of the company require that the board have between five and fifteen directors. Each director is elected to hold office until the close of the next annual meeting. Each of the seven individuals listed in the section entitled “Nominees for director” on pages 102114 to 105117 of this report have been nominated for election at the annual meeting of shareholders to be held May 1, 2020.4, 2021. All of the nominees, with the exception of M.R. Crocker, are now directors and have been since the dates indicated. D.C. Brownell is a current director and has chosen not to stand for re-election.
Reference is made to the section under “Nominees for director”:
| ● | “Director nominee tables”, on pages |
Reference is made to the sections under “Corporate governance disclosure”:
| ● | “Skills and experience of our board |
| ● | “Other public company directorships of our board |
| ● | The table entitled “Audit committee” under “Board and committee structure”, on page |
| ● | “Ethical business conduct”, starting on page |
| ● | “Largest shareholder”, on page |
Reference is made to the sections under “Company executives and executive compensation”:
| ● | “Named executive officers of the company” and “Other executive officers of the company”, on pages |
Executive compensation |
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101.113. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the sections under “Corporate governance disclosure”:
“Director compensation”, on pages |
“Share ownership guidelines of independent directors and chairman, president and chief executive officer”, on page |
Reference is made to the following sections under “Company executives and executive compensation”:
“Letter to shareholders from the executive resources committee on executive compensation”, starting on page |
“Compensation discussion and analysis”, on pages |
Security ownership of certain beneficial owners and management and related stockholder matters |
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101.113. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the section under “Company executives and executive compensation” entitled “Equity compensation plan information”, within the “Compensation discussion and analysis” section, on page 163178 of this report.
Reference is made to the section under “Corporate governance disclosure” entitled “Largest shareholder”, on page 134148 of this report.
Reference is also made to the security ownership information for directors and executive officers of the company under the preceding Items 10 and 11. The compensation of the directors and executive officers of the company for the year-ended December 31, 20192020 is described in the sections under “Nominees for director” starting on page 102,114, “Director compensation” starting on page 123136 and “Company executives and executive compensation” starting on page 136.150. The following table shows the number of Imperial Oil Limited and Exxon Mobil Corporation common shares owned and restricted stock units held by each named executive officer, and the incumbent directors and executive officers as a group, as of February 12, 2020.16, 2021.
| Imperial Oil Limited | Exxon Mobil Corporation | |||||||||||||||
| Named executive officer | Common shares (a) | Restricted stock units (b) | Common shares (a) | Restricted stock units (b) | ||||||||||||
R.M. Kruger (c) | - | 599,100 | 2,007 | 118,500 | ||||||||||||
D.E. Lyons | - | 38,400 | 8,770 | 29,850 | ||||||||||||
B.W. Corson | - | 78,200 | 96,903 | 144,200 | ||||||||||||
J.R. Whelan | - | 66,000 | 28,607 | 15,850 | ||||||||||||
T.B. Redburn | 3,407 | 98,050 | - | - | ||||||||||||
Incumbent directors and executive officers as a group (17 people) | 140,042 | 581,325 | 146,549 | 263,000 | ||||||||||||
Imperial Oil Limited | Exxon Mobil Corporation | |||||||||||||||
| Named executive officer | Common shares (a) | Restricted stock units (b) | Common shares (a) | Restricted stock units (b) | ||||||||||||
B.W. Corson | - | 156,400 | 87,758 | 116,100 | ||||||||||||
D.E. Lyons | - | 61,200 | 9,480 | 19,550 | ||||||||||||
T.B. Redburn | 3,571 | 101,500 | - | - | ||||||||||||
S.P. Younger | - | 16,200 | 7,703 | 25,800 | ||||||||||||
B.A. Jolly | 29,491 | 63,150 | - | - | ||||||||||||
Incumbent directors and executive officers as a group (17 people) | 126,660 | 509,925 | 117,742 | 252,200 | ||||||||||||
| (a) | No common shares are beneficially owned by reason of exercisable options. None of these individuals owns more than 0.01 percent of the outstanding shares of Imperial Oil Limited or Exxon Mobil Corporation. The directors and officers as a group own approximately 0.02 percent of the outstanding shares of Imperial Oil Limited, and less than 0.01 percent of the outstanding shares of Exxon Mobil Corporation. Information not being within the knowledge of the company has been provided by the directors and the executive officers individually. |
| (b) | Restricted stock units do not carry voting rights prior to the issuance of shares on settlement of the awards. |
Certain relationships and related transactions, and director independence |
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101.113. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the section under “Corporate governance disclosure” entitled “Independence of our board members”members and nominees”, on page 110122 of this report.
Reference is made to the section under “Corporate governance disclosure” entitled “Transactions with Exxon Mobil Corporation”, on page 134148 of this report.
D.C. Brownell is deemed a
non-independent
member of the board of directors and the executive resources committee, public policy and corporate responsibility committee, nominations and corporate governance committee and community collaboration and engagement committee under the relevant standards. As an employee of Exxon Mobil Corporation, D.C. Brownell is independent of the company’s management and is able to assist these committees by reflecting the perspective of the company’s shareholders.Principal accountant fees and services |
Auditor information
The audit committee of the board of directors recommends that PwC be reappointed as the auditor of the company until the close of the next annual meeting. PwC has been the auditor of the company for more than five years and are located in Calgary, Alberta. PwC is a participating audit firm with the Canadian Public Accountability Board.
Auditor fees
The aggregate fees of PwC for professional services rendered for the audit of the company’s financial statements and other services for the fiscal years ended December 31, 20192020 and December 31, 20182019 were as follows:
thousands of Canadian dollars | 2019 | 2018 | ||||||
Audit fees | 1,782 | 1,808 | ||||||
Audit-related fees | 94 | 94 | ||||||
Tax fees | - | - | ||||||
All other fees | - | - | ||||||
Total fees | 1,876 | 1,902 |
| thousands of Canadian dollars | 2020 | 2019 | ||||||
Audit fees | 1,910 | 1,782 | ||||||
Audit-related fees | 92 | 94 | ||||||
Tax fees | - | - | ||||||
All other fees | - | - | ||||||
Total fees | 2,002 | 1,876 | ||||||
Audit fees included the audit of the company’s annual financial statements, internal control over financial reporting, and a review of the first three quarterly financial statements in 2019.2020. Audit-related fees consisted of other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities. The company did not engage the auditor for any other services.
The audit committee formally and annually evaluates the performance of the external auditor, recommends the external auditor to be appointed by the shareholders, recommends their remuneration and oversees their 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.
Auditor independence
The audit committee continually discusses with PwC their independence from the company and from management. PwC have confirmed that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta, the Public Company Accounting Oversight Board (United States) (PCAOB) and the rules of the U.S. Securities and Exchange Commission. The company has concluded that the auditor’s independence has been maintained.
PART IV
Item 15. Exhibits, financial statement schedules |
Reference is made to the table of contents in the “Financial section” on page 3641 of this report.
The following exhibits, numbered in accordance with Item 601 of Regulation
S-K,
are filed as part of this report:(3) | ||||
| Restated certificate and articles of incorporation of the company (Incorporated herein by reference to Exhibit (3.1) to the company’s Form 8-K filed on May 3, 2006 (File No. | ||||
By-laws of the company (Incorporated herein by reference to Exhibit (3)(ii) to the company’s Quarterly Report on Form10-Q for thequarter ended March 31, 2003 (File No. 0-12014)). | ||||
(4) | Description of capital stock. (Incorporated herein by reference to Exhibit (4)(vi) of the company’s Annual Report on Form 10-K for the year ended December 31, 2019 (FileNo. 0-12014)). | |||
(10) (ii) | ||||
(1) 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 (FileNo. 2-65290)). | ||||
(2) 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 (FileNo. 2-9259)). | ||||
(3) 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 (FileNo. 0-12014)). | ||||
(4) 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 dated June 25, 1984. (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 (FileNo. 0-12014)). | ||||
(5) 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 (FileNo. 0-12014)). | ||||
(6) 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 (FileNo. 0-12014)). | ||||
(7) 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 (FileNo. 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 (FileNo. 2-9259)). | |||
(2) 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 (FileNo. 0-12014)). | ||||
(3) | ||||
8-K filed on February 23, 2012 (FileNo. 0-12014)). | ||||
8-K filed on October 31, 2016 (FileNo. 0-12014)). |
38
8-K filed on October 31, 2016 (FileNo. 0-12014)). (6) Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2020 and subsequent years, as amended effective November 24, 2020. | ||||
(21) | Imperial Oil Resources Limited is incorporated in Canada, and is a wholly-owned subsidiary 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, | |||
Certification by principal executive officer of Periodic Financial Report pursuant to Rule 13a-14(a). | ||||
Certification by principal financial officer of Periodic Financial Report pursuant to Rule 13a-14(a). | ||||
Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350. | ||||
Certification by chief financial officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350. | ||||
(101) | Interactive Data Files (formatted as Inline XBRL). | |||
(104) | Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). | |||
Copies of Exhibits may be acquired upon written request of any shareholder to the vice president, investor relations, Imperial Oil Limited, 505 Quarry Park Boulevard S.E., Calgary, Alberta T2C 5N1, and payment of processing and mailing costs.
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, 202024, 2021 by the undersigned, thereunto duly authorized.
Imperial Oil Limited by /s/ Bradley W. Corson |
(Bradley W. Corson) |
Chairman, 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, 202024, 2021 by the following persons on behalf of the registrant and in the capacities indicated.
| Signature | Title | |||
/s/ Bradley W. Corson (Bradley W. Corson) | Chairman, president and chief executive officer and director (Principal executive officer) | |||
/s/ Daniel E. Lyons (Daniel E. Lyons) | Senior vice-president, finance and administration, and controller (Principal financial officer and principal accounting officer) | |||
/s/ David C. Brownell (David C. Brownell) | Director | |||
/s/ David W. Cornhill | (David W. Cornhill) | Director | ||
/s/ Krystyna T. Hoeg | ||||
(Krystyna T. Hoeg) | Director | |||
/s/ Miranda C. Hubbs | (Miranda C. Hubbs) | Director | ||
/s/ Jack M. Mintz | (Jack M. Mintz) | Director | ||
/s/ David S. Sutherland | (David S. Sutherland) | Director | ||
Table of contents | Page | |||
Financial information (U.S. GAAP) | ||||||||||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | 2017 | 2016 | |||||||||||||||
Revenues | 22,284 | 34,002 | 34,964 | 29,125 | 25,049 | |||||||||||||||
Net income (loss): | ||||||||||||||||||||
Upstream | (2,318 | ) | 1,348 | (138 | ) | (706 | ) | (661 | ) | |||||||||||
Downstream | 553 | 961 | 2,366 | 1,040 | 2,754 | |||||||||||||||
Chemical | 78 | 108 | 275 | 235 | 187 | |||||||||||||||
Corporate and other | (170 | ) | (217 | ) | (189 | ) | (79 | ) | (115 | ) | ||||||||||
Net income (loss) | (1,857 | ) | 2,200 | 2,314 | 490 | 2,165 | ||||||||||||||
Cash and cash equivalents at year-end | 771 | 1,718 | 988 | 1,195 | 391 | |||||||||||||||
Total assets at year-end | 38,031 | 42,187 | 41,456 | 41,601 | 41,654 | |||||||||||||||
Long-term debt at year-end | 4,957 | 4,961 | 4,978 | 5,005 | 5,032 | |||||||||||||||
Total debt at year-end | 5,184 | 5,190 | 5,180 | 5,207 | 5,234 | |||||||||||||||
Other long-term obligations at year-end | 4,100 | 3,637 | 2,943 | 3,780 | 3,656 | |||||||||||||||
Shareholders’ equity at year-end | 21,418 | 24,276 | 24,489 | 24,435 | 25,021 | |||||||||||||||
Cash flow from operating activities | 798 | 4,429 | 3,922 | 2,763 | 2,015 | |||||||||||||||
Per share information (Canadian dollars) | ||||||||||||||||||||
Net income (loss) per common share - basic | (2.53 | ) | 2.88 | 2.87 | 0.58 | 2.55 | ||||||||||||||
Net income (loss) per common share - diluted | (2.53 | ) | 2.88 | 2.86 | 0.58 | 2.55 | ||||||||||||||
Dividends per common share - declared | 0.88 | 0.85 | 0.73 | 0.63 | 0.59 | |||||||||||||||
42
millions of Canadian dollars | 2019 | 2018 | 2017 | 2016 | 2015 | |||||||||||||||
Revenues | 34,002 | 34,964 | 29,125 | 25,049 | 26,756 | |||||||||||||||
Net income (loss): | ||||||||||||||||||||
Upstream | 1,348 | (138 | ) | (706 | ) | (661 | ) | (704 | ) | |||||||||||
Downstream | 961 | 2,366 | 1,040 | 2,754 | 1,586 | |||||||||||||||
Chemical | 108 | 275 | 235 | 187 | 287 | |||||||||||||||
Corporate and other | (217 | ) | (189 | ) | (79 | ) | (115 | ) | (47 | ) | ||||||||||
Net income (loss) | 2,200 | 2,314 | 490 | 2,165 | 1,122 | |||||||||||||||
Cash and cash equivalents at year-end | 1,718 | 988 | 1,195 | 391 | 203 | |||||||||||||||
Total assets at year-end | 42,187 | 41,456 | 41,601 | 41,654 | 43,170 | |||||||||||||||
Long-term debt at year-end | 4,961 | 4,978 | 5,005 | 5,032 | 6,564 | |||||||||||||||
Total debt at year-end | 5,190 | 5,180 | 5,207 | 5,234 | 8,516 | |||||||||||||||
Other long-term obligations at year-end | 3,637 | 2,943 | 3,780 | 3,656 | 3,597 | |||||||||||||||
Shareholders’ equity at year-end | 24,276 | 24,489 | 24,435 | 25,021 | 23,425 | |||||||||||||||
Cash flow from operating activities | 4,429 | 3,922 | 2,763 | 2,015 | 2,167 | |||||||||||||||
Per share information (Canadian dollars) | ||||||||||||||||||||
Net income (loss) per common share - basic | 2.88 | 2.87 | 0.58 | 2.55 | 1.32 | |||||||||||||||
Net income (loss) per common share - diluted | 2.88 | 2.86 | 0.58 | 2.55 | 1.32 | |||||||||||||||
Dividends per common share - declared | 0.85 | 0.73 | 0.63 | 0.59 | 0.54 | |||||||||||||||
Listed below are definitions of several of Imperial’s key business and financial performance measures. The definitions are provided to facilitate understanding of the terms and how they are calculated.
Capital employed
Capital employed is a measure of net investment. When viewed from the perspective of how capital is used by the business, it includes the company’s property, plant and equipment, and other assets, less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the company, it includes total debt and equity. Both of these views include the company’s share of amounts applicable to equity companies, which the company believes should be included to provide a more comprehensive measurement of capital employed.
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Business uses: asset and liability perspective | ||||||||||||
Total assets | 42,187 | 41,456 | 41,601 | |||||||||
Less: Total current liabilities excluding notes and loans payable | (4,366) | (3,753 | ) | (3,934 | ) | |||||||
Total long-term liabilities excluding long-term debt | (8,355) | (8,034 | ) | (8,025 | ) | |||||||
Add: Imperial’s share of equity company debt | 24 | 23 | 19 | |||||||||
Total capital employed | 29,490 | 29,692 | 29,661 | |||||||||
Total company sources: Debt and equity perspective | ||||||||||||
Notes and loans payable | 229 | 202 | 202 | |||||||||
Long-term debt | 4,961 | 4,978 | 5,005 | |||||||||
Shareholders’ equity | 24,276 | 24,489 | 24,435 | |||||||||
Add: Imperial’s share of equity company debt | 24 | 23 | 19 | |||||||||
Total capital employed | 29,490 | 29,692 | 29,661 | |||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||||
Business uses: asset and liability perspective | ||||||||||||||
Total assets | 38,031 | 42,187 | 41,456 | |||||||||||
Less: | Total current liabilities excluding notes and loans payable | (3,153 | ) | (4,366 | ) | (3,753 | ) | |||||||
| Total long-term liabilities excluding long-term debt | (8,276 | ) | (8,355 | ) | (8,034 | ) | ||||||||
Add: Imperial’s share of equity company debt | 26 | 24 | 23 | |||||||||||
Total capital employed | 26,628 | 29,490 | 29,692 | |||||||||||
Total company sources: Debt and equity perspective | ||||||||||||||
Notes and loans payable | 227 | 229 | 202 | |||||||||||
Long-term debt | 4,957 | 4,961 | 4,978 | |||||||||||
Shareholders’ equity | 21,418 | 24,276 | 24,489 | |||||||||||
Add: Imperial’s share of equity company debt | 26 | 24 | 23 | |||||||||||
Total capital employed | 26,628 | 29,490 | 29,692 | |||||||||||
Return on average capital employed (ROCE)
ROCE is a financial performance ratio. From the perspective of the business segments, ROCE is annual business-segmentbusiness segment net income divided by average business-segmentbusiness segment capital employed (an average of the beginning andamounts). Segment net income includes Imperial’s share of segment net income of equity companies, consistent with the definition used for capital employed, and excludes the cost of financing. The company’s total ROCE is net income excluding theindustry to demonstrate to shareholders that capital has been used wisely over the long term.industry. Additional measures, which are more cash flow based, are used to make investment decisions.
end-of-year
after-tax
cost of financing divided by total average capital employed. The company has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in a capital-intensive, long-term millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Net income | 2,200 | 2,314 | 490 | |||||||||
Financing (after-tax), including Imperial’s share of equity companies | 66 | 77 | 48 | |||||||||
Net income excluding financing | 2,266 | 2,391 | 538 | |||||||||
Average capital employed | 29,591 | 29,677 | 29,967 | |||||||||
Return on average capital employed (percent) – corporate total | 7.7 | 8.1 | 1.8 | |||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Net income (loss) | (1,857 | ) | 2,200 | 2,314 | ||||||||
Financing (after-tax), including Imperial’s share of equity companies | 52 | 66 | 77 | |||||||||
Net income (loss) excluding financing | (1,805 | ) | 2,266 | 2,391 | ||||||||
Average capital employed | 28,059 | 29,591 | 29,677 | |||||||||
Return on average capital employed (percent) – corporate total | (6.4 | ) | 7.7 | 8.1 | ||||||||
Cash flows from operating activities and asset sales
Cash flows from operating activities and asset sales is the sum of the net cash provided by operating activities and proceeds from asset sales reported in the Consolidated statement of cash flows. This cash flow reflects the total sources of cash both from operating the company’s assets and from the divesting of assets. The company employs a long-standing and regular disciplined review process to ensure that all assets are contributing to the company’s strategic objectives. Assets are divested when they no longer meet these objectives or are worth considerably more to others. Because of the regular nature of this activity, the company believes it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Cash flows from operating activities | 4,429 | 3,922 | 2,763 | |||||||||
Proceeds from asset sales | 82 | 59 | 232 | |||||||||
Total cash flows from operating activities and asset sales | 4,511 | 3,981 | 2,995 |
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Cash flows from operating activities | 798 | 4,429 | 3,922 | |||||||||
Proceeds from asset sales | 82 | 82 | 59 | |||||||||
Total cash flows from operating activities and asset sales | 880 | 4,511 | 3,981 | |||||||||
Operating costs
Operating costs are the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy costs, staffing and maintenance costs. They exclude the cost of raw materials, taxes and interest expense and are on a
before-tax
basis. While the company is responsible for all revenue and expense elements of net income, operating costs represent the expenses most directly under the company’s control and therefore, are useful in evaluating the company’s performance.Reconciliation of operating costs
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
From Imperial’s Consolidated statement of income | ||||||||||||
Total expenses | 32,055 | 32,026 | 28,842 | |||||||||
Less: | ||||||||||||
Purchases of crude oil and products | 20,946 | 21,541 | 18,145 | |||||||||
Federal excise tax and fuel charge | 1,808 | 1,667 | 1,673 | |||||||||
Financing | 93 | 108 | 78 | |||||||||
Subtotal | 22,847 | 23,316 | 19,896 | |||||||||
Imperial’s share of equity company expenses | 76 | 74 | 62 | |||||||||
Total operating costs | 9,284 | 8,784 | 9,008 |
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
From Imperial’s Consolidated statement of income | ||||||||||||
Production and manufacturing | 6,520 | 6,121 | 5,586 | |||||||||
Selling and general | 900 | 908 | 883 | |||||||||
Depreciation and depletion | 1,598 | 1,555 | 2,172 | |||||||||
Non-service pension and postretirement benefit | 143 | 107 | 122 | |||||||||
Exploration | 47 | 19 | 183 | |||||||||
Subtotal | 9,208 | 8,710 | 8,946 | |||||||||
Imperial’s share of equity company expenses | 76 | 74 | 62 | |||||||||
Total operating costs | 9,284 | 8,784 | 9,008 |
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
From Imperial’s Consolidated statement of income | ||||||||||||
Total expenses | 24,796 | 32,055 | 32,026 | |||||||||
Less: | ||||||||||||
Purchases of crude oil and products | 13,293 | 20,946 | 21,541 | |||||||||
Federal excise tax and fuel charge | 1,736 | 1,808 | 1,667 | |||||||||
Financing | 64 | 93 | 108 | |||||||||
Subtotal | 15,093 | 22,847 | 23,316 | |||||||||
Imperial’s share of equity company expenses | 64 | 76 | 74 | |||||||||
Total operating costs | 9,767 | 9,284 | 8,784 | |||||||||
Components of operating costs | ||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
From Imperial’s Consolidated statement of income | ||||||||||||
Production and manufacturing | 5,535 | 6,520 | 6,121 | |||||||||
Selling and general | 741 | 900 | 908 | |||||||||
Depreciation and depletion (includes impairments) | 3,293 | 1,598 | 1,555 | |||||||||
Non-service pension and postretirement benefit | 121 | 143 | 107 | |||||||||
Exploration | 13 | 47 | 19 | |||||||||
Subtotal | 9,703 | 9,208 | 8,710 | |||||||||
Imperial’s share of equity company expenses | 64 | 76 | 74 | |||||||||
Total operating costs | 9,767 | 9,284 | 8,784 | |||||||||
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 business model involving exploration for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products.
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. The company’s integrated business model, with significant investments in Upstream, Downstream and Chemical segments, generally reduces the company’s risk from changes in commodity prices. While commodity prices depend on supply and demand and may be volatile on a short-term basis, Imperial’s investment decisions are grounded on fundamentals reflected in its long-term business outlook, and use 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. VolumesVolume projections are based on individual field production profiles, which are also updated annually. Price ranges for crude oil, natural gas, refined products and chemical products are based on corporate plan assumptions developed annually and are utilized for investment evaluation purposes. Major investment opportunities are evaluated over a range of potential market conditions. Once major investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.
The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.
45
Business environment and risk assessment
Long-term business outlook
Given the uncertainty around the near-term impacts of 2019, which combined with the near-term pathways is used to help inform the company’s long-term business strategies and investment plans.
COVID-19
on economic growth, energy demand and energy supply, and lack of precedent, the company is considering a range of recovery pathways to guide near-term plans. These pathways expect that energy demand will grow beyond 2019 levels as early as 2022 reflecting the phase out ofCOVID-19
impacts and re-establishment of long-term supply / demand fundamentals. The “Long-term business outlook” is based on Exxon Mobil Corporation’sOutlook for Energy
By 2040, the world’s population is projected at around 9.29.1 billion people, or about 1.6 billion more than in 2017.2018. Coincident with this population increase, the company expects worldwide economic growth to average close to 32.5 percent per year, with economic output nearly doublinggrowing by around 75 percent by 2040. As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by about 20more than 10 percent from 20172018 to 2040. This increase in energy demand is expected to be driven by developing countries (i.e., those that are not member nations of the Organization for Economic
Co-operation
and Development (OECD)). Canada is expected to see flat to modest local energy demand growth through to 2040 and will continue to be a large supplier of energy exports to help meet rising global energy needs.As expanding prosperity helps drive global energy demand higher, increasing use of energy efficient technologies and practices, as well as lower-emission products will continue to help significantly reduce energy consumption and emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspects of the world’s economy through 2040, affecting energy requirements for power generation, transportation, industrial applications, and residential and commercial needs.
Global electricity demand is expected to increase approximately 6050 percent from 20172018 to 2040, with developing countries likely to account for about 85 percent of the increase. Consistent with this projection, power generation is expected to remain the largest and fastest growing major segment of global primary energy demand, supported by a wide variety of energy sources. The share of coal fired generation is likely to decline substantially and approach 2520 percent of the world’s electricity in 2040, versus nearly 40 percent in 2017,2018, in part as a result of policies to improve air quality as well as reduce greenhouse gas emissions to address the risks related to climate change. From 20172018 to 2040, the amount of electricity supplied using natural gas, nuclear power, and renewables is likely to grow bytwo-thirds,nearly double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal. Electricity from wind and solar is likely to increase about 400 percent, helping total renewables (including other sources, i.e., hydropower) to account for about 7580 percent of the increase in electricity supplies worldwide through 2040. Total renewables will likely reach nearly 40about 50 percent of global electricity supplies by 2040. Natural gas and nuclear are also expected to increase shares over the period to 2040, reaching almost 30more than 25 percent and about 1510 percent of global electricity supplies respectively by 2040. Supplies of electricity by energy type will reflect significant differences across regions reflecting a wide range of factors including the cost and availability of various energy supplies and policy developments.
Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by more than 25about 20 percent from 20172018 to 2040. Transportation energy demand is likely to account for approximatelyover 60 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to peak prior to 2025 and then decline to levels seen in the early-2010s by 2040 as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United States, work to offset growth in the worldwide car fleet of about 7060 percent. By 2040, light-duty vehicles are expected to account for about 20 percent of global liquid fuels demand. During the same time period, nearly all the world’s commercial transportation fleets are likely to continue to run on liquid fuels, which are widely available and offer practical advantages in providing a large quantity of energy in small volumes.
46
Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of transportation, and fitness as a practical solution to meet a wide variety of needs. By 2040, global demand for liquid fuels is projected to grow to approximately 114110 million169 percent from 2017.2018. The1015 percent. Much of the global liquid fuels demand today is met by crude production from traditional conventional sources; these supplies will remain important, and significant development activity is expected to offset much of the natural declines from these fields. At the same time, a variety of emerging supply sources – including tight oil, deepwater, oil sands, natural gas liquids and biofuels – are expected to grow to help meet rising demand. The world’s resource base is sufficient to meet projected demand through 2040 as technology advances continue to expand the availability of economic and lower carbon supply options. However, timely investments will remain critical to meeting global needs with reliable and affordable supplies.
oil-equivalent
barrels per day, an increase of about non-OECD
share of global liquid fuels demand is expected to increase to about 65 percent by 2040, as liquid fuels demand in the OECD is likely to decline by close to Natural gas is alow-emission,lower-emission,versatile and practical fuel for a wide variety of applications, and it is expected to grow the most of any primary energy type from 20172018 to 2040, meeting more than 40about 50 percent of global energy demand growth. Global natural gas demand is expected to rise about 3525 percent from 20172018 to 2040, with about half of that increase coming from the Asia Pacific region. Significant growth in supplies of unconventional gas – the natural gas found in shale and other tight rock formations – will help meet these needs. In total, about 6055 percent of the growth in natural gas supplies is expected to be from unconventional sources. At the same time, conventionally-produced natural gas is likely to remain the cornerstone of global supply, meeting more than
two-thirds
of worldwide demand in 2040. Liquefied natural gas (LNG) trade will expand significantly, meeting about 40 percent of the increase in global demand growth, with much of this supply expected to help meet rising demand in Asia Pacific.The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share remaining close to 30 percent in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas in the 2020 to 2025 timeframe.next few years. The share of natural gas is expected to reach aboutmore than 25 percent by 2040, while the share of coal falls to about 20 percent.two thirds of the natural gas share. Nuclear power is projected to grow significantly, as many nations are likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is likely to exceed 15 percent of global energy by 2040, with biomass, hydro and geothermal contributing a combined share of more than 10 percent. Total energy supplied from wind, solar and biofuels is expected to increase rapidly, growing nearly 250over 350 percent from 20172018 to 2040, when they will likely be just over 56 percent of the world energy mix.
The company anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from increases in previously discovered fields. Technology will underpin these increases. The investments to develop and supply resources to meet global demand through 2040 will be significant – even if demand remains flat. This reflects a fundamental aspect of the oil and natural gas business as the International Energy Agency (IEA) describes in its. According to the IEA’s Stated Energy Policies Scenario, the investment required to meet oil and natural gas supply requirements worldwide over the period 2019 to 2040 will be about US$2017 trillion (measured in 20182019 dollars). In the IEA’s Sustainable Development Scenario, which is in line with the objectives of the Paris Agreement on climate change, the investment need would still accumulate to US$1312 trillion.
World Energy Outlook 20192020
47
International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. Imperial’s estimates of potential costs related to greenhouse gas emissions align with applicable provincial and federal regulations. Additionally, Imperial uses ExxonMobil’sas a foundation for estimating energy supply and demand requirements from various energy sources and uses, and thetakes into account policies established to reduce energy related greenhouse gas emissions. The climate accord reached at the Conference of the Parties (COP 21) in Paris set many new goals, and many related policies are still emerging. Thereflects an environment with increasingly stringent climate policies and is consistent with the aggregation of Nationally Determined Contributions (NDCs), which were submitted by signatories to the United Nations Framework Convention on Climate Change (UNFCCC) 2015 Paris Agreement. Theseeks to identify potential impacts of climate related policies, which often target specific sectors. It estimates potential impacts of these policies on consumer energy demand by using various assumptions and tools – including, depending on the sector, application of a proxy cost of carbon or assessment of targeted policies (i.e., automotive fuel economy standards). As people and nations look for ways to reduce risks of global climate change, they will continue to need practical solutions that do not jeopardize the affordability or reliability of the energy they need.
The company continues to monitor the updates to the NDCs that nations are expected to provide in preparation for COP 26 in Glasgow in November 2021 as well as other policy developments in light of net zero ambitions recently formulated by some nations, including Canada.Outlook for Energy
Outlook for Energy
Outlook for Energy
Outlook for Energy
Practical solutions to the world’s energy and climate challenges will benefit from market competition in addition to well-informed, well-designed and transparent policy approaches that carefully weigh costs and benefits. Such policies are likely to help manage the risks of climate change while also enabling societies to pursue other high priority goals around the world – including clean air and water, access to reliable and affordable energy, and economic progress for all people. The company encourages sound policy solutions that reduce climate-related risks across the economy at the lowest societal cost. All practical and economically viable energy sources both conventional and unconventional, will need to be pursued to continue meeting global energy demand, recognizing the scale and variety of worldwide energy needs, as well as the importance of expanding access to modern energy to promote better standards of living for billions of people.
The information provided in the“Long-term “Long-term business outlook” includes internal estimates and forecastsprojections based upon ExxonMobil’s internal data and analyses, as well as publicly available information from external sources including the International Energy Agency.
48
Upstream
Imperial produces crude oil and natural gas for sale predominantly into North American markets. Imperial’s Upstream business strategies guide the company’s exploration, development, production, research and gas marketing activities. These strategies include maximizing asset reliability, accelerating development and application of high impact technologies, maximizing value by capturing new business opportunities and managing the existing portfolio, as well as pursuing sustainable improvements in organizational efficiency and effectiveness. These strategies are underpinned by a relentless focus on operations integrity, commitment to innovative technologies, disciplined approach to investing and cost management, development of employees and investment in the communities within which the company operates.
Imperial has a significant oil and gas resource base and a large inventory of potential projects. The company continues to evaluate opportunities to support long-term growth. As future development projects bring new production online, Imperial expects growth from oil sands
in-situ
and mining, as well as unconventional resources, with the largest growth potential related toin-situ.
Actual volumes will vary from year to year due to the factors described in Item 1A. “Risk factors”.The upstream industry environment continued to recover in 2019 as crudehas a history of significant price differentialsvolatility. Market demand and prices experienced a sharp decline in the western Canadian market narrowed sincefirst half of 2020 largely driven by the end2018.the year as supply and demand began to rebalance. Prices for most of the company’s crude oil sold are referenced to Western Canada Select (WCS) and West Texas Intermediate (WTI) oil markets. OnIn January 1, 2019, the Government of Alberta’s temporary mandatory production curtailment regulations came into effect. Consequently, the WTI / WCS differential narrowed from an average of approximately US$40 per barrel in the fourth quarter of 2018, to an average of about US$12 per barrel in the first quarter of 2019. Throughout 2019, the Government of Alberta continually easedAlthough the mandatory production limit, increasedcurtailment decreased throughout 2019 and 2020, and was eliminated in December 2020, the base limitregulatory authority to impose curtailment remains in place and there is the potential for production curtailment to beintroduced several exemptions including a special production allowance providing temporary curtailment relief equivalent to incremental increases in shipments by rail.increased. The duration of these regulations is uncertain. Imperial continually monitors the effects of these regulations and evaluates opportunities, including crude shipments by rail and the pace of the development of its Aspen
COVID-19
pandemic. Following this decline, prices improved in the second half of re-imposed
and in-situ
oil sands project, as economically justified.Imperial believes prices over the long-termlong term will be driven by market supply and demand, with the demand side largely being a function of general economic activities, levels of prosperity, technology advances, consumer preference and government policies. On the supply side, prices may be significantly impacted by political events, logistics constraints, the actions of OPEC, governments and other factors. To manage the risks associated with price, Imperial evaluates annual plans and all major investments across a range of price scenarios.
In 2020, Imperial
re-assessed
the long-term development plans of its unconventional portfolio in Alberta and no longer plans to further develop a significant portion of this portfolio. The decision resulted in anon-cash,
after-tax
impairment charge of $1,171 million in 2020, thereby reducing the carrying value of those assets to fair value. The company retains its interest in these resources. Thesenon-core
assets arenon-producing,
undeveloped assets and the company does not expect any material future cash expenditures related to this impairment. This decision is consistent with Imperial’s strategy of focusing its upstream resources and efforts on its key oil sands assets as well as on only the most attractive portions of its unconventional portfolio. Imperial continues to produce from its developed acreage.Kearl’s supplemental crushing facilities started operations in late 2019, with
ramp-up
of all units through early 2020. These facilities have further improved reliability, reduced planned downtime, lowered unit costs and enabled the asset to achieve higher volumes. As disclosed in the company’s 2019 Form10-K,
the original production target in 2020 for Kearl was 240,000 barrels per day (about 170,000 barrels Imperial’s share). As a result of market conditions, the company adjusted planned maintenance and turnaround activity, and revised its full-year guidance for Kearl total gross production to 220,000 barrels per day (about 156,000 barrels Imperial’s share). In 2020, Kearl achieved record annual total gross production of 222,000 barrels per day (158,000 barrels Imperial’s share). Imperial continues to progress initiatives to enable the asset to achieve 255,000 barrels per day of total gross production in 2021 (about 181,000 barrels Imperial’s share). In 2020, gross bitumen production at Cold Lake was impacted by ongoing steam management. The company plans to focus on base performance in the near-term and expects gross bitumen production at Cold Lake to average approximately 130,000 barrels per day in 2021.As described in more detail in Item 1A. “Risk factors”, environmental risks and climate related regulations, and
COVID-19
could have negative impacts on the upstream business.49
Downstream
Imperial’s Downstream serves predominantly Canadian markets with refining, logistics and marketing assets. Imperial’s Downstream business strategies competitively position the company across a range of market conditions. These strategies include targeting industry leading performance in reliability, safety and operations integrity, as well as maximizing value from advanced technologies, capitalizing on integration across Imperial’s businesses, selectively investing for resilient and advantaged returns, operating efficiently and effectively, and providing quality, valued and differentiated products and services to customers.
Imperial owns and operates three refineries in Canada, with aggregate distillation capacity of 423,000428,000 barrels per day. Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, diesel oil, jet fuel, fuel oil and asphalt). Crude oil and many products are widely traded with published prices, including those quoted on the New York Mercantile Exchange. Prices for these commodities are determined by the global and regional marketplaces and are influenced by many factors, including global and regional supply / demand balances, inventory levels, industry refinery operations, import / export balances, currency fluctuations, seasonal demand, weather and political climate. Imperial’s integration across the value chain, from refining to marketing, enhances overall value across the fuels business.
In 2019, Imperial’s margins were negatively2020, demand for petroleum products was significantly impacted by narrowing crude price differentials that resulted,thepart, from the Governmentfirst half of Alberta’s temporary mandatory curtailment regulations on crude oil production.
COVID-19
pandemic, starting in As described in more detail in Item 1A. “Risk factors”, proposed carbon policy and other climate related regulations, as well as continued biofuels mandates, could have negative impacts on the downstream business.
Imperial supplies petroleum products to the motoring public through Esso and Mobil-branded sites and independent marketers. At the end of 2019,2020, there were about 2,3002,400 sites operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate sites in alignment with Esso and Mobil brand standards.
Chemical
North America continued to benefit from abundant supplies of natural gas and gas liquids, providing both low cost energy and feedstock for steam crackers. In 2019,2020, margins were adversely impacted by continued industry capacity additions outpacing demand growth. and effects related to
COVID-19.
Imperial maintains a competitive advantage through continued operational excellence, consistent product quality, investment and cost discipline, and integration of its chemical plant in Sarnia with the refinery. The company also benefits from its relationship with ExxonMobil’s North American chemical businesses, enabling Imperial to maintain a leadership position in its key market segments.Results of operations
In 2020, the balance of supply and demand for petroleum and petrochemical products experienced two significant disruptive effects. On the demand side, the
COVID-19
pandemic spread rapidly across Canada and the world resulting in substantial reductions in consumer and business activity and significantly reduced local and global demand for crude oil, natural gas, and petroleum products. This reduction in demand coincided with announcements of increased production in certain keyoil-producing
countries which led to increases in inventory levels and sharp declines in prices for crude oil, natural gas, and petroleum products. Market conditions continued to reflect considerable uncertainty throughout 2020 as consumer and business activity has exhibited some degree of recovery, but remained lower when compared to prior periods as a result of the pandemic. Despite actions taken by keyoil-producing
countries to reduce oversupply, and improved credit market conditions providing sufficient liquidity to credit-worthy companies, the unfavourable economic impacts appear increasingly likely to persist to some extent well into 2021.In late March, the company announced significant reductions in 2020 capital and operating expense spending plans. Capital and exploration expenditures for 2020 were $874 million, in line with the company’s most recent guidance of $900 million, and less than half of 2019 expenditures. Capital expenditures in 2021 are expected to be approximately $1.2 billion. In addition, full-year production and manufacturing expenses were $985 million lower than the prior year. This decrease enabled the company to surpass its $500 million expense reduction commitment made in 2020 by nearly double.
The effect of
COVID-19
and the current business environment on supply and demand patterns negatively impacted Imperial’s financial and operating results in 2020. Industry conditions seen in 2020 have led to lower realized prices for the company’s products and have resulted in substantially lower earnings and operating cash flow throughout 2020 in comparison to 2019. In response to these conditions, the company operated certain assets at reduced rates and adjusted planned maintenance and turnaround activities throughout the second and third quarters in an effort to reduceon-site
staffing levels and to better balance production with demand. Refinery utilization rates and petroleum product sales were reduced through the second quarter of 2020, but saw some improvement in product demands in the second half of the year. The length and severity ofCOVID-19
impacts to demand and the current business environment are highly uncertain, with the future supply and demand patterns inherently difficult to predict.In the second quarter of 2020, Canadian federal and provincial governments introduced plans and programs to support business and economic activities in response to the disruptive impacts from the
COVID-19
pandemic. The Government of Canada implemented the Canada Emergency Wage Subsidy (CEWS) as part of itsCOVID-19
Economic Response Plan, and has extended the CEWS until June 2021. The company received wage subsidies under this program and, if eligible, intends to continue to apply for these wage subsidies. Additionally, in the fourth quarter, the Alberta government enacted an accelerated reduction in the corporate income tax rate to eight percent beginning July 1, 2020, compared with a previously legislated reduction to eight percent beginning January 1, 2022. The corporate income tax rate change did not have a significant impact on the company’s financial statements.The company has taken steps, in line with federal and provincial guidelines and restrictions, to limit the spread of
COVID-19
among employees, contractors and the broader community, while also maintaining operations to ensure reliable supply of products to customers as a provider of essential services. The company maintains robust business continuity plans, which have been activated to minimize the impact ofCOVID-19
on workforce productivity.51
Consolidated
| millions of Canadian dollars | 2019 | 2018 | 2017 | 2020 | 2019 | 2018 | ||||||||||||||||||
Net income (loss) | 2,200 | 2,314 | 490 | (1,857 | ) | 2,200 | 2,314 | |||||||||||||||||
2020
Net loss in 2020 was $1,857 million, or $2.53 per share on a diluted basis, compared to net income of $2,200 million or $2.88 per share in 2019. Current year results reflect a
non-cash
impairment charge of $1,171 millionafter-tax,
related to the company’s decision to no longer develop a significant portion of its unconventional portfolio, and a favourable impact of about $115 millionafter-tax,
associated with the Canada Emergency Wage Subsidy (CEWS), which includes Imperial’s proportionate share of a joint venture. Full-year 2019 results included a favourable impact of $662 million associated with the Alberta corporate income tax rate decrease.2019
Net income in 2019 was $2,200 million, or $2.88 per share on a diluted basis, compared to net income of $2,314 million or $2.86 per share in 2018. 2019 results include a favourable impact, largely
non-cash,
of $662 million associated with the Alberta corporate income tax rate decrease. On June 28, 2019, the Alberta government enacted a 4 percent decrease in the provincial tax rate, from 12 percent to 8 percent by 2022.Upstream
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Net income (loss) | (2,318 | ) | 1,348 | (138 | ) | |||||||
2020
Upstream recorded a net loss of $2,318 million or $2.86 per share on a diluted basis, an increase of $1,824 millionfor the year, compared to net income of $490$1,348 million or $0.58 per share in 2017. The prior year results included upstream2019. Results were negatively impacted by lower realizations of about $2,620 million, achargescharge of $566$1,171 million, related to the company’s decision to no longer develop a significant portion of its unconventional portfolio, absence of a favourable impact of $689 million associated with the Alberta corporate income tax rate decrease in 2019, and lower volumes of about $130 million.
non-cash
impairment | millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Net income (loss) | 1,348 | (138 | ) | (706 | ) | |||||||
These items were partially offset by lower royalties of about $540 million, lower operating expenses of about $250 million, favourable foreign exchange impacts of about $100 million, and about $70 million associated with the CEWS received by the company which includes Imperial’s proportionate share of a joint venture.
2019
Upstream net income was $1,348 million for the year, reflecting the favourable impact associated with the decreased Alberta corporate income tax rate of $689 million. Excluding this impact, 2019 net income was $659 million, up $797 million compared to a net loss of $138 million in 2018. Improved results reflect higher crude oil realizations of about $1,000 million, as well as higher volumes of about $350 million primarily at Syncrude and Norman Wells. Results were negatively impacted by higher royalties of about $230 million, higher operating expenses of about $190 million and lower Cold Lake volumes of about $120 million.
Average realizations | ||||||||||||
| Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Bitumen (per barrel) | 50.02 | 37.56 | 39.13 | |||||||||
Synthetic oil (per barrel) | 74.47 | 70.66 | 67.58 | |||||||||
Conventional crude oil (per barrel) | 51.81 | 41.84 | 53.51 | |||||||||
Natural gas liquids (per barrel) | 22.83 | 38.66 | 31.46 | |||||||||
Natural gas (per thousand cubic feet) | 2.05 | 2.43 | 2.58 | |||||||||
Average realizations
| Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Bitumen (per barrel) | 25.69 | 50.02 | 37.56 | |||||||||
Synthetic oil (per barrel) | 49.76 | 74.47 | 70.66 | |||||||||
Conventional crude oil (per barrel) | 29.34 | 51.81 | 41.84 | |||||||||
Natural gas liquids (per barrel) | 13.85 | 22.83 | 38.66 | |||||||||
Natural gas (per thousand cubic feet) | 1.90 | 2.05 | 2.43 | |||||||||
2020
WTI averaged US$39.26 per barrel in 2020, down from US$57.03 per barrel in 2019. WCS averaged US$26.87 per barrel and US$44.29 per barrel for the same periods. The WTI / WCS differential narrowed to approximately US$12 per barrel in 2020, from around US$13 per barrel in 2019. The Canadian dollar averaged US$0.75 in 2020, essentially unchanged from 2019.
Imperial’s average Canadian dollar realizations for bitumen decreased in 2020 primarily due to a decrease in WCS. Bitumen realizations averaged $25.69 per barrel, compared to $50.02 per barrel in 2019. The company’s average Canadian dollar realizations for synthetic crude decreased generally in line with WTI, adjusted for changes in exchange rates and transportation costs. Synthetic crude realizations averaged $49.76 per barrel, compared to $74.47 per barrel in 2019.
2019
WTI averaged US$57.03 per barrel in 2019, down from US$65.03 per barrel in 2018. WCS averaged US$44.29 per barrel and US$38.71 per barrel for the same periods. The WTI / WCS differential narrowed to average approximately US$13 per barrel in 2019, from around US$26 per barrel in 2018. The Canadian dollar averaged US$0.75 in 2019, a decrease of US$0.02 from 2018.
Imperial’s average Canadian dollar realizations for bitumen increased in 2019, supported primarily by an increase in WCS and lower diluent costs. Bitumen realizations averaged $50.02 per barrel, up from $37.56 per barrel in 2018. The company’s average Canadian dollar realizations for synthetic crude increased relative to WTI, primarily due to the narrowing of the western Canadian light crude differential. Synthetic crude realizations averaged $74.47 per barrel, up from $70.66 per barrel in 2018.
Crude oil and natural gas liquids (NGL) - production and sales (a) | ||||||||||||||||||||||||
| thousands of barrels per day | 2020 | 2019 | 2018 | |||||||||||||||||||||
gross | net | gross | net | gross | net | |||||||||||||||||||
Bitumen | 290 | 279 | 285 | 254 | 293 | 255 | ||||||||||||||||||
Synthetic oil (b) | 69 | 68 | 73 | 65 | 62 | 60 | ||||||||||||||||||
Conventional crude oil | 11 | 10 | 14 | 13 | 5 | 5 | ||||||||||||||||||
Total crude oil production | 370 | 357 | 372 | 332 | 360 | 320 | ||||||||||||||||||
NGLs available for sale | 2 | 2 | 2 | 1 | 1 | 2 | ||||||||||||||||||
Total crude oil and NGL production | 372 | 359 | 374 | 333 | 361 | 322 | ||||||||||||||||||
Bitumen sales, including diluent (c) | 401 | 387 | 406 | |||||||||||||||||||||
NGL sales | 2 | 6 | 6 | |||||||||||||||||||||
Natural gas - production and production available for sale (a) | ||||||||||||||||||||||||
| millions of cubic feet per day | 2020 | 2019 | 2018 | |||||||||||||||||||||
gross | net | gross | net | gross | net | |||||||||||||||||||
Production (d) (e) | 154 | 150 | 145 | 144 | 129 | 126 | ||||||||||||||||||
Production available for sale (f) | 115 | 108 | 94 | |||||||||||||||||||||
| thousands of barrels per day | 2019 | 2018 | 2017 | |||||||||||||||||||||
| gross | net | gross | net | gross | net | |||||||||||||||||||
Bitumen | 285 | 254 | 293 | 255 | 288 | 255 | ||||||||||||||||||
Synthetic oil (b) | 73 | 65 | 62 | 60 | 62 | 57 | ||||||||||||||||||
Conventional crude oil | 14 | 13 | 5 | 5 | 4 | 3 | ||||||||||||||||||
Total crude oil production | 372 | 332 | 360 | 320 | 354 | 315 | ||||||||||||||||||
NGLs available for sale | 2 | 1 | 1 | 2 | 1 | 1 | ||||||||||||||||||
Total crude oil and NGL production | 374 | 333 | 361 | 322 | 355 | 316 | ||||||||||||||||||
Bitumen sales, including diluent (c) | 387 | 406 | 381 | |||||||||||||||||||||
NGL sales | 6 | 6 | 6 | |||||||||||||||||||||
| millions of cubic feet per day | 2019 | 2018 | 2017 | |||||||||||||||||||||
| gross | net | gross | net | gross | net | |||||||||||||||||||
Production (d) (e) | 145 | 144 | 129 | 126 | 120 | 114 | ||||||||||||||||||
Production available for sale (f) | 108 | 94 | 80 | |||||||||||||||||||||
| (a) | Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both. Net production excludes those shares. |
| (b) | The company’s synthetic oil production volumes were from the company’s share of production volumes in the Syncrude joint venture. |
| (c) | Diluent is natural gas condensate or other light hydrocarbons added to crude bitumen to facilitate transportation to market by pipeline and rail. |
| (d) | Gross production of natural gas includes amounts used for internal consumption with the exception of the amounts re-injected. |
| (e) | Net production is gross production less the mineral owners’ or governments’ share or both. Net production reported in the above table is consistent with production quantities in the net proved reserves disclosure. |
| (f) | Includes sales of the company’s share of net production and excludes amounts used for internal consumption. |
2020
Total gross production of Kearl bitumen averaged 222,000 barrels per day in 2020 (158,000 barrels Imperial’s share), the highest annual production in the asset’s history, up from 205,000 barrels per day (145,000 barrels Imperial’s share) in 2019. Improved production was mainly due to the addition of supplemental crushing facilities in 2020, partially offset by the balancing of near term production with demand through the advancement and extension of planned turnaround activities.
Gross production of Cold Lake bitumen averaged 132,000 barrels per day in 2020, compared to 140,000 barrels per day in 2019.
During 2020, the company’s share of gross production from Syncrude averaged 69,000 barrels per day, compared to 73,000 barrels per day in 2019.
2019
Total gross production of Kearl bitumen averaged 205,000 barrels per day in 2019 (145,000 barrels Imperial’s share), compared to 206,000 barrels per day (146,000 barrels Imperial’s share) in 2018.
Gross production of Cold Lake bitumen averaged 140,000 barrels per day in 2019, compared to 147,000 barrels per day in 2018.
During 2019, the company’s share of gross production from Syncrude averaged 73,000 barrels per day, up from 62,000 barrels per day in 2018. Higher production was mainly due to the absence of production impacts from the 2018 power disruption.
Downstream
Downstream | ||||||||||||
| millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Net income (loss) | 961 | 2,366 | 1,040 | |||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Net income (loss) | 553 | 961 | 2,366 | |||||||||
2020
Downstream net income was $553 million, compared to $961 million in 2019. Results were negatively impacted by lower margins of about $710 million, and lower sales volumes of about $290 million. These items were offset by lower operating expenses of about $190 million, lower turnaround impacts of about $190 million primarily related to reduced turnaround activity in the current year and improved reliability of about $180 million, primarily due to the absence of the Sarnia fractionation tower incident which occurred in April 2019.
2019
Downstream net income was $961 million, compared to $2,366 million in 2018. Earnings were negatively impacted by lower margins of about $1,130 million, reliability events of about $150 million, including the fractionation tower incident at Sarnia, higher net planned turnaround impacts of about $140 million, and lower sales volumes of about $130 million. These factors were partially offset by favourable foreign exchange impacts of about $90 million.
Refinery utilization | ||||||||||||
| thousands of barrels per day (a) | 2020 | 2019 | 2018 | |||||||||
Total refinery throughput (b) | 340 | 353 | 392 | |||||||||
Refinery capacity at December 31 | 428 | 423 | 423 | |||||||||
Utilization of total refinery capacity (percent) | 80 | 83 | 93 | |||||||||
Sales | ||||||||||||
| thousands of barrels per day (a) | 2020 | 2019 | 2018 | |||||||||
Gasolines | 215 | 249 | 255 | |||||||||
Heating, diesel and jet fuels | 146 | 167 | 183 | |||||||||
Heavy fuel oils | 20 | 21 | 26 | |||||||||
Lube oils and other products | 40 | 38 | 40 | |||||||||
Net petroleum product sales | 421 | 475 | 504 | |||||||||
| thousands of barrels per day (a) | 2019 | 2018 | 2017 | |||||||||
Total refinery throughput (b) | 353 | 392 | 383 | |||||||||
Refinery capacity at December 31 | 423 | 423 | 423 | |||||||||
Utilization of total refinery capacity (percent) | 83 | 93 | 91 | |||||||||
| thousands of barrels per day (a) | 2019 | 2018 | 2017 | |||||||||
Gasolines | 249 | 255 | 257 | |||||||||
Heating, diesel and jet fuels | 167 | 183 | 177 | |||||||||
Heavy fuel oils | 21 | 26 | 18 | |||||||||
Lube oils and other products | 38 | 40 | 40 | |||||||||
Net petroleum product sales | 475 | 504 | 492 | |||||||||
| (a) | Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. |
| (b) | Crude oil and feedstocks sent directly to atmospheric distillation units. |
2020
Refinery throughput averaged 340,000 barrels per day in 2020, compared to 353,000 barrels per day in 2019. Capacity utilization was 80 percent, compared to 83 percent in 2019. Lower throughput was driven by reduced demand due to the2018Refinery throughput averaged 392,000 barrels per day in 2018, up from 383,000 barrels per day in 2017. Capacity utilization increased to 93 percent from 91 percent in 2017. Petroleum product sales were 504,000 barrels per day in 2018, up from 492,000 barrels per day in 2017. Sales growth continues to be driven by optimization across the full downstream value chain, and the expansion of Imperial’s logistics capabilities.5548
COVID-19
pandemic, partially offset by lower refinery turnaround activity and reliability events, including impacts from the Sarnia fractionation tower incident which occurred in April 2019. Petroleum product sales were 421,000 barrels per day in 2020, compared to 475,000 barrels per day in 2019. Lower petroleum product sales were primarily driven by reduced demand due to theCOVID-19
pandemic.
2019
Refinery throughput averaged 353,000 barrels per day in 2019, compared to 392,000 barrels per day in 2018. Capacity utilization was 83 percent, compared to 93 percent in 2018. Reduced throughput was mainly due to higher planned turnaround activities and impacts from the Sarnia fractionation tower incident. Petroleum product sales were 475,000 barrels per day in 2019, compared to 504,000 barrels per day in 2018. Lower petroleum product sales were mainly due to lower refinery throughput.
Chemical | ||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Net income (loss) | 78 | 108 | 275 | |||||||||
Sales | ||||||||||||
| thousands of tonnes | 2020 | 2019 | 2018 | |||||||||
Polymers and basic chemicals | 574 | 575 | 602 | |||||||||
Intermediate and others | 175 | 157 | 205 | |||||||||
Total petrochemical sales | 749 | 732 | 807 | |||||||||
Chemical net income was $78 million in 2020, compared to $108 million in 2019, primarily reflecting lower margins.
| millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Net income (loss) | 108 | 275 | 235 | |||||||||
| thousands of tonnes | 2019 | 2018 | 2017 | |||||||||
Polymers and basic chemicals | 575 | 602 | 564 | |||||||||
Intermediate and others | 157 | 205 | 210 | |||||||||
Total petrochemical sales | 732 | 807 | 774 | |||||||||
2019
Chemical net income was $108 million in 2019, compared to $275 million in 2018, primarily due to lower margins.
Corporate and other | ||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Net income (loss) | (170 | ) | (217 | ) | (189 | ) | ||||||
2020
Corporate and other | ||||||||||||
| millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Net income (loss) | (217 | ) | (189 | ) | (79 | ) | ||||||
2019
Corporate and other expenses were $217 million in 2019, compared to $189 million in 2018.
Liquidity and capital resources
Sources and uses of cash
| millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Cash provided by (used in) | ||||||||||||
Operating activities | 4,429 | 3,922 | 2,763 | |||||||||
Investing activities | (1,704 | ) | (1,559 | ) | (781 | ) | ||||||
Financing activities | (1,995 | ) | (2,570 | ) | (1,178 | ) | ||||||
Increase (decrease) in cash and cash equivalents | 730 | (207 | ) | 804 | ||||||||
Cash and cash equivalents at end of year | 1,718 | 988 | 1,195 | |||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Cash provided by (used in) | ||||||||||||
Operating activities | 798 | 4,429 | 3,922 | |||||||||
Investing activities | (802 | ) | (1,704 | ) | (1,559 | ) | ||||||
Financing activities | (943 | ) | (1,995 | ) | (2,570 | ) | ||||||
Increase (decrease) in cash and cash equivalents | (947 | ) | 730 | (207 | ) | |||||||
Cash and cash equivalents at end of year | 771 | 1,718 | 988 | |||||||||
The company issues long-term debt from time to time and maintains a commercial paper program. However, internally generated funds cover the majority of its financial requirements. Cash that may be temporarily surplus to the company’s immediate needs is carefully managed through counterparty quality and investment guidelines to ensure that it is secure and readily available to meet the company’s cash requirements and to optimize returns.
Cash flows from operating activities are highly dependent on crude oil and natural gas prices, as well as petroleum and chemical product margins. In addition, to provide for cash flow in future periods, the company needs to continually find and develop new resources, and continue to develop and apply new technologies to existing fields in order to maintain or increase production.
The company’s financial strength enables it to make large, long-term capital expenditures. Imperial’s portfolio of development opportunities and the complementary nature of its business segments help mitigate the overall risks for the company and its cash flows. Further, due to its financial strength, debt capacity and portfolio of opportunities, the risk associated with 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.
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 completed at least once every three years depending on funding status. The most recent valuation of the company’s registered retirement plans was completed as at December 31, 2016. A valuation of the company’s registered retirement plans as at December 31, 2019 is expected to be completed in 2020.2019. The company contributed $211$195 million to the registered retirement plans in 2019.2020. Future funding requirements are not expected to affect the company’s existing capital investment plans or its ability to pursue new investment opportunities.
Cash flow from operating activities
2020
Cash flow generated from operating activities was $798 million in 2020, compared to $4,429 million in 2019, primarily reflecting lower realizations in the Upstream and unfavourable working capital impacts.
2019
Cash flow generated from operating activities was $4,429 million in 2019, up from $3,922 million in 2018, primarily reflecting favourable working capital effects, partially offset by lower earnings excluding the impact associated with the Alberta corporate income tax rate decrease.
Cash flow from investing activities
2020
Investing activities used net cash of $802 million in 2020, compared to $1,704 million used in 2019, primarily reflecting lower additions to property, plant and equipment.
2019
Investing activities used net cash of $1,704 million in 2019, compared with $1,559 million used in 2018, primarily reflecting higher additions to property, plant and equipment.
Cash flow from financing activities
2020
Cash used in financing activities was $943 million in 2020, compared to $1,995 million used in 2019.
At the end of 2020, total debt outstanding was $5,184 million, compared with $5,190 million at the end of 2019.
In response to market conditions, during the second quarter of 2020, the company entered into a $500 million committed short-term line of credit to May 2021, and a $300 million committed short-term line of credit to June 2021. These facilities were in addition to existing credit facilities of $500 million. The company has not drawn on these facilities.
In November 2020, the company extended the maturity date of one of its existing $250 million committed short-term line of credit to November 2021. The company has not drawn on the facility.
The maturity date of the other existing $250 million credit facility remains unchanged at November 2021. The company has not drawn on the facility.
During 2020, the company, under its share purchase program, purchased about 9.8 million shares for $274 million. In response to market conditions, substantial purchases under the share purchase program were suspended on April 1, 2020.
Dividends paid in 2020 were $649 million. The per share dividend paid in 2020 was $0.88, up from $0.82 in 2019.
2019
Cash used in financing activities was $1,995 million in 2019, compared with $2,570 million used in 2018.
At the end of 2019, total debt outstanding was $5,190 million, compared with $5,180 million at the end of 2018.
In September 2019, the company extended the maturity date of its existing long-term, variable-rate, Canadian dollar loan from ExxonMobil to June 30, 2025. All other terms and conditions remained unchanged.
In November 2019, the company increased the capacity of its
non-interest
bearing, revolving demand loan with ExxonMobil from $75 million to $150 million. The loan represents ExxonMobil’s share of a working capital facility required to support purchasing, marketing, transportation and derivative arrangements for crude oil and diluent products undertaken by Imperial on behalf of ExxonMobil. At December 31, 2019 the company had borrowed $111 million under this arrangement.In November 2019, the company extended the maturity date of its existing $250 million committed long-term line of credit to November 2021. The company has not drawn on the facility.
In December 2019, the company extended the maturity date of its existing $250 million committed short-term line of credit to December 2020. The company has not drawn on the facility.
During 2019, the company, under its share purchase program, purchased about 38.7 million shares for $1,373 million, including shares purchased from Exxon Mobil Corporation.
Dividends paid in 2019 were $631 million. The per share dividend paid in 2019 was $0.82, up from $0.70 in 2018.
Financial strength
The table below shows Imperial’s consolidatedratio. The data demonstrates the company’s creditworthiness:
debt-to-capital
| percent | ||||||||||||||||||||||||
| At December 31 | 2019 | 2018 | 2017 | 2020 | 2019 | 2018 | ||||||||||||||||||
Debt to capital (a) | 18 | 18 | 18 | 19 | 18 | 18 | ||||||||||||||||||
| (a) | Debt, defined as the sum of |
Debt-related interest incurred in 2019,2020, before capitalization of interest, was $138$102 million, compared with $133$138 million in 2018.2019. The average effective interest rate on the company’s debt was 2.0 percent in 2020, compared with 2.7 percent in 2019, compared with 2.5 percent in 2018.2019.
The company’s financial strength represents a competitive advantage of strategic importance providing it the opportunity to readily access capital markets under 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, 2019.2020. It combines data from the Consolidated balance sheet and from individual notes to the consolidated financial statements, where appropriate.
| Payment due by period | Payment due by period | |||||||||||||||||||||||||||||||||||||||||||||||
| millions of Canadian dollars | Note reference | 2021 | 2022 | 2024 | 2026 and | Total | ||||||||||||||||||||||||||||||||||||||||||
| Note reference | 2020 | 2021 to 2022 | 2023 to 2024 | 2025 and beyond | Total | to 2023 | to 2025 | beyond | ||||||||||||||||||||||||||||||||||||||||
Long-term debt excluding finance lease obligations (a) | 15 | - | 4,447 | - | - | 4,447 | 15 | - | 4,447 | - | - | 4,447 | ||||||||||||||||||||||||||||||||||||
Operating and finance leases (b) | 14 | 194 | 203 | 119 | 1,116 | 1,632 | 14 | 152 | 174 | 117 | 1,080 | 1,523 | ||||||||||||||||||||||||||||||||||||
Firm capital commitments (c) | 217 | 111 | 66 | - | 394 | 133 | 20 | - | 162 | 315 | ||||||||||||||||||||||||||||||||||||||
Pension and other postretirement obligations (d) | 5 | 275 | 120 | 122 | 1,363 | 1,880 | 5 | 223 | 121 | 127 | 1,692 | 2,163 | ||||||||||||||||||||||||||||||||||||
Asset retirement obligations (e) | 6 | 76 | 64 | 47 | 1,213 | 1,400 | 6 | 60 | 175 | 172 | 1,267 | 1,674 | ||||||||||||||||||||||||||||||||||||
Other long-term purchase agreements (f) | 883 | 1,599 | 1,470 | 8,637 | 12,589 | 786 | 1,610 | 1,341 | 8,380 | 12,117 | ||||||||||||||||||||||||||||||||||||||
| (a) | Long-term debt includes a loan from an affiliated company of ExxonMobil of $4,447 million. The payment by period for the related party long-term loan is estimated based on the right of the related party to cancel the loan on at least 370 days advance written notice. |
| (b) | Minimum commitments for finance and operating leases, both commenced and non-commenced, are shown on an undiscounted basis. Leases are primarily associated with storage tanks, rail cars, marine vessels, transportation facilities and service agreements. |
| (c) | Firm capital commitments represent legally-binding payment obligations to third parties where agreements specifying all significant terms have been executed for the construction and purchase of fixed assets and other permanent investments. In certain cases where the company executes contracts requiring commitments to a work scope, those commitments have been included to the extent that the amounts and timing of payments can be reliably estimated. Firm capital commitments related to capital projects are shown on an undiscounted basis. |
| (d) | The amount by which the benefit obligations exceeded the fair value of fund assets for pension and other postretirement plans at year end. The payments by period include expected contributions to funded pension plans in |
| (e) | Asset retirement obligations represent the fair value of legal obligations associated with site restoration on the retirement of assets with determinable useful lives. |
| (f) | Other long-term purchase agreements are non-cancelable, or cancelable only under certain conditions and long-term commitments other than unconditional purchase obligations. They include primarily transportation services agreements, raw material supply and community benefits agreements. |
Unrecognized tax benefits totalling $35$36 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 4 to the financial statements on page 78.
88.Litigation and other contingencies
As discussed in note 10 to the consolidated financial statements on page 87,98, a variety of claims have been made against Imperial 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, financial condition, or financial statements taken as a whole.
Additionally, as discussed in note 10, Imperial was contingently liable at December 31, 2019,2020, for guarantees relating to performance under contracts. These guarantees do not have a material effect on the company’s operations, financial condition, or financial statements taken as a whole.
There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.
Capital and exploration expenditures represent the combined total of additions at cost to property, plant and equipment; exploration expenses on a
before-tax
basis from the Consolidated statement of income; and the company’s share of similar costs for equity companies. Capital and exploration expenditures exclude the purchase of carbon emission credits. While Imperial’s management is responsible for all investments and elements of net income, particular focus is placed on managing the controllable aspects of this group of expenditures.| millions of Canadian dollars | 2019 | 2018 | 2020 | 2019 | ||||||||||||
Upstream (a) | 1,248 | 991 | 561 | 1,248 | ||||||||||||
Downstream | 484 | 383 | 251 | 484 | ||||||||||||
Chemical | 34 | 25 | 21 | 34 | ||||||||||||
Corporate and other | 48 | 28 | 41 | 48 | ||||||||||||
Total | 1,814 | 1,427 | 874 | 1,814 | ||||||||||||
(a) Exploration expenses included. | ||||||||||||||||
Total capital and exploration expenditures were $1,814$874 million in 2019, an increase2020, a decrease of $387$940 million from 2018.2019. In response to the challenges presented by the
COVID-19
pandemic and decreases in commodity prices, in the first quarter of 2020 the company provided an updated capital outlook of $1.1 billion to $1.2 billion (from original guidance of $1.6 billion to $1.7 billion). In the third quarter of 2020, the company further updated this capital outlook to about $900 million.For the Upstream segment, capital and exploration expenditures were $561 million in 2020, compared with $1,248 million in 2019, compared with $991 million in 2018.2019. Investments were primarily related to growth activities including investmentsustaining activity in supplemental crushing capacity at Kearl, further developmentsupport of unconventional assets, and expenditures on the Aspencompany’sproject.and oil sands assets.
in-situ
For the Downstream segment, capital expenditures were $251 million in 2020, compared with $484 million in 2019, compared with $383 million in 2018.2019. Investments were primarily in support offor enhancing the company’s distribution network as well as refinery projects to improve reliability, feedstock flexibility, energy efficiency and environmental performance.
Total capital and exploration expenditures are expected to range between $1.6 billion to $1.7be approximately $1.2 billion in 2020.2021. Actual spending could vary depending on the progress of individual projects.
Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied.
Imperial’s earnings are influenced by North American crude oil benchmark prices as well as changes in the differentials between these benchmarks and western Canadian prices for light and heavy crude oil. Imperial’s integrated business model reduces the company’s risk from changes in commodity prices. For instance, when light and heavy differentials between North American crude benchmarks and western Canadian prices widen together, Imperial is able to mitigate the impact of widening differentials on the Upstream through integration with Downstream investments in refineries, pipeline commitments and the Edmonton rail terminal. As an example, the negative impact of a widening differential in the Upstream is more than offset by the benefit of lower feedstock costs in the Downstream.
At this time, Imperial is a net consumer of natural gas, used in Imperial’s Upstream operation and refineries. A decrease in the value of natural gas reduces Imperial’s operating expenses, thereby increasing Imperial’s earnings.
In the competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels on products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices in turn depend on global and regional supply / demand balances, inventory levels, refinery operations, import / export balances and weather.
Industry crude oil and natural gas commodity prices and petroleum and chemical product prices are commonly benchmarked in U.S. dollars. The majority of Imperial’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the Canadian / U.S. dollar exchange rate fluctuates, the company’s earnings will be affected.
Imperial is exposed to changes in interest rates, primarily on its debt which carries floating interest rates. The impact of a quarter percent change in interest rates affecting Imperial’s debt would not be material to earnings or cash flow or fair value.flow. Imperial has access to significant sources of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of financial requirements, supplemented by long-term and short-term debt as needed.
The company’s potential exposure to commodity price and margin, and Canadian / U.S. dollar exchange rate fluctuations is summarized in the earnings sensitivities table, which shows the estimated annual effect, under current conditions, on the company’s
after-tax
net income. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil and products, production and sales volumes, transportation capacity, costs and egress methods, and other factors. Accordingly, changes in benchmark prices for crude oil and crude oil differentials, and other factors listed in the table following, only provide broad indicators of changes in the earnings experienced in any particular period.Earnings sensitivities
(a)
millions of Canadian dollars, | ||||||||
One dollar (U.S.) per barrel increase (decrease) in crude oil prices | + (-) | 110 | ||||||
One dollar (U.S.) per barrel increase (decrease) in light and heavy crude price differentials (b) | + (-) | 40 | ||||||
Ten cents per thousand cubic feet decrease (increase) in natural gas prices | + (-) | 9 | ||||||
One dollar (U.S.) per barrel increase (decrease) in refining 2-1-1 (c) | + (-) | 140 | ||||||
One cent (U.S.) per pound increase (decrease) in sales margins for polyethylene | + (-) | 7 | ||||||
One cent decrease (increase) in the value of the Canadian dollar versus the U.S. dollar | + (-) | 90 | ||||||
| (a) | Each sensitivity calculation shows the impact on net income resulting from a change in one factor, after-tax and royalties and holding all other factors constant. These sensitivities have been updated to reflect current market conditions. They may not apply proportionately to larger fluctuations. |
| (b) | Light and heavy crude differentials represent the difference between WTI benchmark prices and western Canadian prices for light and heavy crudes. |
| (c) | The 2-1-1 |
The demand for crude oil, natural gas, petroleum products and petrochemical products are generally linked closely with economic growth. The occurrence of recessions or other periods of low or negative economic growth, such as impacts due to themedium termmedium-term due to global economic conditions, political events, decisions by OPEC, governments and other factors, industry economics over the long termlong-term will continue to be driven by market supply and demand. Accordingly, the company evaluates the viability of its major investments over a range of prices.
COVID-19
pandemic, will typically have a direct adverse impact on the company’s financial results. Although price levels of crude oil and natural gas may rise and fall significantly over the short to The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the company’s businesses. Such conditions, along with the capital-intensive nature of the industry and very long lead times associated with many of the company’s projects, underscore the importance of maintaining a strong financial position. Management views the company’s financial strength as a competitive advantage.
In general, segment results are not dependent on the ability to sell and / or purchase products to / from other segments. Where such intersegment sales take place, they are the result of efficiencies and competitive advantages from integrated business segments and refinery and chemical complexes. The company’s intersegment sales include crude oil produced by the Upstream and sold to the Downstream, as well as sales between refineries and the chemical plant related to raw materials, feedstocks and finished products. All intersegment sales are at market based prices. Refer to Note 3 for additional information on intersegment revenue.
The company has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment. The asset management program includes a disciplined, regular review to ensure that all assets are contributing to the company’s strategic objectives.
Risk management
The company’s size, strong capital structure and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the company’s enterprise-wide risk from changes in commodity prices and currency exchange rates. In addition, the company may use commodity-based contracts, including derivatives, to manage commodity price risk and for trading purposes. The company’s derivatives are not accounted for under hedge accounting. Credit risk associated with the company’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. No material market or credit risks to the company’s financial position, results of operations or liquidity exist as a result of the derivatives described in note 7 on page 85.95. The company maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity.
Critical accounting estimates
The company’s financial statements have been prepared in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). U.S. GAAP requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. The company’s accounting and financial reporting fairly reflect its business model involving exploration for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products. Imperial does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The company’s significant accounting policies are summarized in note 1 to the consolidated financial statements on page 70.79.
Oil and gas reserves
Evaluations of oil and natural gas reserves are important to the effective management of upstream assets. They are an integral part of investment decisions about oil and gas properties such as whether development should proceed.
The estimation of proved reserves,reserve volumes, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments, and detailed analysis of well information such as flow rates and reservoir pressures.pressures, and development and production costs, among other factors. The estimation of proved reserves is controlled by the company through long-standing approval guidelines. Reserves changes are made within a well-established, disciplined process driven by qualified geoscience and engineering professionals, assisted by the reserves management group which has 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 reserves targets to determine compensation. Key features of the reserves estimation process are covered in “Disclosure of reserves” in Item 1.
Oil and natural gas reserves include both proved and unproved reserves.
| · | Proved oil and natural gas reserves are determined in accordance with U.S. Securities and Exchange Commission (SEC) requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-day-of-the-month |
Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells and facilities with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion. Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific circumstances support a longer period of time.
The percentage of proved developed reserves was 8975 percent of total proved reserves at2019, unchanged2020, a reduction from 2018.89 percent in 2019. 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 and optimization of development projects, reservoir performance, regulatory approvals, government policy,policies, consumer preferences, royalty frameworks and significant changes in long-term oil and natural gas prices.price levels.
year-end
| · | Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered. |
63
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation oroil and natural gas prices andyear-end / or costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment / facility capacity.
re-evaluation
of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in the average offirst-day-of-the-month
At
year-end
2016, downward revisions of proved developed and undeveloped bitumen reserves were a result of low prices. The entire 2.5 billion barrels of bitumen at Kearl and approximately 0.2 billion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the U.S. Securities and Exchange Commission definition of proved reserves.At
year-end
2017, an additional 0.3 billion barrels of bitumen at Kearl and Cold Lake qualified as proved reserves resulting from improved prices in the year.As a result of improved prices in 2018, an additional 2.3 billion barrels of bitumen at Kearl qualified as proved reserves at
year-end
2018.In 2019, downward revisions to proved bitumen reserves were driven by technical and development plan updates at Kearl, resulting in a decrease of 0.2 billion barrels, partially offset by an increase of 0.1 billion barrels at Cold Lake associated with an end of field life change driven by pricing. Downward revisions to proved synthetic oil reserves were a result of higher royalty obligations at Syncrude driven by pricing. Changes to liquids and natural gas proved reserves were the result of updated development plans at the Montney and Duvernay unconventional assets and the divestment of conventional properties.
In 2020, downward revisions of proved bitumen reserves were a result of low prices. The 2.2 billion barrels of bitumen at Kearl and 0.6 billion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the U.S. Securities and Exchange Commission definition of proved reserves. Downward revisions to proved synthetic oil reserves were a result of lower prices, offset by the addition of proved undeveloped reserves associated with future development at Syncrude. Changes to the liquids and natural gas proved reserves were the result of updated development plans at the Montney and Duvernay unconventional assets and the divestment of conventional properties.
Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial. The company’s operating decisions andcompany does not expect its outlook for future production volumes are not impactedoperations to be affected by the downward revision of reported proved reserves as disclosed under the U.S. Securities and Exchange Commission (SEC) definition.
Unit-of-production
The calculation ofdepreciation is a critical accounting estimate that measures the depreciation of upstream assets. Oil and natural gas reserve quantitiesvolumes are used as the basis to calculatedepreciation rates for most upstream assets. Depreciation is calculated by taking the ratio of asset cost to total proved reserves or proved developed reserves applied to the actual cost of production. The volumes produced and asset cost are known, while proved reserves are based on estimates that are subject to some variability.
unit-of-production
unit-of-production
In the event that themethod does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the company uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life.
unit-of-production
To the extent that proved reserves for a property are substantiallymethod based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. This approach was applied in 2017 and 2018, with the corresponding effect on depreciation expense being immaterial when compared to prior periods. InThis approach will also be applied in 2021 and the effect of this approach is anticipated to be immaterial compared to 2020. For 2019 and 2020, all properties havehad sufficient reserves at currenttheir relevant SEC prices which will enableenabled equitable allocation of cost over the economic lives of the Upstream assets. The effect of this approach compared to prior periods is immaterial.
de-booked
and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using aunit-of-production
Impact of oil and gas reserves and prices and margins on testing for impairment
The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:
| · | A significant decrease in the market price of a long-lived asset; |
| · | A significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in the company’s current and projected reserve volumes; |
| · | A significant adverse change in legal factors or in the business climate that could affect the value, including a significant adverse action or assessment by a regulator; |
| · | An accumulation of project costs significantly in excess of the amount originally expected; |
| · | A current-period operating loss combined with a history and forecast of operating or cash flow losses; and |
| · | A current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. |
Asset valuation analysis, profitability reviews and other periodic control processes assist Imperial in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable.
In general, Imperial does not view temporarily low prices or margins as an indication of impairment. Management believes prices over the long-termlong term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long-termlong term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments and technological and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities and levels of prosperity. Because the lifespans of the company’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and development and production costs. During the lifespan of these major assets, the company expects that oil and gas prices will experience significant volatility, and consequently these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether the events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the company considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are subject to wide fluctuations, longer termlonger-term price views are more stable and meaningful for purposes of assessing future cash flows.
When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the company’s long-term price or margin assumptions it uses for its capital investment decisions. To the extent those changes result in a significant reduction to its long-term oil prices or natural gas prices or margin ranges, the company may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, as an indicator of potential impairment for certain assets.
In the upstream, the standardized measure of discounted cash flows included in the “Supplemental information on oil and gas exploration and production activities” is required to use prices based on the yearly average ofprices. These prices represent discrete points in time and could be higher or lower than the company’s long-term price assumptions which are used for impairment assessments. The company believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment.
first-day-of-the-month
65
The company has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of, and relies on the company’s planning and budgeting cycle. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, 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. Cash flows used in recoverability assessments are based on the company’s
ASC 360 and ASC 932
assumptions which are developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the company’s assumptions of future capital allocations, crude oil and natural gas commodity prices, including price differentials, refining and chemical margins, volumes, development and operating costs, foreign currency exchange rates and inflation rates. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow estimates for impairment testing exclude the effects of derivative instruments.
An asset group is impaired if its estimated future undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. FairThe assessment of fair value ismay be based on market prices if an active market exists for the asset group or may require the use of Level 3 inputs and assumptions that are based upon the views of a likely market participant. The principal parameters used to establish fair value can include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows using a discount rate commensurateflows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, commodity prices which are consistent with the risk. average of third-party industry experts and government agencies, drilling and development costs, and discount rates.
Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs would be recorded based on the company’s future development plans, the estimated economic chance of success and the length of time that the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.
In 2020, events or changes in circumstances indicated that the carrying amount of certain of the company’s long-lived assets may not be recoverable. Those situations primarily related to the annual review and approval of the company’s business and strategic plan. As part of this process the company assessed its full portfolio of assets which included its unconventional assets. Subsequently the company announced its decision to not further develop a significant portion of its unconventional portfolio in Alberta which resulted in a non-cash, after-tax impairment charge of $1,171 million in the company’s 2020 Upstream results, thereby reducing the carrying value of those assets to fair value. For certain other upstream properties, the undiscounted cash flows were compared to the carrying values and no other adjustments were necessary.
Factors which could put further assets at risk of impairment in the future include reductions in the company’s price outlooks, changes in the allocation of capital, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price increases. However, due to the inherent difficulty in predicting future commodity prices, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the company’s long-lived assets.
Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements.
66
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 4.5 percent used in 2019,2020, compares to actual returns of 8.18.4 percent and 6.66.9 percent achieved over the last2019.2020. If different assumptions are used, the obligation and expense could increase or decrease as a result. As an indication of the company’s potential exposure to changes in the critical assumptions such as the expected rate of return on plan assets and the discount rate for measuring the benefits obligation, a reduction of 1 percent in the discount rate would increase the plan benefits obligation by approximately $1,820 million.$2.2 billion. Similarly, a reduction of 1 percent in the long-term rate of return on plan assets would increase the annual pension expense by approximately $75$85 million before tax. 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 average remaining service life of employees. Employee benefits expense represented about 12 percent of total expenses in 2019.2020.
10-
and20-year
periods respectively, ending December 31, 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 production and manufacturing expenses. 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 2019,2020, the obligations were discounted at 6 percent and the accretion expense was $80$82 million, before tax,
before-tax,
which was significantly less than 1 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.
Suspended exploratory well costs
The company continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and 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. The facts and circumstances that support continued capitalization of suspended wells at93.104.
year-end
are disclosed in note 16 to the consolidated financial statements on page 67
Tax contingencies
The operations of the company are complex, and related tax interpretations, regulations and legislation are continually changing. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.
The benefits of uncertain tax positions that the company has taken or expects to take in its income tax returns are 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 or expected to be 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 4 to the consolidated financial statements starting on page 78.
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 criteria established in issued 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, 2019.2020.
Internal Control – Integrated Framework (2013)
PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the company’s internal control over financial reporting as of December 31, 2019,2020, as stated in their report which is included herein.
/s/ Bradley W. Corson
B.W. Corson
Chairman, president and
chief executive officer
/s/ Daniel E. Lyons
D.E. Lyons
Senior vice-president,
finance and administration, and controller
(Principal accounting officer and principal financial officer)
February 26, 2020
24, 2021
To the Board of Directors and Shareholders of Imperial Oil Limited
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Imperial Oil Limited and its subsidiaries (together, the Company) as of December 31, 20192020 and 2018,2019, and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2019,2020, including the related notes (collectively referred to as the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2019,2020, based on criteria established in(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
Internal Control – Integrated Framework
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 20192020 and 2018,2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 20192020 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2020, based on criteria established in(2013) issued by the COSO.
Internal Control – Integrated Framework
Basis for Opinions
The Company’s management is responsible for these consolidated financial statements, 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 opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
70
Definition and Limitations of Internal Control over Financial Reporting
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.
Critical Audit Matters
The critical audit mattermatters communicated below is a matterare matters arising from the current period audit of the consolidated financial statements that waswere communicated or required to be communicated to the audit committee and that (i) relatesrelate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit mattermatters below, providing a separate opinionopinions on the critical audit mattermatters or on the accounts or disclosures to which it relates.they relate.
The impact of proved oil and natural gas reserves on upstream property, plant and equipment, net
As described in Notes 1 and 3 to the consolidated financial statements, the Company’s upstream property, plant and equipment (PP&E), net balance net was $31.2 billion$28,907 million as of December 31, 2019,2020, and the related depreciation depletion and amortization (DD&A)depletion expense for the year ended December 31, 20192020 was $1.4 billion.$3,084 million. Management uses the successful efforts method to account for its exploration and production activities. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. As disclosed by management, proved oil and natural gas reserves quantitiesreserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. The estimation of proved oil and natural gas reservesreserve volumes is an ongoing process based on technical evaluations, commercial and market assessments, and detailed analysis of well information such as flow rates and reservoir pressures, and development and production costs, among other factors. As further disclosed by management, has disclosed, reserves changes are made within a well-established, disciplined process driven by qualified geoscience and engineering professionals, assisted by the Reserves Management Groupreserves management group (together management’s specialists).
71
The principal considerationconsiderations for our determination that performing procedures relating to the impact of proved oil and natural gas reserves on upstream PP&E, net is a critical audit matter is that there wasare (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved oil and natural gas reserves. Thisreserve volumes, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence obtained related to the significantdata, methods, and assumptions used by management includingand its specialists in developing the estimates of proved oil and natural gas reserve volumes, and the assumptions related to development costs and production volumes.costs, as applicable.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and natural gas reserves and the calculation of DD&A expense. These procedures also included, among others (i) testing the completeness, accuracy, and relevance of underlying data used in developing management’s estimates, (ii) evaluating the significant assumptions used by management in developing these estimates, including development costs and production volumes, and (iii) testing the unit-of-production rates used to calculate DD&A expense.reserve volumes. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved oil and natural gas reserves.reserve volumes. As a basis for using this work, themanagement’s specialists’ qualifications and objectivity were understood as well asand the Company’s relationship with management’s specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists. The procedures performed also includedmanagement’s specialists, tests of the data used by management’s specialists, and an evaluation of themanagement’s specialists’ findings. EvaluatingThese procedures also included, among others, testing the significant assumptions relating to the estimates of proved oilcompleteness and natural gas reserves also involved obtaining evidence to support the reasonablenessaccuracy of the assumptions, includingdata related to future development and production costs. Additionally, these procedures included evaluating whether the assumptions usedrelated to development and production costs were reasonable considering the past performance of the Company and whether they were consistent with evidence obtainedits business and strategic plan, as applicable.
Impairment assessment of certain upstream property, plant and equipment, net
As described in other areasNotes 1 and 3 to the consolidated financial statements, the Company’s upstream property, plant and equipment (PP&E), net balance was $28,907 million as of December 31, 2020. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, management estimates the future undiscounted cash flows of the audit.affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of cash flows of other groups of assets. These estimates of the future undiscounted cash flows make use of management’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, upstream production volumes, development and operating costs, foreign currency exchange rates and inflation rates. Management’s estimate of upstream production volumes used for undiscounted cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. As further disclosed by management, estimates of upstream production volumes are made within a well-established, disciplined process driven by qualified geoscience and engineering professionals, assisted by the reserves management group (together management’s specialists). An asset group is impaired if its estimated undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value.
The principal considerations for our determination that performing procedures relating to the impairment assessment of certain upstream PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of future undiscounted cash flows, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to crude oil and natural gas commodity prices including price differentials, upstream production volumes, and development costs, as applicable.
72
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s upstream PP&E, net impairment assessment over proved properties. These procedures also included, among others (i) testing management’s process for assessing the recoverability of carrying amounts of upstream PP&E, net; (ii) evaluating the appropriateness of the undiscounted cash flow models; (iii) testing the completeness and accuracy of underlying data used in the models; and (iv) evaluating the reasonableness of significant assumptions used by management related to crude oil and natural gas commodity prices including price differentials, upstream production volumes, and development costs. Evaluating the reasonableness of management’s assumptions related to future crude oil and natural gas commodity prices including price differentials involved comparing the assumption against observable market data. Evaluating development costs involved evaluating the reasonableness of the assumptions as compared to the past performance of the Company and its business and strategic plan. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of upstream production volumes. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with management’s specialists was assessed. The procedures performed also included evaluation of the methods and assumptions used by management’s specialists, tests of the data used by management’s specialists, and an evaluation of management’s specialists’ findings.
/s/
PricewaterhouseCoopers LLP
Chartered Professional Accountants
Calgary, Canada
February 26, 202024, 2021
We have served as the Company’s auditor since 1934.
Consolidated statement of income (U.S. GAAP)
millions of Canadian dollars | ||||||||||||||
For the years ended December 31 | 2019 | 2018 | 2017 | |||||||||||
Revenues and other income | ||||||||||||||
Revenues (a) | 34,002 | 34,964 | 29,125 | |||||||||||
Investment and other income (note 9) | 99 | 135 | 299 | |||||||||||
Total revenues and other income | 34,101 | 35,099 | 29,424 | |||||||||||
Expenses | ||||||||||||||
Exploration (note 16) | 47 | 19 | 183 | |||||||||||
Purchases of crude oil and products (b) | 20,946 | 21,541 | 18,145 | |||||||||||
Production and manufacturing (c) | 6,520 | 6,121 | 5,586 | |||||||||||
Selling and general (c) | 900 | 908 | 883 | |||||||||||
Federal excise tax and fuel charge | 1,808 | 1,667 | 1,673 | |||||||||||
Depreciation and depletion | 1,598 | 1,555 | 2,172 | |||||||||||
Non-service pension and postretirement benefit | 143 | 107 | 122 | |||||||||||
Financing (d) (note 13) | 93 | 108 | 78 | |||||||||||
Total expenses | 32,055 | 32,026 | 28,842 | |||||||||||
Income (loss) before income taxes | 2,046 | 3,073 | 582 | |||||||||||
Income taxes (note 4) | (154 | ) | 759 | 92 | ||||||||||
Net income (loss) | 2,200 | 2,314 | 490 | |||||||||||
Per share information (Canadian dollars) | ||||||||||||||
Net income (loss) per common share - basic (note 11) | 2.88 | 2.87 | 0.58 | |||||||||||
Net income (loss) per common share - diluted (note 11) | 2.88 | 2.86 | 0.58 | |||||||||||
(a) | Amounts from related parties included in revenues, (note 17). | 8,569 | 6,383 | 4,110 | ||||||||||
(b) | Amounts to related parties included in purchases of crude oil and products, (note 17). | 3,305 | 4,092 | 2,687 | ||||||||||
(c) | Amounts to related parties included in production and manufacturing, and selling and general expenses, (note 17). | 628 | 566 | 544 | ||||||||||
(d) | Amounts to related parties included in financing, (note 17). | 98 | 89 | 60 | ||||||||||
| millions of Canadian dollars | ||||||||||||||
| For the years ended December 31 | 2020 | 2019 | 2018 | |||||||||||
Revenues and other income | ||||||||||||||
Revenues (a) | 22,284 | 34,002 | 34,964 | |||||||||||
Investment and other income (note 9) | 104 | 99 | 135 | |||||||||||
Total revenues and other income | 22,388 | 34,101 | 35,099 | |||||||||||
Expenses | ||||||||||||||
Exploration (note 16) | 13 | 47 | 19 | |||||||||||
Purchases of crude oil and products (b) | 13,293 | 20,946 | 21,541 | |||||||||||
Production and manufacturing (c) (note 12) | 5,535 | 6,520 | 6,121 | |||||||||||
Selling and general (c) | 741 | 900 | 908 | |||||||||||
Federal excise tax and fuel charge | 1,736 | 1,808 | 1,667 | |||||||||||
Depreciation and depletion (includes impairments) (note 3, 12) | 3,293 | 1,598 | 1,555 | |||||||||||
Non-service pension and postretirement benefit | 121 | 143 | 107 | |||||||||||
Financing (d) (note 13) | 64 | 93 | 108 | |||||||||||
Total expenses | 24,796 | 32,055 | 32,026 | |||||||||||
Income (loss) before income taxes | (2,408 | ) | 2,046 | 3,073 | ||||||||||
Income taxes (note 4) | (551 | ) | (154 | ) | 759 | |||||||||
Net income (loss) | (1,857 | ) | 2,200 | 2,314 | ||||||||||
Per share information (Canadian dollars) | ||||||||||||||
Net income (loss) per common share - basic (note 11) | (2.53 | ) | 2.88 | 2.87 | ||||||||||
Net income (loss) per common share - diluted (note 11) | (2.53 | ) | 2.88 | 2.86 | ||||||||||
(a) | Amounts from related parties included in revenues, (note 17). | 5,107 | 8,569 | 6,383 | ||||||||||
(b) | Amounts to related parties included in purchases of crude oil and products, (note 17). | 2,484 | 3,305 | 4,092 | ||||||||||
(c) | Amounts to related parties included in production and manufacturing, and selling and general expenses, (note 17). | 579 | 628 | 566 | ||||||||||
(d) | Amounts to related parties included in financing, (note 17). | 61 | 98 | 89 | ||||||||||
The information in the notes to consolidated financial statements is an integral part of these statements.
74
Consolidated statement of comprehensive income (U.S. GAAP)
| millions of Canadian dollars | ||||||||||||
| For the years ended December 31 | 2020 | 2019 | 2018 | |||||||||
Net income (loss) | (1,857 | ) | 2,200 | 2,314 | ||||||||
Other comprehensive income (loss), net of income taxes | ||||||||||||
Postretirement benefits liability adjustment (excluding amortization) | (212 | ) | (505 | ) | 158 | |||||||
Amortization of postretirement benefits liability adjustment included in net periodic benefit costs | 134 | 111 | 140 | |||||||||
Total other comprehensive income (loss) | (78 | ) | (394 | ) | 298 | |||||||
Comprehensive income (loss) | (1,935 | ) | 1,806 | 2,612 | ||||||||
The information in the notes to consolidated financial statements is an integral part of these statements.
75
Consolidated balance sheet (U.S. GAAP)
| millions of Canadian dollars | ||||||||
| At December 31 | 2020 | 2019 | ||||||
Assets | ||||||||
Current assets | ||||||||
Cash | 771 | 1,718 | ||||||
Accounts receivable - net (a) (note 2) | 1,919 | 2,699 | ||||||
Inventories of crude oil and products (note 12) | 1,161 | 1,296 | ||||||
Materials, supplies and prepaid expenses | 673 | 616 | ||||||
Total current assets | 4,524 | 6,329 | ||||||
Investments and long-term receivables (b) (note 2) | 781 | 891 | ||||||
Property, plant and equipment, | ||||||||
less accumulated depreciation and depletion | 32,034 | 34,203 | ||||||
Goodwill (note 12) | 166 | 186 | ||||||
Other assets, including intangibles - net | 526 | 578 | ||||||
Total assets | 38,031 | 42,187 | ||||||
Liabilities | ||||||||
| Current liabilities | ||||||||
Notes and loans payable (c) (note 13) | 227 | 229 | ||||||
Accounts payable and accrued liabilities (a) (note 12) | 3,153 | 4,260 | ||||||
Income taxes payable | 0 | 106 | ||||||
| Total current liabilities | 3,380 | 4,595 | ||||||
| Long-term debt (d) (note 15) | 4,957 | 4,961 | ||||||
| Other long-term obligations (note 6) | 4,100 | 3,637 | ||||||
| Deferred income tax liabilities (note 4) | 4,176 | 4,718 | ||||||
Total liabilities | 16,613 | 17,911 | ||||||
Commitments and contingent liabilities (note 10) | 0 | 0 | ||||||
Shareholders’ equity | ||||||||
| Common shares at stated value (e) (note 11) | 1,357 | 1,375 | ||||||
| Earnings reinvested | 22,050 | 24,812 | ||||||
| Accumulated other comprehensive income (loss) (note 18) | (1,989 | ) | (1,911 | ) | ||||
Total shareholders’ equity | 21,418 | 24,276 | ||||||
Total liabilities and shareholders’ equity | 38,031 | 42,187 | ||||||
| (a) | Accounts receivable - net included net amounts receivable from related parties of $384 million (2019 – $1,007 million), (note 17). |
| (b) | Investments and long-term receivables included amounts from related parties of $313 million (2019 – $296 million), (note 17). |
| (c) | Notes and loans payable included amounts to related parties of $111 million (2019 – $111 million), (note 17). |
| (d) | Long-term debt included amounts to related parties of $4,447 million (2019 – $4,447 million), (note 17). |
| (e) | Number of common shares authorized and outstanding were 1,100 million and 734 million, respectively (2019 – 1,100 million and 744 million, respectively), (note 11). |
The information in the notes to consolidated financial statements is an integral part of these statements.
/s/ Bradley W. Corson B.W. Corson Chairman, president and chief executive officer | /s/ Daniel E. Lyons D.E. Lyons Senior vice-president, finance and administration, and controller | |
76
Consolidated statement of comprehensive incomeshareholders’ equity (U.S. GAAP)
millions of Canadian dollars | ||||||||||||
For the years ended December 31 | 2019 | 2018 | 2017 | |||||||||
Net income (loss) | 2,200 | 2,314 | 490 | |||||||||
Other comprehensive income (loss), net of income taxes Postretirement benefits liability adjustment (excluding amortization) | (505 | ) | 158 | (54 | ) | |||||||
Amortization of postretirement benefits liability adjustment included in net periodic benefit costs | 111 | 140 | 136 | |||||||||
Total other comprehensive income (loss) | (394 | ) | 298 | 82 | ||||||||
Comprehensive income (loss) | 1,806 | 2,612 | 572 | |||||||||
millions of Canadian dollars | ||||||||||||
At December 31 | 2020 | 2019 | 2018 | |||||||||
Common shares at stated value (note 11) | ||||||||||||
At beginning of year | 1,375 | 1,446 | 1,536 | |||||||||
Share purchases at stated value | (18 | ) | (71 | ) | (90 | ) | ||||||
At end of year | 1,357 | 1,375 | 1,446 | |||||||||
Earnings reinvested | ||||||||||||
At beginning of year | 24,812 | 24,560 | 24,714 | |||||||||
Net income (loss) for the year | (1,857 | ) | 2,200 | 2,314 | ||||||||
Share purchases in excess of stated value | (256 | ) | (1,302 | ) | (1,881 | ) | ||||||
Dividends declared | (647 | ) | (646 | ) | (587 | ) | ||||||
Cumulative effect of accounting change (note 2) | (2 | ) | 0 | 0 | ||||||||
At end of year | 22,050 | 24,812 | 24,560 | |||||||||
Accumulated other comprehensive income (loss) (note 18) | ||||||||||||
At beginning of year | (1,911 | ) | (1,517 | ) | (1,815 | ) | ||||||
Other comprehensive income (loss) | (78 | ) | (394 | ) | 298 | |||||||
At end of year | (1,989 | ) | (1,911 | ) | (1,517 | ) | ||||||
Shareholders’ equity at end of year | 21,418 | 24,276 | 24,489 | |||||||||
The information in the notes to consolidated financial statements is an integral part of these statements.
77
millions of Canadian dollars | ||||||||
At December 31 | 2019 | 2018 | ||||||
Assets | ||||||||
Current assets | ||||||||
Cash | 1,718 | 988 | ||||||
Accounts receivable, less estimated doubtful accounts (a) | 2,699 | 2,529 | ||||||
Inventories of crude oil and products (note 12) | 1,296 | 1,297 | ||||||
Materials, supplies and prepaid expenses | 616 | 541 | ||||||
Total current assets | 6,329 | 5,355 | ||||||
Investments and long-term receivables (b) | 891 | 857 | ||||||
Property, plant and equipment, less accumulated depreciation and depletion | 34,203 | 34,225 | ||||||
Goodwill | 186 | 186 | ||||||
Other assets, including intangibles, net | 578 | 833 | ||||||
Total assets | 42,187 | 41,456 | ||||||
Liabilities | ||||||||
Current liabilities | ||||||||
Notes and loans payable (c) (note 13) | 229 | 202 | ||||||
Accounts payable and accrued liabilities (a) (note 12) | 4,260 | 3,688 | ||||||
Income taxes payable | 106 | 65 | ||||||
Total current liabilities | 4,595 | 3,955 | ||||||
Long-term debt (d) (note 15) | 4,961 | 4,978 | ||||||
Other long-term obligations (e) (note 6) | 3,637 | 2,943 | ||||||
Deferred income tax liabilities (note 4) | 4,718 | 5,091 | ||||||
Total liabilities | 17,911 | 16,967 | ||||||
Commitments and contingent liabilities (note 10) | ||||||||
Shareholders’ equity | ||||||||
Common shares at stated value (f) (note 11) | 1,375 | 1,446 | ||||||
Earnings reinvested | 24,812 | 24,560 | ||||||
Accumulated other comprehensive income (loss) (note 18) | (1,911 | ) | (1,517 | ) | ||||
Total shareholders’ equity | 24,276 | 24,489 | ||||||
Total liabilities and shareholders’ equity | 42,187 | 41,456 |
millions of Canadian dollars | ||||||||||||
At December 31 | 2018 | 2017 | ||||||||||
Common shares at stated value (note 11) | ||||||||||||
At beginning of year | 1,446 | 1,536 | 1,566 | |||||||||
Issued under the stock option plan | - | - | - | |||||||||
Share purchases at stated value | (71 | ) | (90 | ) | (30 | ) | ||||||
At end of year | 1,375 | 1,446 | 1,536 | |||||||||
Earnings reinvested | ||||||||||||
At beginning of year | 24,560 | 24,714 | 25,352 | |||||||||
Net income (loss) for the year | 2,200 | 2,314 | 490 | |||||||||
Share purchases in excess of stated value | (1,302 | ) | (1,881 | ) | (597 | ) | ||||||
Dividends declared | (646 | ) | (587 | ) | (531 | ) | ||||||
At end of year | 24,812 | 24,560 | 24,714 | |||||||||
Accumulated other comprehensive income (loss) (note 18) | ||||||||||||
At beginning of year | (1,517 | ) | (1,815 | ) | (1,897 | ) | ||||||
Other comprehensive income (loss) | (394 | ) | 298 | 82 | ||||||||
At end of year | (1,911 | ) | (1,517 | ) | (1,815 | ) | ||||||
Shareholders’ equity at end of year | 24,276 | 24,489 | 24,435 | |||||||||
millions of Canadian dollars | ||||||||||||
Inflow (outflow) | ||||||||||||
For the years ended December 31 | 2019 | 2018 | 2017 | |||||||||
Operating activities | ||||||||||||
Net income (loss) | 2,200 | 2,314 | 490 | |||||||||
Adjustments for non-cash items: | ||||||||||||
Depreciation and depletion | 1,598 | 1,509 | 2,172 | |||||||||
Impairment of intangible assets | - | 46 | - | |||||||||
(Gain) loss on asset sales (note 9) | (46 | ) | (54 | ) | (220 | ) | ||||||
Deferred income taxes and other | (237 | ) | 806 | 321 | ||||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable | (170 | ) | 224 | (689 | ) | |||||||
Inventories, materials, supplies and prepaid expenses | (74 | ) | (338 | ) | (83 | ) | ||||||
Income taxes payable | 41 | 8 | (431 | ) | ||||||||
Accounts payable and accrued liabilities | 1,010 | (764 | ) | 678 | ||||||||
All other items - net (a) (c) | 107 | 171 | 525 | |||||||||
Cash flows from (used in) operating activities | 4,429 | 3,922 | 2,763 | |||||||||
Investing activities | ||||||||||||
Additions to property, plant and equipment (a) | (1,636 | ) | (1,491 | ) | (993 | ) | ||||||
Proceeds from asset sales (note 9) | 82 | 59 | 232 | |||||||||
Additional investments | - | - | (1 | ) | ||||||||
Loan to equity company | (150 | ) | (127 | ) | (19 | ) | ||||||
Cash flows from (used in) investing activities | (1,704 | ) | (1,559 | ) | (781 | ) | ||||||
Financing activities | ||||||||||||
Short-term debt - net (note 13) | 36 | - | - | |||||||||
Reduction in finance lease obligations (note 15) | (27 | ) | (27 | ) | (27 | ) | ||||||
Dividends paid | (631 | ) | (572 | ) | (524 | ) | ||||||
Common shares purchased (note 11) | (1,373 | ) | (1,971 | ) | (627 | ) | ||||||
Cash flows from (used in) financing activities | (1,995 | ) | (2,570 | ) | (1,178 | ) | ||||||
Increase (decrease) in cash | 730 | (207 | ) | 804 | ||||||||
Cash at beginning of year | 988 | 1,195 | 391 | |||||||||
Cash at end of year (b) | 1,718 | 988 | 1,195 | |||||||||
(a) The impact of carbon emission programs are included inA dditions to property, plant and equipment, andA ll other items - net. | ||||||||||||
(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. | ||||||||||||
(c) Included contributions to registered pension plans. | (211 | ) | (203 | ) | (212 | ) | ||||||
Income taxes (paid) refunded. | 145 | (82 | ) | (231 | ) | |||||||
Interest (paid), net of capitalization. | (91 | ) | (110 | ) | (76 | ) | ||||||
millions of Canadian dollars | ||||||||||||
Inflow (outflow) | ||||||||||||
For the years ended December 31 | 2020 | 2019 | 2018 | |||||||||
Operating activities | ||||||||||||
Net income (loss) | (1,857 | ) | 2,200 | 2,314 | ||||||||
Adjustments for non-cash items: | ||||||||||||
Depreciation and depletion (includes impairments) (note 3) | 3,273 | 1,598 | 1,509 | |||||||||
Impairment of intangible assets (note 12) | 20 | 0 | 46 | |||||||||
(Gain) loss on asset sales (note 9) | (35 | ) | (46 | ) | (54 | ) | ||||||
Deferred income taxes and other | (521 | ) | (237 | ) | 806 | |||||||
Changes in operating assets and liabilities: | ||||||||||||
Accounts receivable | 780 | (170 | ) | 224 | ||||||||
Inventories, materials, supplies and prepaid expenses | 78 | (74 | ) | (338 | ) | |||||||
Income taxes payable | (106 | ) | 41 | 8 | ||||||||
Accounts payable and accrued liabilities | (1,087 | ) | 1,010 | (764 | ) | |||||||
All other items - net (b) | 253 | 107 | 171 | |||||||||
Cash flows from (used in) operating activities | 798 | 4,429 | 3,922 | |||||||||
Investing activities | ||||||||||||
Additions to property, plant and equipmen t | (868 | ) | (1,636 | ) | (1,491 | ) | ||||||
Proceeds from asset sales (note 9) | 82 | 82 | 59 | |||||||||
| Loans to equity companies - net | (16 | ) | (150 | ) | (127 | ) | ||||||
Cash flows from (used in) investing activities | (802 | ) | (1,704 | ) | (1,559 | ) | ||||||
Financing activities | ||||||||||||
Short-term debt - net (note 13) | 0 | 36 | 0 | |||||||||
Reduction in finance lease obligations (note 15) | (20 | ) | (27 | ) | (27 | ) | ||||||
Dividends paid | (649 | ) | (631 | ) | (572 | ) | ||||||
Common shares purchased (note 11) | (274 | ) | (1,373 | ) | (1,971 | ) | ||||||
Cash flows from (used in) financing activities | (943 | ) | (1,995 | ) | (2,570 | ) | ||||||
Increase (decrease) in cash | (947 | ) | 730 | (207 | ) | |||||||
Cash at beginning of year | 1,718 | 988 | 1,195 | |||||||||
Cash at end of year (a) | 771 | 1,718 | 988 | |||||||||
(a) 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. | ||||||
(b) Included contributions to registered pension plans. | (195 | ) | (211 | ) | (203 | ) | ||||||
| Income taxes (paid) refunded. | (42 | ) | 145 | (82 | ) | |||||||
| Interest (paid), net of capitalization. | (62 | ) | (91 | ) | (110 | ) | ||||||
Non-cash
transactionsIn 2019, the company removed $570$570 million of assets and corresponding liabilities associated with the Government of Ontario’s revocation of its cap and trade legislation. The impact of this removal was not reflected in “Accounts payable and accrued liabilities” and “All other items - net” lines on the Consolidated statement of cash flows as it was not a cash transaction.
The information in the notes to consolidated financial statements is an integral part of these statements.
The accompanying consolidated financial statements and the supporting and
a
nd supplemental material are the responsibility of the management of Imperial Oil Limited.The company’s principal business is energy, involving the exploration for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products.
The consolidated financial statements have been prepared in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP), which requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. Prior years’ data has been reclassified in certain cases to conform to the 20192020 presentation basis. All amounts are in Canadian dollars unless otherwise indicated.
Principles of consolidation
The consolidated financial statements include the accounts of subsidiaries the company controls. 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. Imperial Oil Resources Limited is the only significant subsidiary included in the consolidated financial statements and is wholly owned by Imperial Oil Limited. The consolidated financial statements also include the company’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses, including itsventure and its70.96 percent interest in the Kearl joint venture.
70.96 percent interest in the Kearl joint venture and its 25
percent interest in the Syncrude joint Revenues
Imperial generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases, products may be sold under long-term agreements, with periodic price adjustments to reflect market conditions.
Revenue is recognized at the amount the company expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when final information is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days.
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. 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.
Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility.
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.
“Revenues” and “Accounts receivable less estimated doubtful accounts”- net” primarily arise from contracts with customers. Long-term receivables are primarily from
non-customers.
Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments, loyalty programs and accruals of expected volume discounts, and are not significant.79
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, the federal goods and services tax and the federal/provincial harmonized sales tax.
Derivative instruments
Imperial,, firm commitmentsand forecasted transactions.
may
use derivative instrumentsfor
to offset exposures associated withtrading purposes and
commodity
prices,currency exchange rates and interest
that arise from existing assets, liabilities,interest rates
All derivative instruments, except those designated as normal purchase and normal sale, are recorded at fair value.
Derivative assets and liabilities with the same counterparty are netted if the right of offset exists and certain other criteria are met. Collateral payables or receivables are netted against derivative assets and derivative liabilities respectively.Recognition and classification of the gain or loss that results from adjusting a derivative to fair value depends on the purpose for the derivative. The gains and losses resulting from changes in the fair value of derivatives are recorded under “Revenues” or “Purchases of crude oil and products” onin the Consolidated statement of income.
Fair value
Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs other than quoted prices included within Level 1 that are directly or indirectly observable for the asset or liability. Hierarchy Level 3 inputs are inputs that are not observable in the market.
Inventories
Inventories are recorded at the lower of current market value or cost. The cost of crude oil and products is determined primarily using the
last-in,
first-out
(LIFO) method. LIFO was selected over the alternativefirst-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 location. Selling and general expenses are reported as period costs and excluded from inventory costs. Inventories of materials and supplies are valued at cost or less.
Investments
The company’s interests in the underlying net assets of affiliates it does not control, but over which it exercises significant influence, 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 investments is included in “Investment and other income” in the Consolidated statement of income. Investments in equity securities, other than consolidated subsidiaries and equity method investments, are measured at fair value, with changes in the fair value recognized in net income. The company uses a modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions in similar investment of the same issuer. Dividends from these investments are included in “Investment and other income”.These investments represent interests in
non-publicly
traded pipeline companies and a rail loading joint venture that facilitate the sale and purchase of liquids in the conduct of company operations. Other parties who also have an equity interest in these investments share in the risks and rewards according to their percentage of ownership. Imperial does not invest in these investments in order to remove liabilities from its balance sheet.80
Property, plant and equipment
Cost basis
Imperial uses the “successful efforts” method to account for its exploration and production activities. Under this method, costs are accumulated on abasis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where 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. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dryholes, are capitalized.
field-by-field
Maintenance and repair costs, including planned major maintenance, are expensed as incurred.i
n
curred. Improvements that increase or prolong the service life or capacity of an asset are capitalized.Depreciation, depletion and amortization
Depreciation, depletion and amortization are primarily determined under either themethod or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. 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.
unit-of-production
Acquisition costs of proved properties are amortized using areserves.reserve volumes. Capitalized
exploratory drilling and development costs associated with productive depletable extractive properties are amortized using theunit-of-production
method, computed on the basis of total proved oil and natural gas unit-of-production
unit-of-production
unit-of-production
15
years and50
years respectively. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset.To the extent that proved reserves for a property are substantiallymethod based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. This approach was applied in 2017 and 2018, with the corresponding effect on depreciation expense being immaterial when compared to the prior periods. InThis approach will also be applied in 2021 and the effect of this approach is anticipated to be immaterial compared to 2020. For 2019 and 2020, all properties havehad sufficient reserves at currenttheir relevant SEC prices which will enableenabled equitable allocation of cost over the economic lives of the Upstream assets. The effect of this approach compared to prior periods is anticipated to be immaterial.
de-booked
and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using aunit-of-production
Investments in refinery25-year25-yearlife. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired.
and
chemical process manufacturing equipment are generally depreciated on a straight-line basis over aImpairment assessment
The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:
● | A significant decrease in the market price of a long-lived asset; |
● | A significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in the company’s current and projected reserve volumes; |
● | A significant adverse change in legal factors or in the business climate that could affect the value, including a significant adverse action or assessment by a regulator; |
● | An accumulation of project costs significantly in excess of the amount originally expected; |
● | A current-period operating loss combined with a history and forecast of operating or cash flow losses; and |
● | A current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. |
Asset valuation analysis, profitability reviews and other periodic control processes assist Imperial in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable.
In general, Imperial does not view temporarily low prices or margins as an indication of impairment. Management believes prices over the long-termlong term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long-termlong term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments and technological and efficiency advancements. OPEC investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities and levels of prosperity. Because the lifespans of the company’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and development and production costs. During the lifespan of these major assets, the company expects that oil and gas prices will experience significant volatility, and consequently these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether the events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the company considers recent periods of operating losses in the context of its longer-term view of prices. While near-term prices are subject to wide fluctuations, longer termlonger-term price views are more stable and meaningful for purposes of assessing future cash flows.
When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the company’s long-term price or margin assumptions it uses for its capital investment decisions. To the extent those changes result in a significant reduction to its long-term oil prices or natural gas prices or margin ranges, the company may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, as an indicator of potential impairment for certain assets.
In the upstream, the standardized measure of discounted cash flows included in the “Supplemental information on oil and gas exploration and production activities” is required to use prices based on the yearly average ofprices. These prices represent discrete points in time and could be higher or lower than the company’s long-term price assumptions which are used for impairment assessments. The company believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment.
first-day-of-the-month
82
The company has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements ofand, and relies on the company’s planning and budgeting cycle. If
ASC 360
ASC
932
events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, 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. Cash flows used in recoverability assessments are based on the company’s assumptions which are developed in the annual planning and budgeting
process, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the company’s assumptions of future capital allocations, crude oil and natural gas commodity prices, including price differentials, refining and chemical margins, volumes, development and operating costs, foreign currency exchange rates and inflation rates. Volumes are based on projected field and facility production profiles, throughput,thr
o
ughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. Cash flow estimates for impairment testing exclude the effects of derivative instruments.An asset group is impaired if its estimated future undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the amount by which the carrying value exceeds fair value. FairThe assessment of fair value ismay be based on market prices if an active market exists for the asset group or may require the use of Level 3 inputs and assumptions that are based upon the views of a likely market participant. The principal parameters used to establish fair value can include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows using a discount rate commensurateflows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, commodity prices which are consistent with the risk. average of third-party industry experts and government agencies, drilling and development costs, and discount rates.
Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs would be recorded based on the company’s future development plans, the estimated economic chance of success and the length of time that the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.
Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any interest retained nor any substantial obligation for future performance by the company. Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.
Gains or losses on assets sold are included in “Investment and other income” in the Consolidated statement of income.
Interest capitalization
Interest costs incurred to finance expenditures during the construction phase of projects are capitalized as part of property, plant and equipment and are depreciated over the service life of the related assets. 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.
Leases
In situations where assets are leased, right of use assets and lease liabilities are established on the balance sheet for leases with an expected term greater than one year, by discounting the amounts fixed in the lease agreement for the duration of the lease which is reasonably certain, considering the probability of exercising any early termination and extension options. The portion of the fixed payment related to service costs for tankers and finance leases is excluded from the calculation of right of use assets and lease liabilities. Assets leased for nearly all of their useful lives are accounted for as finance leases. In general, leases are capitalized using the company’s incremental borrowing rate. See note 14 to the consolidated financial statements on page 90 102
for further details.
83
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 reclamation and remediation, and costs of abandonment and demolition of oil and gas wells and related facilities. The company uses estimates, assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, the credit-adjusted risk-free rate to be used, and inflation rates. 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
, marketing and office 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. 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. These provisions are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted.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.
Share-based compensation
The company awards share-based compensation to certain 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 on page 8697 for further details.
2. Accounting changes
Effective January 1, 2020, Imperialthe company adopted the Financial Accounting Standards Board’s update,(Topic 326), as amended. The standard requires a valuation allowance for credit losses be recognized for certain financial assets that reflects the current expected credit loss over the asset’s contractual life. The valuation allowance considers the risk of loss, even if remote, and considers past events, current conditions and expectations of the future.reasonable and suppoJanuary 1, 2020 estimatedstandard requires this expected loss methodology for trade receivables, certain other financial assets andrelatedin Shareholders’ equity by $2 million.
Financial Instruments -– Credit Losses (Topic 326),
r
table forecasts. The off-balance-sheet
credit exposures. The cumulative effect adjustment related to the adoption of this standard reduced “Earnings reinvested” The company is exposed to implementationcredit losses primarily through sales of petroleum products, crude oil, natural gas liquids and natural gas, as well as loans to equity companies and joint venture receivables. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms, the counterparty’s established credit rating or the company’s assessment of the Credit Losses standard is expectedcounterparty’s credit worthiness, contract terms, and other risks. The company can require prepayment or collateral to be de minimis.
At December 31, 2020, the company’s evaluation of financial assets under, as a rightamended, included
Financial Instruments – Credit Losses (Topic 326)
$
1,437 million of use assetaccounts receivable, net of allowances of $
4 million, and a lease liability.investments and long-term receivables of $
323 million. The company used a transition methodhas determined that, applies the new lease standard at January 1, 2019. Imperial applied a policy election to exclude short-term leases from balance sheet recognitionthis time,
0credit allowance is required for investments and also elected certain practical expedients at adoption. As permitted, the company did not reassess whether existing contracts are or contain leases, the lease classificationlong-term receivables, and for any existing leases, initial direct costs for any existing lease and whether existing land easements and rights of way, which were not previously accounted for as leases, are or contain a lease. At adoption on January 1, 2019, an operating lease liability of $298 million was recorded and the operating lease right of use asset was $298 million. There was no cumulative earnings effect adjustment.
off-balance-sheet
credit exposures.
85
3. Business segments
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 to distribute and market 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, capitalized interest costs, short-term borrowings, long-term debt and liabilities associated with incentive compensation, pension and other postretirement benefit liabilities. Net earnings effects under Corporate and other activities primarily include debt-related financing, corporate governance costs,
non-service
pension and postretirement benefit costs, share-based incentive compensation expenses and interest income.Segment accounting policies are the same as those described in the summary of significant accounting policies. Upstream, Downstream and Chemical expenses include amounts allocated from Corporate and other activities. The allocation is based on proportional segment expenses. 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.
86
| Upstream | Downstream | Chemical | ||||||||||||||||||||||||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||
Revenues and other income | ||||||||||||||||||||||||||||||||||||
Revenues (a) | 6,263 | 9,479 | 8,525 | 15,178 | 23,591 | 25,200 | 843 | 932 | 1,239 | |||||||||||||||||||||||||||
| Intersegment sales | 2,527 | 3,763 | 2,634 | 1,480 | 1,597 | 1,542 | 165 | 229 | 279 | |||||||||||||||||||||||||||
Investment and other income (note 9) | 7 | 17 | 11 | 78 | 47 | 95 | - | - | - | |||||||||||||||||||||||||||
8,797 | 13,259 | 11,170 | 16,736 | 25,235 | 26,837 | 1,008 | 1,161 | 1,518 | ||||||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||
Exploration (note 16) | 13 | 47 | 19 | - | - | - | - | - | - | |||||||||||||||||||||||||||
| Purchases of crude oil and products | 4,834 | 6,528 | 5,833 | 12,047 | 19,332 | 19,326 | 579 | 667 | 831 | |||||||||||||||||||||||||||
Production and manufacturing (note 12) | 3,852 | 4,440 | 4,305 | 1,468 | 1,829 | 1,606 | 215 | 251 | 210 | |||||||||||||||||||||||||||
| Selling and general | - | - | - | 619 | 774 | 773 | 92 | 86 | 87 | |||||||||||||||||||||||||||
| Federal excise tax and fuel charge | - | - | - | 1,736 | 1,808 | 1,667 | - | - | - | |||||||||||||||||||||||||||
Depreciation and depletion (b) (note 12) | 3,084 | 1,374 | 1,278 | 166 | 186 | 242 | 19 | 16 | 14 | |||||||||||||||||||||||||||
Non-service pension and postretirement benefit | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||
Financing (note 13) | 3 | 3 | 1 | - | - | 2 | - | - | - | |||||||||||||||||||||||||||
Total expenses | 11,786 | 12,392 | 11,436 | 16,036 | 23,929 | 23,616 | 905 | 1,020 | 1,142 | |||||||||||||||||||||||||||
Income (loss) before income taxes | (2,989 | ) | 867 | (266 | ) | 700 | 1,306 | 3,221 | 103 | 141 | 376 | |||||||||||||||||||||||||
Income tax expense (benefit) (c) (note 4) | (671 | ) | (481 | ) | (128 | ) | 147 | 345 | 855 | 25 | 33 | 101 | ||||||||||||||||||||||||
Net income (loss) | (2,318 | ) | 1,348 | (138 | ) | 553 | 961 | 2,366 | 78 | 108 | 275 | |||||||||||||||||||||||||
Cash flows from (used in) operating activities | 286 | 2,423 | 916 | 470 | 1,965 | 2,749 | 114 | 172 | 354 | |||||||||||||||||||||||||||
Capital and exploration expenditures (d) | 561 | 1,248 | 991 | 251 | 484 | 383 | 21 | 34 | 25 | |||||||||||||||||||||||||||
Property, plant and equipment | ||||||||||||||||||||||||||||||||||||
| Cost | 47,693 | 47,050 | 46,435 | 6,321 | 6,123 | 5,900 | 975 | 954 | 916 | |||||||||||||||||||||||||||
| Accumulated depreciation and depletion | (18,786 | ) | (15,889 | ) | (15,050 | ) | (3,962 | ) | (3,830 | ) | (3,763 | ) | (699 | ) | (680 | ) | (662 | ) | ||||||||||||||||||
Net property, plant and equipment (e) | 28,907 | 31,161 | 31,385 | 2,359 | 2,293 | 2,137 | 276 | 274 | 254 | |||||||||||||||||||||||||||
Total assets (f) (g) | 31,835 | 34,554 | 34,829 | 4,554 | 5,179 | 5,119 | 408 | 416 | 438 | |||||||||||||||||||||||||||
| Upstream | Downstream | Chemical | ||||||||||||||||||||||||||||||||||
| millions of Canadian dollars | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| Revenues and other income | ||||||||||||||||||||||||||||||||||||
Revenues (a) | 9,479 | 8,525 | 7,302 | 23,591 | 25,200 | 20,714 | 932 | 1,239 | 1,109 | |||||||||||||||||||||||||||
| Intersegment sales | 3,763 | 2,634 | 2,264 | 1,597 | 1,542 | 1,155 | 229 | 279 | 262 | |||||||||||||||||||||||||||
Investment and other income (note 9) | 17 | 11 | 16 | 47 | 95 | 269 | - | - | - | |||||||||||||||||||||||||||
| 13,259 | 11,170 | 9,582 | 25,235 | 26,837 | 22,138 | 1,161 | 1,518 | 1,371 | ||||||||||||||||||||||||||||
| Expenses | ||||||||||||||||||||||||||||||||||||
Exploration (b) (note 16) | 47 | 19 | 183 | - | - | - | - | - | - | |||||||||||||||||||||||||||
| Purchases of crude oil and products | 6,528 | 5,833 | 4,526 | 19,332 | 19,326 | 16,543 | 667 | 831 | 751 | |||||||||||||||||||||||||||
Production and manufacturing (c) | 4,440 | 4,305 | 3,913 | 1,829 | 1,606 | 1,576 | 251 | 210 | 209 | |||||||||||||||||||||||||||
Selling and general (c) | - | - | - | 774 | 773 | 772 | 86 | 87 | 78 | |||||||||||||||||||||||||||
| Federal excise tax and fuel charge | - | - | - | 1,808 | 1,667 | 1,673 | - | - | - | |||||||||||||||||||||||||||
Depreciation and depletion (b) (d) | 1,374 | 1,278 | 1,939 | 186 | 242 | 202 | 16 | 14 | 12 | |||||||||||||||||||||||||||
Non-service pension and postretirement benefit(c) | - | - | - | - | - | - | - | - | - | |||||||||||||||||||||||||||
Financing (note 13) | 3 | 1 | 13 | - | 2 | - | - | - | - | |||||||||||||||||||||||||||
| Total expenses | 12,392 | 11,436 | 10,574 | 23,929 | 23,616 | 20,766 | 1,020 | 1,142 | 1,050 | |||||||||||||||||||||||||||
| Income (loss) before income taxes | 867 | (266 | ) | (992 | ) | 1,306 | 3,221 | 1,372 | 141 | 376 | 321 | |||||||||||||||||||||||||
Income tax expense (benefit) (e) (note 4) | (481 | ) | (128 | ) | (286 | ) | 345 | 855 | 332 | 33 | 101 | 86 | ||||||||||||||||||||||||
| Net income (loss) | 1,348 | (138 | ) | (706 | ) | 961 | 2,366 | 1,040 | 108 | 275 | 235 | |||||||||||||||||||||||||
| Cash flows from (used in) operating activities | 2,423 | 916 | 1,257 | 1,965 | 2,749 | 1,396 | 172 | 354 | 235 | |||||||||||||||||||||||||||
Capital and exploration expenditures (f) | 1,248 | 991 | 416 | 484 | 383 | 200 | 34 | 25 | 17 | |||||||||||||||||||||||||||
| Property, plant and equipment | ||||||||||||||||||||||||||||||||||||
| Cost | 47,050 | 46,435 | 45,542 | 6,123 | 5,900 | 5,683 | 954 | 916 | 888 | |||||||||||||||||||||||||||
| Accumulated depreciation and depletion | (15,889 | ) | (15,050 | ) | (13,844 | ) | (3,830 | ) | (3,763 | ) | (3,594 | ) | (680 | ) | (662 | ) | (644 | ) | ||||||||||||||||||
Net property, plant and equipment (g) | 31,161 | 31,385 | 31,698 | 2,293 | 2,137 | 2,089 | 274 | 254 | 244 | |||||||||||||||||||||||||||
Total assets (h) (i) | 34,554 | 34,829 | 35,044 | 5,179 | 5,119 | 4,890 | 416 | 438 | 399 | |||||||||||||||||||||||||||
| Corporate and other | Eliminations | Consolidated | ||||||||||||||||||||||||||||||||||
| millions of Canadian dollars | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | |||||||||||||||||||||||||||
| Revenues and other income | ||||||||||||||||||||||||||||||||||||
Revenues (a) | - | - | - | - | - | - | 34,002 | 34,964 | 29,125 | |||||||||||||||||||||||||||
| Intersegment sales | - | - | - | (5,589 | ) | (4,455 | ) | (3,681 | ) | - | - | - | ||||||||||||||||||||||||
Investment and other income (note 9) | 35 | 29 | 14 | - | - | - | 99 | 135 | 299 | |||||||||||||||||||||||||||
| 35 | 29 | 14 | (5,589 | ) | (4,455 | ) | (3,681 | ) | 34,101 | 35,099 | 29,424 | |||||||||||||||||||||||||
| Expenses | ||||||||||||||||||||||||||||||||||||
Exploration (b) (note 16) | - | - | - | - | - | - | 47 | 19 | 183 | |||||||||||||||||||||||||||
| Purchases of crude oil and products | - | - | - | (5,581 | ) | (4,449 | ) | (3,675 | ) | 20,946 | 21,541 | 18,145 | ||||||||||||||||||||||||
Production and manufacturing (c) | - | - | - | - | - | - | 6,520 | 6,121 | 5,698 | |||||||||||||||||||||||||||
Selling and general (c) | 48 | 54 | 49 | (8 | ) | (6 | ) | (6 | ) | 900 | 908 | 893 | ||||||||||||||||||||||||
| Federal excise tax and fuel charge | - | - | - | - | - | - | 1,808 | 1,667 | 1,673 | |||||||||||||||||||||||||||
Depreciation and depletion (b) (d) | 22 | 21 | 19 | - | - | - | 1,598 | 1,555 | 2,172 | |||||||||||||||||||||||||||
Non-service pension and postretirement benefit(c) | 143 | 107 | - | - | - | - | 143 | 107 | - | |||||||||||||||||||||||||||
Financing (note 13) | 90 | 105 | 65 | - | - | - | 93 | 108 | 78 | |||||||||||||||||||||||||||
Total expenses | 303 | 287 | 133 | (5,589 | ) | (4,455 | ) | (3,681 | ) | 32,055 | 32,026 | 28,842 | ||||||||||||||||||||||||
| Income (loss) before income taxes | (268 | ) | (258 | ) | (119 | ) | - | - | - | 2,046 | 3,073 | 582 | ||||||||||||||||||||||||
Income tax expense (benefit) (e) (note 4) | (51 | ) | (69 | ) | (40 | ) | - | - | - | (154 | ) | 759 | 92 | |||||||||||||||||||||||
| Net income (loss) | (217 | ) | (189 | ) | (79 | ) | - | - | - | 2,200 | 2,314 | 490 | ||||||||||||||||||||||||
| Cash flows from (used in) operating activities | (124 | ) | (116 | ) | (125 | ) | (7 | ) | 19 | - | 4,429 | 3,922 | 2,763 | |||||||||||||||||||||||
Capital and exploration expenditures (f) | 48 | 28 | 38 | - | - | - | 1,814 | 1,427 | 671 | |||||||||||||||||||||||||||
| Property, plant and equipment | ||||||||||||||||||||||||||||||||||||
| Cost | 741 | 693 | 665 | - | - | - | 54,868 | 53,944 | 52,778 | |||||||||||||||||||||||||||
| Accumulated depreciation and depletion | (266 | ) | (244 | ) | (223 | ) | - | - | - | (20,665 | ) | (19,719 | ) | (18,305 | ) | |||||||||||||||||||||
Net property, plant and equipment (g) | 475 | 449 | 442 | - | - | - | 34,203 | 34,225 | 34,473 | |||||||||||||||||||||||||||
Total assets (h) (i) | 2,536 | 1,548 | 1,703 | (498 | ) | (478 | ) | (435 | ) | 42,187 | 41,456 | 41,601 | ||||||||||||||||||||||||
| Corporate and other | Eliminations | Consolidated | ||||||||||||||||||||||||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||||||||||
Revenues and other income | ||||||||||||||||||||||||||||||||||||
Revenues (a) | - | - | - | - | - | - | 22,284 | 34,002 | 34,964 | |||||||||||||||||||||||||||
| Intersegment sales | - | - | - | (4,172 | ) | (5,589 | ) | (4,455 | ) | - | - | - | ||||||||||||||||||||||||
Investment and other income (note 9) | 19 | 35 | 29 | - | - | - | 104 | 99 | 135 | |||||||||||||||||||||||||||
19 | 35 | 29 | (4,172 | ) | (5,589 | ) | (4,455 | ) | 22,388 | 34,101 | 35,099 | |||||||||||||||||||||||||
Expenses | ||||||||||||||||||||||||||||||||||||
| Exploration (note 16) | - | - | - | - | - | - | 13 | 47 | 19 | |||||||||||||||||||||||||||
| Purchases of crude oil and products | - | - | - | (4,167 | ) | (5,581 | ) | (4,449 | ) | 13,293 | 20,946 | 21,541 | ||||||||||||||||||||||||
Production and manufacturing (note 12) | - | - | - | - | - | - | 5,535 | 6,520 | 6,121 | |||||||||||||||||||||||||||
| Selling and general | 35 | 48 | 54 | (5 | ) | (8 | ) | (6 | ) | 741 | 900 | 908 | ||||||||||||||||||||||||
| Federal excise tax and fuel charge | - | - | - | - | - | - | 1,736 | 1,808 | 1,667 | |||||||||||||||||||||||||||
Depreciation and depletion (b) (note 12) | 24 | 22 | 21 | - | - | - | 3,293 | 1,598 | 1,555 | |||||||||||||||||||||||||||
Non-service pension and postretirement benefit | 121 | 143 | 107 | - | - | - | 121 | 143 | 107 | |||||||||||||||||||||||||||
Financing (note 13) | 61 | 90 | 105 | - | - | - | 64 | 93 | 108 | |||||||||||||||||||||||||||
Total expenses | 241 | 303 | 287 | (4,172 | ) | (5,589 | ) | (4,455 | ) | 24,796 | 32,055 | 32,026 | ||||||||||||||||||||||||
Income (loss) before income taxes | (222 | ) | (268 | ) | (258 | ) | - | - | - | (2,408 | ) | 2,046 | 3,073 | |||||||||||||||||||||||
Income tax expense (benefit) (c) (note 4) | (52 | ) | (51 | ) | (69 | ) | - | - | - | (551 | ) | (154 | ) | 759 | ||||||||||||||||||||||
Net income (loss) | (170 | ) | (217 | ) | (189 | ) | - | - | - | (1,857 | ) | 2,200 | 2,314 | |||||||||||||||||||||||
Cash flows from (used in) operating activities | (64 | ) | (124 | ) | (116 | ) | (8 | ) | (7 | ) | 19 | 798 | 4,429 | 3,922 | ||||||||||||||||||||||
Capital and exploration expenditures (d) | 41 | 48 | 28 | - | - | - | 874 | 1,814 | 1,427 | |||||||||||||||||||||||||||
Property, plant and equipment | ||||||||||||||||||||||||||||||||||||
| Cost | 782 | 741 | 693 | - | - | - | 55,771 | 54,868 | 53,944 | |||||||||||||||||||||||||||
| Accumulated depreciation and depletion | (290 | ) | (266 | ) | (244 | ) | - | - | - | (23,737 | ) | (20,665 | ) | (19,719 | ) | |||||||||||||||||||||
Net property, plant and equipment (e) | 492 | 475 | 449 | - | - | - | 32,034 | 34,203 | 34,225 | |||||||||||||||||||||||||||
Total assets (f) (g) | 1,632 | 2,536 | 1,548 | (398 | ) | (498 | ) | (478 | ) | 38,031 | 42,187 | 41,456 | ||||||||||||||||||||||||
87
| Includes export sales to the United States of $4,614 million (2019 - $7,190 million, |
| (b) | In 2020, the Upstream segment non-cash impairment |
| company’s decision not to further develop a significant portion of its unconventional portfolio. In 2018, the Downstream segment included a non-cash impairment charge of $46 million,before-tax, associated with the Government of Ontario’s revocation of its cap and trade legislation. |
Segment results in 2019 include a largely |
Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant and equipment, additions to finance leases, additional investments and acquisitions. CAPEX excludes the purchase of carbon emission credits. |
Includes property, plant and equipment under construction of $1,874 million (2019 - $2,149 million, |
Effective January 1, 2019, Imperial adopted the Financial Accounting Standards Board’s standard, Leases (Topic 842) |
In 2019, the company removed $570 million from Total assets and corresponding liabilities in the Downstream segment associated with the Government of Ontario’s revocation of its cap and trade |
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Current income tax expense (a) | 140 | (14 | ) | (58 | ) | |||||||
Deferred income tax expense (a) | (294 | ) | 773 | 150 | ||||||||
Total income tax expense (a) | (154 | ) | 759 | 92 | ||||||||
Statutory corporate tax rate (percent) | 26.0 | 26.9 | 26.9 | |||||||||
Increase (decrease) resulting from: | ||||||||||||
Disposals (b) | (0.6 | ) | (0.3 | ) | (5.3 | ) | ||||||
Enacted tax rate change (a) | (31.9 | ) | - | 0.9 | ||||||||
Other (c) | (1.0 | ) | (1.9 | ) | (6.6 | ) | ||||||
Effective income tax rate | (7.5 | ) | 24.7 | 15.9 |
millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Current income tax expense (benefit) (a) | (27 | ) | 140 | (14 | ) | |||||||
Deferred income tax expense (benefit) (a) | (524 | ) | (294 | ) | 773 | |||||||
Total income tax expense (benefit) (a) | (551 | ) | (154 | ) | 759 | |||||||
Statutory corporate tax rate (percent) | 25.0 | 26.0 | 26.9 | |||||||||
Increase (decrease) resulting from: | ||||||||||||
Enacted tax rate change (a) | 0.1 | (31.9 | ) | - | ||||||||
Other (b) | (2.2 | ) | (1.6 | ) | (2.2 | ) | ||||||
Effective income tax rate | 22.9 | (7.5 | ) | 24.7 |
| (a) | On June 28, 2019 the Alberta government enacted a 4 percent decrease in the provincial tax rate, from 12 percent to 8 percent by 2022. On |
| (b) |
Other decreases |
Deferred income taxes are based on differences between the accounting and tax values of assets and liabilities. These differences in value are
re-measured
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 millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Depreciation and amortization | 5,164 | 5,726 | 5,564 | |||||||||
Successful drilling and land acquisitions | 750 | 856 | 762 | |||||||||
Pension and benefits | (469 | ) | (336 | ) | (422 | ) | ||||||
Asset retirement obligation | (336 | ) | (381 | ) | (376 | ) | ||||||
Capitalized interest | 117 | 121 | 118 | |||||||||
LIFO inventory valuation | (276 | ) | (107 | ) | (318 | ) | ||||||
Tax loss carryforwards | (141 | ) | (658 | ) | (936 | ) | ||||||
Other | (161 | ) | (150 | ) | (196 | ) | ||||||
Net deferred income tax liabilities | 4,648 | 5,071 | 4,196 |
millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Depreciation and amortization | 5,319 | 5,164 | 5,726 | |||||||||
Successful drilling and land acquisitions | 363 | 750 | 856 | |||||||||
Pension and benefits | (534 | ) | (469 | ) | (336 | ) | ||||||
Asset retirement obligation | (403 | ) | (336 | ) | (381 | ) | ||||||
Capitalized interest | 120 | 117 | 121 | |||||||||
LIFO inventory valuation | (150 | ) | (276 | ) | (107 | ) | ||||||
Tax loss carryforwards | (460 | ) | (141 | ) | (658 | ) | ||||||
Other | (154 | ) | (161 | ) | (150 | ) | ||||||
Net deferred income tax liabilities | 4,101 | 4,648 | 5,071 |
88
Unrecognized tax benefits
Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements.
The following table summarizes the movement in unrecognized tax benefits:
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Balance as of January 1 | 36 | 78 | 106 | |||||||||
Additions for prior years’ tax positions | 1 | 9 | 2 | |||||||||
Reductions for prior years’ tax positions | - | (2 | ) | - | ||||||||
Reductions due to lapse of the statute of limitations | - | - | - | |||||||||
Settlements with tax authorities | (2 | ) | (49 | ) | (30 | ) | ||||||
Balance as of December 31 | 35 | 36 | 78 |
millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Balance as of January 1 | 35 | 36 | 78 | |||||||||
Additions based on current year’s tax position | 2 | - | - | |||||||||
Additions for prior years’ tax positions | - | 1 | 9 | |||||||||
Reductions for prior years’ tax positions | - | - | (2 | ) | ||||||||
Settlements with tax authorities | (1 | ) | (2 | ) | (49 | ) | ||||||
Balance as of December 31 | 36 | 35 | 36 |
The unrecognized tax benefit balances shown above are predominately related to tax positions that would reduce the company’s effective tax rate if the positions are favourably resolved. Unfavourable resolution of these tax positions generally would not increase the effective tax rate. The 2020, 2019 2018 and 20172018 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 20152016 to 20192020 are subject to examination by the tax authorities. Tax filings from 20032007 to 20142015 have open objections and therefore are also subject to examination by the tax authorities. The Canada Revenue Agency has made certain adjustments to the company’s filings. Management has evaluated these adjustments and is formally disputing those matters to which the company disagrees. Many of these outstanding matters will not be resolved until after 2020.2021. The impact on unrecognized tax benefits and the company’s effective income tax rate from these matters is not expected to be material.
Resolution of the related tax positions could take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the company.
The company classifies interest on income tax related balances as interest expense or interest income and classifies tax related penalties as operating expense.
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.
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 to retirement.
The expense and obligations for both funded and unfunded benefits are determined in accordance with accepted actuarial practices and U.S. GAAP. 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.
89
The benefit obligations and plan assets associated with the company’s defined benefit plans are measured on December 31.
Pension benefits | Other postretirement benefits | |||||||||||||||||||
2019 | 2018 | 2019 | 2018 | |||||||||||||||||
Assumptions used to determine benefit obligations at December 31 (percent) | ||||||||||||||||||||
Discount rate | 3.10 | 3.90 | 3.10 | 3.90 | ||||||||||||||||
Long-term rate of compensation increase | 4.50 | 4.50 | 4.50 | 4.50 | ||||||||||||||||
millions of Canadian dollars | ||||||||||||||||||||
Change in projected benefit obligation | ||||||||||||||||||||
Projected benefit obligation at January 1 | 8,359 | 8,785 | 582 | 670 | ||||||||||||||||
Current service cost | 228 | 239 | 16 | 17 | ||||||||||||||||
Interest cost | 324 | 302 | 20 | 22 | ||||||||||||||||
Actuarial loss (gain) | 1,053 | (498 | ) | 99 | (101 | ) | ||||||||||||||
Amendments | 283 | - | - | - | ||||||||||||||||
Benefits paid (a) | (461 | ) | (469 | ) | (24 | ) | (26 | ) | ||||||||||||
Projected benefit obligation at December 31 | 9,786 | 8,359 | 693 | 582 | ||||||||||||||||
Accumulated benefit obligation at December 31 | 8,814 | 7,661 | ||||||||||||||||||
| Pension benefits | Other postretirement benefits | |||||||||||||||||||
2020 | 2019 | 2020 | 2019 | |||||||||||||||||
Assumptions used to determine benefit obligations at December 31 (percent) | ||||||||||||||||||||
Discount rate | 2.50 | 3.10 | 2.50 | 3.10 | ||||||||||||||||
Long-term rate of compensation increase | 4.00 | 4.50 | 4.00 | 4.50 | ||||||||||||||||
millions of Canadian dollars | ||||||||||||||||||||
Change in projected benefit obligation | ||||||||||||||||||||
Projected benefit obligation at January 1 | 9,786 | 8,359 | 693 | 582 | ||||||||||||||||
Current service cost | 305 | 228 | 24 | 16 | ||||||||||||||||
Interest cost | 308 | 324 | 24 | 20 | ||||||||||||||||
Actuarial loss (gain) (a) | 811 | 1,053 | 152 | 99 | ||||||||||||||||
Amendments | - | 283 | - | - | ||||||||||||||||
Benefits paid (b) | (494 | ) | (461 | ) | (20 | ) | (24 | ) | ||||||||||||
Projected benefit obligation at December 31 | 10,716 | 9,786 | 873 | 693 | ||||||||||||||||
Accumulated benefit obligation at December 31 | 9,619 | 8,814 | ||||||||||||||||||
| (a) | Actuarial loss primarily driven by a decrease in the year-end discount rate from 3.10 percent to 2.50 percent, partially offset by the impact of a reduction in the long-term rate of compensation increase assumption from 4.50 percent to 4.00 percent. |
| (b) | Benefit payments for funded and unfunded plans. |
The discount rate for the purpose of calculating20202021 and gradually decline to 3.57 percent by 20402040 and beyond. A 1.0 percent increase in the health care cost trend rate would increase service and interest cost by $5 million and the accumulated postretirement benefit obligation by $75 million. A 1.0 percent decrease in the health care cost trend rate would decrease service and interest cost by $4 million and the accumulated postretirement benefit obligation by $60 million.
year-end
postretirement benefits plan liabilities is determined by using the Canadian Institute of Actuaries recommended spot curve for high-quality, long-term Canadian corporate bonds with an average maturity (or duration) approximating that of the liabilities. For the measurement of the accumulated postretirement benefit obligation, the assumed health care cost trend rates start with5.66
percent in Pension benefits | Other postretirement benefits | |||||||||||||||||||
millions of Canadian dollars | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||
Change in plan assets | ||||||||||||||||||||
Fair value at January 1 | 7,691 | 7,870 | ||||||||||||||||||
Actual return (loss) on plan assets | 1,114 | 20 | ||||||||||||||||||
Company contributions | 211 | 203 | ||||||||||||||||||
Benefits paid (b) | (417 | ) | (402 | ) | ||||||||||||||||
Fair value at December 31 | 8,599 | 7,691 | ||||||||||||||||||
Plan assets in excess of (less than) projected benefit obligation at December 31 | ||||||||||||||||||||
Funded plans | (590 | ) | (180 | ) | ||||||||||||||||
Unfunded plans | (597 | ) | (488 | ) | (693 | ) | (582 | ) | ||||||||||||
Total (c) | (1,187 | ) | (668 | ) | (693 | ) | (582 | ) | ||||||||||||
| Pension benefits | Other postretirement benefits | |||||||||||||||||||
millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||
Change in plan assets | ||||||||||||||||||||
Fair value at January 1 | 8,599 | 7,691 | ||||||||||||||||||
Actual return (loss) on plan assets | 1,073 | 1,114 | ||||||||||||||||||
Company contributions | 195 | 211 | ||||||||||||||||||
Benefits paid (a) | (441 | ) | (417 | ) | ||||||||||||||||
Fair value at December 31 | 9,426 | 8,599 | ||||||||||||||||||
| Plan assets in excess of (less than) projected benefit obligation at December 31 | ||||||||||||||||||||
Funded plans | (641 | ) | (590 | ) | ||||||||||||||||
Unfunded plans | (649 | ) | (597 | ) | (873 | ) | (693 | ) | ||||||||||||
Total (b) | (1,290 | ) | (1,187 | ) | (873 | ) | (693 | ) | ||||||||||||
| (a) |
| Benefit payments for funded plans only. |
Fair value of assets less projected benefit obligation shown above. |
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. In accordance with authoritative guidance relating to the accounting for defined pension and other postretirement benefits plans, the underfunded status of the company’s defined benefit postretirement plans was recorded as a liability in the Consolidated balance sheet, and the changes in that funded status in the year in which the changes occurred was recognized through other comprehensive income.
90
| Pension benefits | Other postretirement benefits | |||||||||||||||||||
millions of Canadian dollars | 2019 | 2018 | 2019 | 2018 | ||||||||||||||||
Amounts recorded in the Consolidated balance sheet consist of: | ||||||||||||||||||||
Current liabilities | (27 | ) | (27 | ) | (31 | ) | (28 | ) | ||||||||||||
Other long-term obligations | (1,160 | ) | (641 | ) | (662 | ) | (554 | ) | ||||||||||||
Total recorded | (1,187 | ) | (668 | ) | (693 | ) | (582 | ) | ||||||||||||
Amounts recorded in accumulated other comprehensive income consist of: | ||||||||||||||||||||
Net actuarial loss (gain) | 2,256 | 2,117 | 133 | 33 | ||||||||||||||||
Prior service cost | 283 | - | - | - | ||||||||||||||||
Total recorded in accumulated other comprehensive income, before tax | 2,539 | 2,117 | 133 | 33 | ||||||||||||||||
| Pension benefits | Other postretirement benefits | |||||||||||||||||||
millions of Canadian dollars | 2020 | 2019 | 2020 | 2019 | ||||||||||||||||
Amounts recorded in the Consolidated balance sheet consist of: | ||||||||||||||||||||
Current liabilities | (27 | ) | (27 | ) | (31 | ) | (31 | ) | ||||||||||||
Other long-term obligations | (1,263 | ) | (1,160 | ) | (842 | ) | (662 | ) | ||||||||||||
Total recorded | (1,290 | ) | (1,187 | ) | (873 | ) | (693 | ) | ||||||||||||
Amounts recorded in accumulated other comprehensive income consist of: | ||||||||||||||||||||
Net actuarial loss (gain) | 2,232 | 2,256 | 272 | 133 | ||||||||||||||||
Prior service cost | 269 | 283 | - | - | ||||||||||||||||
Total recorded in accumulated other comprehensive income, before-tax | 2,501 | 2,539 | 272 | 133 | ||||||||||||||||
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 percentages and the long-term return assumption for each asset class. The 20192020 long-term expected return of
4.5 percent used in the calculations of pension expense compares to an actual rate of return of
8.4 percent and
6.9 percent over the last
10-
and
20-year
periods respectively, ending December 31, 2019.2020.
| 2019 | 2018 | 2017 | 2019 | 2018 | 2017 | |||||||||||||||||||
Assumptions used to determine net periodic benefit cost for years ended December 31 (percent) | ||||||||||||||||||||||||
Discount rate | 3.90 | 3.40 | 3.75 | 3.90 | 3.40 | 3.75 | ||||||||||||||||||
Long-term rate of return on funded assets | 4.50 | 5.00 | 5.50 | - | - | - | ||||||||||||||||||
Long-term rate of compensation increase | 4.50 | 4.50 | 4.50 | 4.50 | 4.50 | 4.50 | ||||||||||||||||||
millions of Canadian dollars | ||||||||||||||||||||||||
Components of net periodic benefit cost | ||||||||||||||||||||||||
Current service cost | 228 | 239 | 217 | 16 | 17 | 16 | ||||||||||||||||||
Interest cost | 324 | 302 | 313 | 20 | 22 | 23 | ||||||||||||||||||
Expected return on plan assets | (349 | ) | (402 | ) | (408 | ) | - | - | - | |||||||||||||||
Amortization of prior service cost | - | 4 | 10 | - | - | - | ||||||||||||||||||
Amortization of actuarial loss (gain) | 149 | 175 | 176 | (1 | ) | 6 | 8 | |||||||||||||||||
Net periodic benefit cost | 352 | 318 | 308 | 35 | 45 | 47 | ||||||||||||||||||
Changes in amounts recorded in accumulated other comprehensive income | ||||||||||||||||||||||||
Net actuarial loss (gain) | 288 | (116 | ) | 123 | 99 | (101 | ) | (49 | ) | |||||||||||||||
Amortization of net actuarial (loss) gain included in net periodic benefit cost | (149 | ) | (175 | ) | (176 | ) | 1 | (6 | ) | (8 | ) | |||||||||||||
Prior service cost | 283 | - | - | - | - | - | ||||||||||||||||||
Amortization of prior service cost included in net periodic benefit cost | - | (4 | ) | (10 | ) | - | - | - | ||||||||||||||||
Total recorded in other comprehensive income | 422 | (295 | ) | (63 | ) | 100 | (107 | ) | (57 | ) | ||||||||||||||
Total recorded in net periodic benefit cost and other comprehensive income, before | 774 | 23 | 245 | 135 | (62 | ) | (10 | ) | ||||||||||||||||
| Pension benefits | Other postretirement benefits | |||||||||||||||||||||||
2020 | 2019 | 2018 | 2020 | 2019 | 2018 | |||||||||||||||||||
| Assumptions used to determine net periodic benefit cost for years ended December 31 (percent) | ||||||||||||||||||||||||
Discount rate | 3.10 | 3.90 | 3.40 | 3.10 | 3.90 | 3.40 | ||||||||||||||||||
Long-term rate of return on funded assets | 4.50 | 4.50 | 5.00 | - | - | - | ||||||||||||||||||
Long-term rate of compensation increase | 4.50 | 4.50 | 4.50 | 4.50 | 4.50 | 4.50 | ||||||||||||||||||
millions of Canadian dollars | ||||||||||||||||||||||||
Components of net periodic benefit cost | ||||||||||||||||||||||||
Current service cost | 305 | 228 | 239 | 24 | 16 | 17 | ||||||||||||||||||
Interest cost | 308 | 324 | 302 | 24 | 20 | 22 | ||||||||||||||||||
Expected return on plan assets | (391 | ) | (349 | ) | (402 | ) | - | - | - | |||||||||||||||
Amortization of prior service cost | 14 | - | 4 | - | - | - | ||||||||||||||||||
Amortization of actuarial loss (gain) | 153 | 149 | 175 | 13 | (1 | ) | 6 | |||||||||||||||||
Net periodic benefit cost | 389 | 352 | 318 | 61 | 35 | 45 | ||||||||||||||||||
Changes in amounts recorded in accumulated other comprehensive income | ||||||||||||||||||||||||
Net actuarial loss (gain) | 129 | 288 | (116 | ) | 152 | 99 | (101 | ) | ||||||||||||||||
Amortization of net actuarial (loss) gain included in net periodic benefit cost | (153 | ) | (149 | ) | (175 | ) | (13 | ) | 1 | (6 | ) | |||||||||||||
Prior service cost | - | 283 | - | - | - | - | ||||||||||||||||||
Amortization of prior service cost included in net periodic benefit cost | (14 | ) | - | (4 | ) | - | - | - | ||||||||||||||||
Total recorded in other comprehensive income | (38 | ) | 422 | (295 | ) | 139 | 100 | (107 | ) | |||||||||||||||
Total recorded in net periodic benefit cost and other comprehensive income, before-tax | 351 | 774 | 23 | 200 | 135 | (62 | ) | |||||||||||||||||
Costs for defined contribution plans, primarily the employee savings plan, were $47 million in 2020 (2019 - $43 million, in 2019 (20182018 - $41 million, 2017 - $40 million).
91
A summary of the change in accumulated other comprehensive income is shown in the table below:
Total pension and other postretirement benefits | ||||||||||||
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
(Charge) credit to other comprehensive income, before tax | (522 | ) | 402 | 120 | ||||||||
Deferred income tax (charge) credit (note 18) | 128 | (104) | (38) | |||||||||
(Charge) credit to other comprehensive income, after tax | (394 | ) | 298 | 82 | ||||||||
Total pension and other postretirement benefits | ||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
(Charge) credit to other comprehensive income, before-tax | (101 | ) | (522 | ) | 402 | |||||||
Deferred income tax (charge) credit (note 18) | 23 | 128 | (104 | ) | ||||||||
(Charge) credit to other comprehensive income, after-tax | (78 | ) | (394 | ) | 298 | |||||||
The company’s investment strategy for pension plan assets reflects a long-term view, a careful assessment of therisks inherent in various asset classes and broad diversification to reduce the risk of the portfolio. Consistent with the long-term nature of the liability, the plan assets are primarily invested in global,indexed equity and domestic indexed bond funds to diversify risk while minimizing costs. The equity funds hold Imperial Oil Limited stock only to the extent necessary to replicate the relevant equity index. The balance of the plan assets is largely invested in high-quality corporate and government debt securities. Studies are periodically conducted to establish the preferred target asset allocation. The target asset allocation for equity securities is 30 percent. The target allocation for debt securities is 67 percent. Plan assets for the remaining 3 percent are invested in venture capital partnerships that pursue a strategy of investment in U.S. and international early stage venturesventures.
market-cap-weighted
The 2020 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below:
| Fair value measurements at December 31, 2020, using: | ||||||||||||||||||||
| millions of Canadian dollars | Total | Level 1 | Level 2 | Level 3 | Net Asset Value | |||||||||||||||
Asset class | ||||||||||||||||||||
Equity securities | ||||||||||||||||||||
Canadian | 222 | 222 | ||||||||||||||||||
Non-Canadian | 2,690 | 2,690 | ||||||||||||||||||
Debt securities - Canadian | ||||||||||||||||||||
Corporate | 1,426 | 1,426 | ||||||||||||||||||
Government | 4,825 | 4,825 | ||||||||||||||||||
Asset backed | - | - | ||||||||||||||||||
Equities – Venture capital | 214 | 214 | ||||||||||||||||||
Cash | 49 | 41 | 8 | |||||||||||||||||
Total plan assets at fair value | 9,426 | 41 | 9,385 | |||||||||||||||||
92
The 2019 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below:
| Fair value measurements at December 31, 2019, using: | ||||||||||||||||||||
| millions of Canadian dollars | Total | Level 1 | Level 2 | Level 3 | Net Asset Value | |||||||||||||||
Asset class | ||||||||||||||||||||
Equity securities | ||||||||||||||||||||
Canadian | 210 | 210 | ||||||||||||||||||
Non-Canadian | 2,449 | 2,449 | ||||||||||||||||||
Debt securities - Canadian | ||||||||||||||||||||
Corporate | 1,379 | 1,379 | ||||||||||||||||||
Government | 4,299 | 4,299 | ||||||||||||||||||
Asset backed | 1 | 1 | ||||||||||||||||||
Equities – Venture capital | 204 | 204 | ||||||||||||||||||
Cash | 57 | 40 | 17 | |||||||||||||||||
Total plan assets at fair value | 8,599 | 40 | 8,559 | |||||||||||||||||
Fair value measurements at December 31, 2018, using: | ||||||||||||||||||||
millions of Canadian dollars | Total | Level 1 | Level 2 | Level 3 | Net Asset Value | |||||||||||||||
Asset class | ||||||||||||||||||||
Equity securities | ||||||||||||||||||||
Canadian | 170 | 170 | ||||||||||||||||||
Non-Canadian | 2,035 | 2,035 | ||||||||||||||||||
Debt securities - Canadian | ||||||||||||||||||||
Corporate | 1,231 | 1,231 | ||||||||||||||||||
Government | 3,987 | 3,987 | ||||||||||||||||||
Asset backed | 3 | 3 | ||||||||||||||||||
Equities – Venture capital | 226 | 226 | ||||||||||||||||||
Cash | 39 | 33 | 6 | |||||||||||||||||
Total plan assets at fair value | 7,691 | 33 | - | - | 7,658 | |||||||||||||||
| Fair value measurements at December 31, 2019, using: | ||||||||||||||||||||
| millions of Canadian dollars | Total | Level 1 | Level 2 | Level 3 | Net Asset Value | |||||||||||||||
Asset class | ||||||||||||||||||||
Equity securities | ||||||||||||||||||||
Canadian | 210 | 210 | ||||||||||||||||||
Non-Canadian | 2,449 | 2,449 | ||||||||||||||||||
Debt securities - Canadian | ||||||||||||||||||||
Corporate | 1,379 | 1,379 | ||||||||||||||||||
Government | 4,299 | 4,299 | ||||||||||||||||||
Asset backed | 1 | 1 | ||||||||||||||||||
Equities – Venture capital | 204 | 204 | ||||||||||||||||||
Cash | 57 | 40 | 17 | |||||||||||||||||
Total plan assets at fair value | 8,599 | 40 | 8,559 | |||||||||||||||||
A summary of pension plans with accumulated benefit obligationsobligation and projected benefit obligation in excess of plan assets is shown in the table below:
Pension benefits | ||||||||||||
millions of Canadian dollars | 2019 | 2018 | ||||||||||
For funded pension plans with accumulated benefit obligations in excess of plan assets: (a) | ||||||||||||
Projected benefit obligation | 1,042 | 943 | ||||||||||
Accumulated benefit obligation | 942 | 852 | ||||||||||
Fair value of plan assets | 870 | 739 | ||||||||||
Accumulated benefit obligation less fair value of plan assets | 72 | 113 | ||||||||||
For unfunded plans covered by book reserves: | ||||||||||||
Projected benefit obligation | 597 | 488 | ||||||||||
Accumulated benefit obligation | 536 | 451 | ||||||||||
| Pension benefits | ||||||||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||||||
For funded pension plans with accumulated benefit obligation in excess of plan assets: (a) | ||||||||||||
Accumulated benefit obligation | 1,034 | 942 | ||||||||||
Fair value of plan assets | 954 | 870 | ||||||||||
Accumulated benefit obligation less fair value of plan assets | 80 | 72 | ||||||||||
For funded pension plans with projected benefit obligation in excess of plan assets: | ||||||||||||
Projected benefit obligation | 10,067 | 9,189 | ||||||||||
Fair value of plan assets | 9,426 | 8,599 | ||||||||||
Projected benefit obligation less fair value of plan assets | 641 | 590 | ||||||||||
For unfunded plans covered by book reserves: | ||||||||||||
Projected benefit obligation | 649 | 597 | ||||||||||
Accumulated benefit obligation | 565 | 536 | ||||||||||
| (a) | The amounts shown for funded pension plans with accumulated benefit |
millions of Canadian dollars | Pension benefits | Other postretirement benefits | ||||||
Net actuarial loss (gain) (a) | 157 | 9 | ||||||
Prior service cost (b) | 13 | - | ||||||
Cash flows
Benefit payments expected in:
millions of Canadian dollars | Pension benefits | Other postretirement benefits | ||||||
2020 | 460 | 31 | ||||||
2021 | 460 | 31 | ||||||
2022 | 460 | 32 | ||||||
2023 | 460 | 32 | ||||||
2024 | 460 | 32 | ||||||
2025 - 2029 | 2,245 | 160 | ||||||
| millions of Canadian dollars | Pension benefits | Other postretirement benefits | ||||||
2021 | 460 | 31 | ||||||
2022 | 460 | 32 | ||||||
2023 | 465 | 32 | ||||||
2024 | 465 | 33 | ||||||
2025 | 465 | 34 | ||||||
2026 - 2030 | 2,325 | 175 | ||||||
In 2020,2021, the company expects to make cashcontributions of about $216$164 million to its pension plans.
93
6. Other long-term obligations
millions of Canadian dollars | 2019 | 2018 | ||||||||
Employee retirement benefits (a) (note 5) | 1,822 | 1,195 | ||||||||
Asset retirement obligations and other environmental liabilities (b) (d) | 1,388 | 1,435 | ||||||||
Share-based incentive compensation liabilities (note 8) | 65 | 78 | ||||||||
Operating lease liability (c) (note 14) | 143 | - | ||||||||
Other obligations | 219 | 235 | ||||||||
Total other long-term obligations | 3,637 | 2,943 | ||||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||||
Employee retirement benefits (a) (note 5) | 2,105 | 1,822 | ||||||||
Asset retirement obligations and other environmental liabilities (b) (c) | 1,676 | 1,388 | ||||||||
Share-based incentive compensation liabilities (note 8) | 45 | 65 | ||||||||
Operating lease liability (note 14) | 95 | 143 | ||||||||
Other obligations | 179 | 219 | ||||||||
Total other long-term obligations | 4,100 | 3,637 | ||||||||
(a) | Total recorded employee retirement benefits obligations also included $58 million in current liabilities $58 million). |
| (b) | |||||||
Total asset retirement obligations and other environmental liabilities also included $100 million in current liabilities $124 million). | |||||||
(c) | |||||||
For percent percent). | |||||||
Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The following table summarizes the activity in the liability for asset retirement obligations: |
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Balance as at January 1 | 1,400 | 1,417 | 1,397 | |||||||||
Additions (deductions) | 265 | (23 | ) | (5 | ) | |||||||
Accretion | 82 | 80 | 85 | |||||||||
Settlement | (73 | ) | (74 | ) | (60 | ) | ||||||
Balance as at December 31 | 1,674 | 1,400 | 1,417 | |||||||||
millions of Canadian dollars | 2019 | 2018 | ||||||
| Balance as at January 1 | 1,417 | 1,397 | ||||||
| Additions (deductions) | (23 | ) | (5 | ) | ||||
| Accretion | 80 | 85 | ||||||
| Settlement | (74 | ) | (60 | ) | ||||
| Balance as at December 31 | 1,400 | 1,417 | ||||||
94
7. Financial and derivative instruments
Financial instruments
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 value of the company’s financial instruments and the recorded carrying value.
At December 31, 20192020 and at December 31, 2018,2019, the fair value of long-term debt
($4,447 million, excluding finance lease obligations) was primarily a level 2 measurement.
Derivative instruments
The company’s size, strong capital structure and the complementary nature of the Upstream, Downstream and Chemical businesses reduce the company’s enterprise-wide risk from changes in commodity prices and currency exchange rates. In addition, the company uses commodity-based contracts, including derivative instruments to manage commodity price risk. The company does not designate derivative instruments as a hedge for hedge accounting purposes.
Credit risk associated with the company’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. The company maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity.
| At December 31 | 2020 | 2019 | ||||||
Crude (barrels) | (800,000 | ) | (590,000 | ) | ||||
Products (barrels) | (390,000 | ) | - | |||||
Realized and unrealized gain or (loss) on derivative instruments recognized in the Consolidated statement of income is included in the following lines on a
before-tax
basis:millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Revenues | (3 | ) | 6 | - | ||||||||
Purchases of crude oil and products | (7 | ) | (24 | ) | (5 | ) | ||||||
Total | (10 | ) | (18 | ) | (5 | ) | ||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Revenues | (13 | ) | (3 | ) | 6 | |||||||
Purchases of crude oil and products | (21 | ) | (7 | ) | (24 | ) | ||||||
Total | (34 | ) | (10 | ) | (18 | ) | ||||||
The estimated fair value of derivative instruments, and the related hierarchy level for the fair value measurement is as follows:
millions of Canadian dollars At December 31, 2020 | ||||||||||||||||||||||||||||
| Fair value | Effect of counterparty netting | Effect of collateral netting | Net carrying value | |||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | |||||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||
Derivative assets (a) | 2 | - | - | 2 | (2 | ) | - | - | ||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||
Derivative liabilities (b) | 12 | - | - | 12 | (2 | ) | (10 | ) | - | |||||||||||||||||||
(a) Included in the Consolidated balance sheet line: “Materials, supplies and prepaid expenses”.
(b) Included in the Consolidated balance sheet line: “Accounts payable and accrued liabilities”.
95
millions of Canadian dollars At December 31, 2019 | ||||||||||||||||||||||||||||
| Fair value | Effect of | Effect of | Net | |||||||||||||||||||||||||
| counterparty | collateral | carrying | ||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | Total | netting | netting | value | ||||||||||||||||||||||
Assets | ||||||||||||||||||||||||||||
Derivative assets (a) | - | - | - | - | - | - | - | |||||||||||||||||||||
Liabilities | ||||||||||||||||||||||||||||
Derivative liabilities (b) | 2 | - | - | 2 | - | (2) | - | |||||||||||||||||||||
| (a) | Included in the Consolidated balance sheet line: “Materials, supplies and prepaid expenses”. |
| (b) | Included in the Consolidated balance sheet line: “Accounts payable and accrued liabilities”. |
At December 31, 2020, the Company had $5
million of collateral under a master netting arrangement not offset against the derivatives on the Consolidated balance sheet in “Accounts receivable - net”, primarily related to initial margin requirements.
96
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 over the long-term. The nonemployee directors also participate in share-based incentiveincent
i
ve compensation programs.Restricted stock units and deferred share units
Under the restricted stock unit plan, each unit entitles the recipient to the conditional right to receive from the company, upon vesting, an amount equal to the value of one common share of the company, based on theFifty percentFor the majority of the units, fifty percent of the units vest on the third anniversary of the grant date, and the remainder vest on the seventh anniversary of the grant date. The company may also issue units to the chairman, president and chief executive officer
five-day
average of the closing price of the company’s common shares on the Toronto Stock Exchange on and immediately prior to the vesting dates. where either
50 percent
of the units vest on the fifth anniversary of the grant date and the remainder vest on the tenth anniversary of the grant date, or where 50 percentexcept that for awards granted prior to 2020, the vesting of the units vest on the fifth anniversary of the grant date and the remainder vest on the tenth anniversary of the grant date, or date ofportion is delayed until retirement of the recipient, whichever is later.if later than 10 years.
The deferred share unit plan is made available to nonemployee directors. The nonemployee directors can elect to receive all or part of their eligible directors’ fees in units. The number of units granted is determined at the end of each calendar quarter by dividing the dollar amount of the nonemployee director’s fees for that calendar quarter elected to be received as deferred share units by the average closing price of the company’s shares for the five consecutive trading days (“average closing price”) immediately prior to the last day of the calendar quarter. Additional units are granted to represent dividends on unexercised units, and are calculated by dividing the cash dividend payable on the company’s shares 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 service as a director, including termination due to death, and must be exercised in their entirety in one election no later than December 31 of the year following the year of termination of service. On the exercise date, the cash value to be received for the units is determined based on the company’s average closing price immediately prior to the date of exercise, as adjusted for any share splits.
All units require settlement by cash payments with the following exceptions. The restricted stock unit program provides that, for units granted to Canadian residents, the recipient may receive one common share of the company per unit or elect to receive the cash payment for the units that vest on the seventh year anniversary of the grant date. For units where 50 percent vest on the fifth anniversary of the grant date and the remainder vest on either the tenth anniversary of grant, or 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 that vest.
The company accounts for all units by using the fair-value-based method. The fair value of awards in the form of restricted stock and deferred share 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.
The following table summarizes information about these units for the year ended December 31, 2019:
2020:
Restricted stock units | Deferred share units | |||||||
Outstanding at January 1, 2019 | 5,302,825 | 151,695 | ||||||
Granted | 854,800 | 18,468 | ||||||
Vested / Exercised | (1,241,280 | ) | - | |||||
Forfeited and cancelled | (3,540 | ) | - | |||||
Outstanding at December 31, 2019 | 4,912,805 | 170,163 | ||||||
| Restricted | Deferred | |||||||
| stock units | share units | |||||||
Outstanding at January 1, 2020 | 4,912,805 | 170,163 | ||||||
Granted | 747,040 | 34,811 | ||||||
Vested / Exercised | (1,187,630 | ) | (57,569 | ) | ||||
Forfeited and cancelled | (8,895 | ) | - | |||||
Outstanding at December 31, 2020 | 4,463,320 | 147,405 | ||||||
97
In 2019, the before-tax2020, net loss included a favourable impact of
$
2million
beforetax
associated with compensation expense charged against income for these programs was $34
(2019- $
34 million (2018 expense,
2018- $32 $
32million 2017 - $14 million)expense). Income tax benefit recognized in income related toexpense associated with compensation expenseprograms for the year was $9$
0 million (2018- $9
(2019- $
9 million 2017 benefit,
2018- $4 million)$
9million benefit). Cash payments of $50$
33 million were made for these programs in
2020(2019- $71 $
50 million,
2018- $
59million).
As of December 31, 2019,2020, there was $76$45 million of total2019.2020.
before-tax
unrecognized compensation expense related tonon-vested
restricted stock units based on the company’s share price at the end of the current reporting period. The weighted average vesting period ofnon-vested
restricted stock units is 4.1 years. All units under the deferred share programs have vested as of December 31, 9. Investment and other income
Investment and other income includes gains and losses on asset sales as follows:
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Proceeds from asset sales | 82 | 59 | 232 | |||||||||
Book value of asset sales | 36 | 5 | 12 | |||||||||
Gain (loss) on asset sales, before-tax (a) | 46 | 54 | 220 | |||||||||
Gain (loss) on asset sales, after-tax (a) | 42 | 38 | 192 | |||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Proceeds from asset sales | 82 | 82 | 59 | |||||||||
Book value of asset sales | 47 | 36 | 5 | |||||||||
Gain (loss) on asset sales, before-tax | 35 | 46 | 54 | |||||||||
Gain (loss) on asset sales, after-tax | 32 | 42 | 38 | |||||||||
10. Litigation and other contingencies
A variety of claims have been made against Imperial 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. For purposes of the company’s contingency disclosures, “significant” includes material matters, as well as other matters which management believes should be disclosed. 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, financial condition, or financial statements taken as a whole.
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. The company has 0t entered into any unconditional purchase obligations.As a result of the completed sale of Imperial’s remaining company-owned Esso retail sites, the company was contingently liable at December 31, 2019,2020, for guarantees relating to performance under contracts of other third-party
obligations
totalling
At December 31, 20192020 the company is contingently liable for up to $64$62 million, under existing indemnification arrangements, for costs associated with continuing a third partythird-party pipeline project development (2018(2019 - $46$64 million).
98
11. Common shares
thousands of shares At December 31 | 2019 | |||||||
Authorized | 1,100,000 | 1,100,000 | ||||||
Common shares outstanding | 743,902 | 782,565 | ||||||
thousands of shares At December 31 | 2020 | 2019 | ||||||
Authorized | 1,100,000 | 1,100,000 | ||||||
Common shares outstanding | 734,077 | 743,902 | ||||||
12-month
limited normal course issuer bid program came into effect on Juneo
gram enables the company to purchase up to a maximum of 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, 2017 | 847,599 | 1,566 | ||||||||||
Issued under employee share-based awards | 2 | - | ||||||||||
Purchases at stated value | (16,359 | ) | (30 | ) | ||||||||
Balance as at December 31, 2017 | 831,242 | 1,536 | ||||||||||
Issued under employee share-based awards | 2 | - | ||||||||||
Purchases at stated value | (48,679 | ) | (90 | ) | ||||||||
Balance as at December 31, 2018 | 782,565 | 1,446 | ||||||||||
Issued under employee share-based awards | 1 | - | ||||||||||
Purchases at stated value | (38,664 | ) | (71 | ) | ||||||||
Balance as at December 31, 2019 | 743,902 | 1,375 | ||||||||||
| Thousands of | Millions of | |||||||
| shares | dollars | |||||||
Balance as at January 1, 2018 | 831,242 | 1,536 | ||||||
Issued under employee share-based awards | 2 | 0 | ||||||
Purchases at stated value | (48,679 | ) | (90 | ) | ||||
Balance as at December 31, 2018 | 782,565 | 1,446 | ||||||
Issued under employee share-based awards | 1 | 0 | ||||||
Purchases at stated value | (38,664 | ) | (71 | ) | ||||
Balance as at December 31, 2019 | 743,902 | 1,375 | ||||||
Issued under employee share-based awards | 7 | - | ||||||
Purchases at stated value | (9,832 | ) | (18 | ) | ||||
Balance as at December 31, 2020 | 734,077 | 1,357 | ||||||
The following table provides the calculation of basic and diluted earnings per common share and the dividends declared by the company on its outstanding common shares:
2019 | 2017 | |||||||||||
Net income (loss) per common share – basic | ||||||||||||
Net income (loss) (millions of Canadian dollars) | 2,200 | 2,314 | 490 | |||||||||
Weighted average number of common shares outstanding (millions of shares) | 762.7 | 807.5 | 842.9 | |||||||||
Net income (loss) per common share (dollars) | 2.88 | 2.87 | 0.58 | |||||||||
Net income (loss) per common share – diluted | ||||||||||||
Net income (loss) (millions of Canadian dollars) | 2,200 | 2,314 | 490 | |||||||||
Weighted average number of common shares outstanding (millions of shares) | 762.7 | 807.5 | 842.9 | |||||||||
Effect of employee share-based awards (millions of shares) | 2.3 | 2.6 | 2.8 | |||||||||
Weighted average number of common shares outstanding, assuming dilution (millions of shares) | 765.0 | 810.1 | 845.7 | |||||||||
Net income (loss) per common share (dollars) | 2.88 | 2.86 | 0.58 | |||||||||
Dividends per common share – declared (dollars) | 0.85 | 0.73 | 0.63 | |||||||||
2020 | 2019 | 2018 | ||||||||||
Net income (loss) per common share – basic | ||||||||||||
Net income (loss) (millions of Canadian dollars) | (1,857 | ) | 2,200 | 2,314 | ||||||||
Weighted average number of common shares outstanding (millions of shares) | 735.3 | 762.7 | 807.5 | |||||||||
Net income (loss) per common share (dollars) | (2.53 | ) | 2.88 | 2.87 | ||||||||
Net income (loss) per common share – diluted | ||||||||||||
Net income (loss) (millions of Canadian dollars) | (1,857 | ) | 2,200 | 2,314 | ||||||||
Weighted average number of common shares outstanding (millions of shares) | 735.3 | 762.7 | 807.5 | |||||||||
Effect of employee share-based awards (millions of shares) (a) | - | 2.3 | 2.6 | |||||||||
Weighted average number of common shares outstanding, assuming dilution (millions of shares) | 735.3 | 765.0 | 810.1 | |||||||||
Net income (loss) per common share (dollars) | (2.53 | ) | 2.88 | 2.86 | ||||||||
Dividends per common share – declared (dollars) | 0.88 | 0.85 | 0.73 | |||||||||
| a) | For 2020, the Net income (loss) per common share – diluted excludes the effect of 1.9 million employee share-based awards. Share-based awards have the potential to dilute basic earnings per share in the future. |
99
12. Miscellaneous financial information
In 2019,2020, net incomeloss included an(2018loss, 2018 – $16 million gain, 2017 – $5 million gain) attributable to the effect of changes in20192020 by about $0.8 billion (2019 – $1.2 billion (2018 – $0.9 billion).
$397$344 million at December 31, 2019 (20182020 (2019 – $413$397 million).
after-tax
loss
of $19 million (2019 – $22 million last-in,
first-out
(LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, Inventories of crude oil and products at
year-end
consisted of the following:millions of Canadian dollars | 2019 | 2018 | ||||||
Crude oil | 764 | 731 | ||||||
Petroleum products | 396 | 473 | ||||||
Chemical products | 64 | 72 | ||||||
Other | 72 | 21 | ||||||
Total inventories of crude oil and products | 1,296 | 1,297 | ||||||
| millions of Canadian dollars | 2020 | 2019 | ||||||
Crude oil | 630 | 764 | ||||||
Petroleum products | 403 | 396 | ||||||
Chemical products | 55 | 64 | ||||||
Other | 73 | 72 | ||||||
Total inventories of crude oil and products | 1,161 | 1,296 | ||||||
Research expenditures are mainly spent on developing technologies to improve bitumen recovery, reduce costs and reduce the environmental impact of upstream operations, including technologies to reduce greenhouse gas emissions intensity, supporting environmental and process improvements in the refineries, as well as accessing ExxonMobil’s research worldwide.
The company has scientific research agreements with affiliatesof ExxonMobil, which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licencing of patents, and patent rights. These agreements provide mutual access to scientific and operating data related to nearlyevery phase of the petroleum and petrochemical operations of the parties.
Net research and development costs charged to expenses in 20192020 were $105 million (2019 – $133 million, (20182018 – $110 million, 2017 – $111 million). These costs are included in expenses due to the uncertainty of future benefits.
“Accounts payable and accrued liabilitiesliabilities” included
accrued taxes other than income taxes of In the second quarter of 2020, the Government of Canada implemented the Canada Emergency Wage Subsidy (CEWS) as part of its COVID-19 Economic Response Plan. The program’s intent is to help sustain employment levels by providing expense relief to companies during the pandemic. The company qualified for these wage subsidies which are recognized throughout the year when received. The relief provided under this program in 2020, about
$
155 million before tax, including the company’s proportionate share of a joint venture, is recognized as a reduction to expense and is included in the Consolidated statement of income, primarily as part of “Production and manufacturing”.
In the first quarter of 2020, with the change in economic conditions and the reduction in the company’s market capitalization, the company assessed its goodwill balances for impairment and recognized a
non-cash
goodwill impairment charge of $20 million in the company’s Upstream segment. The goodwill impairment is reflected in “Depreciation and depletion” on the Consolidated statement of income and “Goodwill” on the Consolidated balance sheet. The remaining balance of goodwill is associated with the Downstream segment.100
13. Financing and additional notes and loans payable information
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Debt-related interest (a) | 138 | 133 | 103 | |||||||||
Capitalized interest | (48 | ) | (28 | ) | (38) | |||||||
Net interest expense | 90 | 105 | 65 | |||||||||
Other interest | 3 | 3 | 13 | |||||||||
Total financing (b) | 93 | 108 | 78 | |||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Debt-related interest (a) | 102 | 138 | 133 | |||||||||
Capitalized interest | (41 | ) | (48 | ) | (28 | ) | ||||||
Net interest expense | 61 | 90 | 105 | |||||||||
Other interest | 3 | 3 | 3 | |||||||||
Total financing (b) | 64 | 93 | 108 | |||||||||
| (a) | Includes related party interest with ExxonMobil. |
| (b) | The weighted average interest rate on short-term borrowings in |
non-interest
bearing, revolving demand loan from ExxonMobil from
marketing and transportation and
In response to market conditions, during the second quarter of 2020, the company had borrowed $111entered into
a $500 million credit to June 2021. These facilities were in addition to existing credit facilities of $500 million. The company has 0t drawn on these facilities.
In November 2019,2020, the company extended the maturity date of its existing $250 million committed long-term line of credit to November 2021. The company has0t drawn on the facility.
The maturity date of the other existing $250 million credit facility remains unchanged at November 2021. The company has 0t drawn on the facility.
101
The company generally purchases the property, plant and equipment used in operations, but there are situations where assets are leased, primarily storage tanks, rail cars, marine vessels
and
transportation
facilities.
Right of use assets and lease liabilities are established on the balance sheet for leases with an expected term greater than one year, by discounting the amounts fixed in the lease agreement for the duration of the lease which is reasonably certain, considering the probability of exercising any early termination and extension options. The portion of the fixed payment related to service costs
for
tankers
and finance
leases
is
excluded from the calculation of right of use assets and lease liabilities. Usually, assets are leased only for a portion of their useful lives and are accounted for as operating leases. In limited situations assets are leased for nearly all of their useful lives and are accounted for as finance leases. In general, leases are capitalized using the company’s incremental borrowing rate.
Variable payments under these lease agreements are not significant. Residual value guarantees, restrictions, or covenants related to leases, and transactions with related parties are also not significant. The company’s activities as a lessor are not material.
The table below summarizes the total lease cost incurred:
2019 | ||||||||
millions of Canadian dollars | Operating leases | Finance leases | ||||||
Operating lease cost | 151 | |||||||
Short-term and other (net of sublease rental income) | 76 | |||||||
Amortization of right of use assets | 55 | |||||||
Interest on lease liabilities | 40 | |||||||
Total lease cost | 227 | 95 | ||||||
2020 | 2019 | |||||||||||||||
| millions of Canadian dollars | Operating leases | Finance leases | Operating leases | Finance leases | ||||||||||||
Operating lease cost | 157 | 151 | ||||||||||||||
Short-term and other (net of sublease rental income) | 40 | 76 | ||||||||||||||
Amortization of right of use assets | 29 | 55 | ||||||||||||||
Interest on lease liabilities | 38 | 40 | ||||||||||||||
Total lease cost | 197 | 67 | 227 | 95 | ||||||||||||
The following table summarizes the amounts related to operating leases and finance leases recorded on the Consolidated balance sheet, as at December 31, 2019:
2019 | ||||||||
millions of Canadian dollars | Operating leases | Finance leases | ||||||
Right of use assets | ||||||||
Included in Other assets, including intangibles, net | 260 | |||||||
Included in Property, plant and equipment, net | 546 | |||||||
Total right of use assets | 260 | 546 | ||||||
Lease liability due within one year | ||||||||
Included in Accounts payable and accrued liabilities | 115 | 15 | ||||||
Included in Notes and loans payable | 18 | |||||||
Long-term lease liability | ||||||||
Included in Other long-term obligations | 143 | - | ||||||
Included in Long-term debt | 514 | |||||||
Total lease liability | 258 | 547 | ||||||
2020 | 2019 | |||||||||||||||
| millions of Canadian dollars | Operating leases | | Finance leases | | Operating leases | | Finance leases | | ||||||||
Right of use assets | ||||||||||||||||
Included in Other assets, including intangibles, net | 188 | 260 | ||||||||||||||
Included in Property, plant and equipment, net | 532 | 546 | ||||||||||||||
Total right of use assets | 188 | 532 | 260 | 546 | ||||||||||||
Lease liability due within one year | ||||||||||||||||
Included in Accounts payable and accrued liabilities | 97 | - | 115 | 15 | ||||||||||||
Included in Notes and loans payable | 16 | 18 | ||||||||||||||
Long-term lease liability | ||||||||||||||||
Included in Other long-term obligations | 95 | - | 143 | 0 | ||||||||||||
Included in Long-term debt | 510 | 514 | ||||||||||||||
Total lease liability | 192 | 526 | 258 | 547 | ||||||||||||
Weighted average remaining lease term (years) | 4 | 38 | 4 | 40 | ||||||||||||
Weighted average discount rate (percent) | 2.5 | 7.3 | 2.6 | 7.5 | ||||||||||||
102
The maturity analysis of the company’s lease liabilities as at December 31 2019, are summarized below:
2019 | ||||||||
millions of Canadian dollars, unless noted | Operating leases | | Finance leases | | ||||
Maturity analysis of lease liabilities | ||||||||
202 0 | 121 | 71 | ||||||
2021 | 70 | 50 | ||||||
2022 | 30 | 49 | ||||||
2023 | 13 | 48 | ||||||
2024 | 11 | 47 | ||||||
2025 and beyond | 30 | 1,086 | ||||||
Total lease payments | 275 | 1,351 | ||||||
Discount to present value | (17 | ) | (804 | ) | ||||
Total lease liability | 258 | 547 | ||||||
Weighted average remaining lease term (years) | 4 | 40 | ||||||
Weighted average discount rate (percent) | 2.6 | 7.5 | ||||||
2020 | ||||||||
| millions of Canadian dollars, unless noted | Operating leases | Finance leases | ||||||
Maturity analysis of lease liabilities | ||||||||
2021 | 96 | 53 | ||||||
2022 | 49 | 52 | ||||||
2023 | 16 | 51 | ||||||
2024 | 12 | 50 | ||||||
2025 | 3 | 47 | ||||||
2026 and beyond | 27 | 1,040 | ||||||
Total lease payments | 203 | 1,293 | ||||||
Discount to present value | (11 | ) | (767 | ) | ||||
Total lease liability | 192 | 526 | ||||||
In addition to the operating lease liabilities in the table immediately above, at December 31, 2019,2020, additional undiscounted commitments for leases not yet commenced totalled $27 million (2019 - $6 million.million).
The table below summarizes the cash paid for amounts included in the measurement of lease liabilities and the right of use assets obtained in exchange for new lease liabilities:
2019 | ||||||||
millions of Canadian dollars | Operating leases | | Finance leases | |||||
Cash paid for amounts included in the measurement of lease liabilities | ||||||||
Cash flows from operating activities | 147 | 45 | ||||||
Cash flows from financing activities | 27 | |||||||
Non-cash right of use assets recorded for lease liabilities | ||||||||
For January 1 adoption of Leases (Topic 842) | 298 | |||||||
In exchange for new lease liabilities during the year | 104 | |||||||
2020 | 2019 | |||||||||||||||
| millions of Canadian dollars | Operating leases | Finance leases | Operating leases | Finance leases | ||||||||||||
Cash paid for amounts included in the measurement of lease liabilities | ||||||||||||||||
Cash flows from operating activities | 136 | 15 | 147 | 45 | ||||||||||||
Cash flows from financing activities | 20 | �� | 27 | |||||||||||||
Non-cash right of use assets recorded for lease liabilities | ||||||||||||||||
For January 1 adoption of Leases (Topic 842) | 298 | |||||||||||||||
In exchange for lease liabilities during the year | 63 | 104 | ||||||||||||||
Disclosures under the previous lease standard
– Leases
(Topic 840)
Net rental cost incurred under both cancelable and2018 and $206 million in 2017. At December 31, 2018, minimum undiscounted lease commitments under non-cancelable operating leases for 2019 and beyond were $291 million.2018.
non-cancelable
operating leases was $221 million in At December 31 | 2019 | 2018 | ||||||
Long-term debt (a) | 4,447 | 4,447 | ||||||
Finance leases (b) | 514 | 531 | ||||||
Total long-term debt | 4,961 | 4,978 |
millions of Canadian dollars | ||||||||||||
At December 31 | 2020 | 2019 | ||||||||||
Long-term debt (a) | 4,447 | 4,447 | ||||||||||
Finance leases (b) | 510 | 514 | ||||||||||
Total long-term debt | 4,957 | 4,961 |
| (a) | Borrowed under an existing agreement with an affiliated company of ExxonMobil that provides for a long-term, variable-rate, Canadian dollar loan from ExxonMobil to the company of up to $7.75 billion at interest equivalent to Canadian market rates. The agreement is effective until June 30, 2025, cancelable if ExxonMobil provides at least 370 days advance written notice. |
| (b) | Finance leases are primarily associated with transportation facilities and services agreements. The average imputed rate was |
16. Accounting for suspended exploratory well costs
The company continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Balance as at January 1 | - | - | 143 | |||||||||
Additions pending the determination of proved reserves | - | - | - | |||||||||
Charged to expense | - | - | (143 | ) | ||||||||
Reclassification to wells, facilities and equipment based on the determination of proved reserves | - | - | - | |||||||||
Balance as at December 31 | - | - | - | |||||||||
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Capitalized for a period of one year or less | - | - | - | |||||||||
Capitalized for a period of between one and ten years | - | - | - | |||||||||
Capitalized for a period of greater than one year | - | - | - | |||||||||
Total | - | - | - | |||||||||
Exploration activity often involves drilling multiple wells, over a number of years, to fully evaluate a project.
)
.2019 | 2018 | 2017 | ||||||||||
Number of projects that only have exploratory well costs capitalized for a period of one year or less | - | - | - | |||||||||
Number of projects that have exploratory well costs capitalized for a period of greater than one year | - | - | - | |||||||||
Total | - | - | - | |||||||||
19304
17. Transactions with related parties
Revenues and expenses of the company also include the results of transactions with affiliated companies of ExxonMobil in the normal course of operations. These were conducted on terms comparable to those which would have been conducted with unrelated parties and primarily consisted of the purchase and sale of crude oil, natural gas, petroleum and chemical products, as well as technical, engineering and research and development costs. 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.
In addition, the company has existing agreements with ExxonMobil:
| a) | 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; |
| b) | To operate certain western Canada production properties owned by ExxonMobil, as well as provide for the delivery of management, business and technical services to ExxonMobil in Canada. These agreements are designed to provide organizational efficiencies and to reduce costs. No separate legal entities were created from these arrangements. 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; |
| c) | To provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil; |
| d) | To provide for the option of equal participation in new upstream opportunities; and |
| e) | To enter into derivative agreements on each other’s behalf. |
Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.
The amounts of purchases and sales by Imperial in 2019,2020, with ExxonMobil, were $2,424 million and $5,101 million respectively (2019 - $3,245 million and $8,552 million respectively (2018 - $4,036 million and $6,364 million respectively).
As at December 31, 2019,2020, the company had outstanding long-term loans of $4,447 million (2018(2019 – $4,447 million) and short-term loans of $111 million (2018(2019 – $75$111 million) from ExxonMobil (see note 15, Long-term debt, on page92 104 and note 13, Financing and additional notes and loans payable information, on page89 101 for further details). The amount of financing costs with ExxonMobil were $96$61 million (2018(2019 - $87$96 million).
Imperial has other related party transactions not detailed above in note 17, as they are not significant.
18. Other comprehensive income (loss) information
Changes in accumulated other comprehensive income (loss):
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Balance at January 1 | (1,517 | ) | (1,815 | ) | (1,897 | ) | ||||||
Postretirement benefits liability adjustment: | ||||||||||||
Current period change excluding amounts reclassified from accumulated other | (505 | ) | 158 | (54 | ) | |||||||
Amounts reclassified from accumulated other comprehensive income | 111 | 140 | 136 | |||||||||
Balance at December 31 | (1,911 | ) | (1,517 | ) | (1,815 | ) | ||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Balance at January 1 | (1,911 | ) | (1,517 | ) | (1,815 | ) | ||||||
Postretirement benefits liability adjustment: | ||||||||||||
Current period change excluding amounts reclassified from accumulated other comprehensive income | (212 | ) | (505 | ) | 158 | |||||||
Amounts reclassified from accumulated other comprehensive income | 134 | 111 | 140 | |||||||||
Balance at December 31 | �� | (1,989 | ) | (1,911 | ) | (1,517 | ) | |||||
Amounts reclassified out of accumulated other comprehensive income (loss) -
before-tax
income (expense):| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Amortization of postretirement benefits liability adjustment included in net periodic benefit cost (a) | (180 | ) | (148 | ) | (185 | ) | ||||||
| millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Amortization of postretirement benefits liability adjustment included in net periodic benefit cost (a) | (148 | ) | (185 | ) | (194 | ) | ||||||
(a) This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 5). | ||||||||||||
| (a) | This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 5). |
Income tax expense (credit) for components of other comprehensive income (loss):
| millions of Canadian dollars | 2019 | | 2017 | |||||||||
Postretirement benefits liability adjustments: | ||||||||||||
Postretirement benefits liability adjustment (excluding amortization) | (165 | ) | 59 | (20 | ) | |||||||
Amortization of postretirement benefits liability adjustment included in net periodic benefit cost | 37 | 45 | 58 | |||||||||
Total | (128 | ) | 104 | 38 | ||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Postretirement benefits liability adjustments: | ||||||||||||
Postretirement benefits liability adjustment (excluding amortization) | (69 | ) | (165 | ) | 59 | |||||||
Amortization of postretirement benefits liability adjustment included in net periodic benefit cost | 46 | 37 | 45 | |||||||||
Total | (23 | ) | (128 | ) | 104 | |||||||
The information on pages 96107 to 97108 excludes items not related to oil and natural gas extraction, such as administrative and general expenses, pipeline operations, gas plant processing fees and gains or losses on asset sales. The company’s 25 percent interest in proved synthetic oil reserves in the Syncrude joint-venture is included as part of the company’s total proved oil and gas reserves and in the calculation of the standardized measure of discounted future cash flows, in accordance with U.S. Securities and Exchange Commission and U.S. Financial Accounting Standards Board rules. Results of operations, costs incurred in property acquisitions, exploration and development activities, and capitalized costs include the company’s share of Kearl, Syncrude and other unproved mineable acreages in the following tables.
Results of operations
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Sales to customers (a) | 3,927 | 3,264 | 3,283 | |||||||||
Intersegment sales (a) (b) | 2,627 | 1,964 | 1,750 | |||||||||
| 6,554 | 5,228 | 5,033 | ||||||||||
Production expenses | 4,467 | 4,342 | 3,959 | |||||||||
Exploration expenses | 47 | 19 | 183 | |||||||||
Depreciation and depletion | 1,266 | 1,151 | 1,623 | |||||||||
Income taxes | (487 | ) | (92 | ) | (217 | ) | ||||||
Results of operations | 1,261 | (192 | ) | (515 | ) |
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Sales to customers (a) | 2,066 | 3,927 | 3,264 | |||||||||
Intersegment sales (a) (b) | 1,777 | 2,627 | 1,964 | |||||||||
3,843 | 6,554 | 5,228 | ||||||||||
Production expenses | 3,977 | 4,467 | 4,342 | |||||||||
Exploration expenses | 13 | 47 | 19 | |||||||||
Depreciation and depletion (includes impairments) | 2,857 | 1,266 | 1,151 | |||||||||
Income taxes | (678 | ) | (487 | ) | (92 | ) | ||||||
Results of operations | (2,326 | ) | 1,261 | (192 | ) | |||||||
The amounts reported as costs incurred in property acquisitions, exploration and development activities include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date.
Costs incurred in property acquisitions, exploration and development activities
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Property costs (c) | ||||||||||||
Proved | - | - | - | |||||||||
Unproved | 2 | - | 32 | |||||||||
Exploration costs | 47 | 19 | 40 | |||||||||
Development costs | 1,176 | 966 | 214 | |||||||||
Total costs incurred in property acquisitions, exploration and development activities | 1,225 | 985 | 286 |
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Property costs (c) | ||||||||||||
Proved | - | - | - | |||||||||
Unproved | - | 2 | - | |||||||||
Exploration costs | 13 | 47 | 19 | |||||||||
Development costs | 816 | 1,176 | 966 | |||||||||
Total costs incurred in property acquisitions, exploration and development activities | 829 | 1,225 | 985 | |||||||||
| (a) | 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 or diluent costs. These items are reported gross in note 3 in “Revenues”, “Intersegment sales” and in “Purchases of crude oil and products”. |
| (b) | 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. |
| (c) | “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. |
Capitalized costs | ||||||||
millions of Canadian dollars | 2019 | 2018 | ||||||
Property costs (a) | ||||||||
Proved | 2,236 | 2,296 | ||||||
Unproved | 2,342 | 2,372 | ||||||
Producing assets | 38,975 | 38,695 | ||||||
Incomplete construction | 1,640 | 1,214 | ||||||
Total capitalized cost | 45,193 | 44,577 | ||||||
Accumulated depreciation and depletion | (15,695 | ) | (14,897 | ) | ||||
Net capitalized costs | 29,498 | 29,680 | ||||||
Capitalized costs
| millions of Canadian dollars | 2020 | 2019 | ||||||
Property costs (a) | ||||||||
Proved | 2,070 | 2,236 | ||||||
Unproved | 2,462 | 2,342 | ||||||
Producing assets | 39,785 | 38,975 | ||||||
Incomplete construction | 1,518 | 1,640 | ||||||
Total capitalized cost | 45,835 | 45,193 | ||||||
Accumulated depreciation and depletion | (18,551 | ) | (15,695 | ) | ||||
Net capitalized costs | 27,284 | 29,498 | ||||||
| (a) | “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. |
Standardized measure of discounted future cash flows
As required by the U.S. Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applyingaverage prices,average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change.
first-day-of-the-month
year-end
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, includingfirst-day-of-the-month
Standardized measure of discounted future net cash flows related to proved oil and gas reserves
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Future cash flows | 166,801 | 174,326 | 72,325 | |||||||||
Future production costs | (127,911 | ) | (124,316 | ) | (44,822 | ) | ||||||
Future development costs | (24,759 | ) | (25,507 | ) | (14,640 | ) | ||||||
Future income taxes | (3,960 | ) | (5,232 | ) | (3,916 | ) | ||||||
Future net cash flows | 10,171 | 19,271 | 8,947 | |||||||||
Annual discount of 10 percent for estimated timing of cash flows | (4,660 | ) | (10,537 | ) | (3,811 | ) | ||||||
Discounted future cash flows | 5,511 | 8,734 | 5,136 |
millions of Canadian dollars | 2019 | 2018 | 2017 | |||||||||
Balance at beginning of year | 8,734 | 5,136 | 2,746 | |||||||||
Changes resulting from: | ||||||||||||
Sales and transfers of oil and gas produced, net of production costs | (2,441 | ) | (1,117 | ) | (1,516 | ) | ||||||
Net changes in prices, development costs and production costs (a) | (3,117 | ) | 1,395 | 4,231 | ||||||||
Extensions, discoveries, additions and improved recovery, less related costs | 169 | 259 | 81 | |||||||||
Development costs incurred during the year | 1,016 | 923 | 376 | |||||||||
Revisions of previous quantity estimates | (168 | ) | 2,157 | 110 | ||||||||
Accretion of discount | 643 | 584 | 290 | |||||||||
Net change in income taxes | 675 | (603 | ) | (1,182 | ) | |||||||
Net change | (3,223 | ) | 3,598 | 2,390 | ||||||||
Balance at end of year | 5,511 | 8,734 | 5,136 |
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Future cash flows | 23,911 | 166,801 | 174,326 | |||||||||
Future production costs | (18,787 | ) | (127,911 | ) | (124,316 | ) | ||||||
Future development costs | (6,096 | ) | (24,759 | ) | (25,507 | ) | ||||||
Future income taxes | (155 | ) | (3,960 | ) | (5,232 | ) | ||||||
Future net cash flows | (1,127 | ) | 10,171 | 19,271 | ||||||||
Annual discount of 10 percent for estimated timing of cash flows | 1,065 | (4,660 | ) | (10,537 | ) | |||||||
Discounted future cash flows | (62 | ) | 5,511 | 8,734 | ||||||||
Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves | ||||||||||||
| millions of Canadian dollars | 2020 | 2019 | 2018 | |||||||||
Balance at beginning of year | 5,511 | 8,734 | 5,136 | |||||||||
Changes resulting from: | ||||||||||||
Sales and transfers of oil and gas produced, net of production costs | (447 | ) | (2,441 | ) | (1,117 | ) | ||||||
Net changes in prices, development costs and production costs (a) | (8,661 | ) | (3,117 | ) | 1,395 | |||||||
Extensions, discoveries, additions and improved recovery, less related costs | 114 | 169 | 259 | |||||||||
Development costs incurred during the year | 563 | 1,016 | 923 | |||||||||
Revisions of previous quantity estimates | 459 | (168 | ) | 2,157 | ||||||||
Accretion of discount | 623 | 643 | 584 | |||||||||
Net change in income taxes | 1,776 | 675 | (603 | ) | ||||||||
Net change | (5,573 | ) | (3,223 | ) | 3,598 | |||||||
Balance at end of year | (62 | ) | 5,511 | 8,734 | ||||||||
| (a) | SEC rules require the company’s reserves to be calculated on the basis of average first-day-of-the-month |
Net proved reserves
(a)
| Liquids | (b) | Natural gas | Synthetic oil | Bitumen | Total oil-equivalent basis (c) | | ||||||||||||||
| millions of barrels | billions of cubic feet | millions of barrels | millions of barrels | millions of barrels | ||||||||||||||||
Beginning of year 2017 | 35 | 495 | 564 | 701 | 1,382 | |||||||||||||||
Revisions | 4 | 115 | (70 | ) | 332 | 286 | ||||||||||||||
Improved recovery | - | 1 | - | 6 | 6 | |||||||||||||||
(Sale) purchase of reserves in place | 4 | 28 | - | - | 9 | |||||||||||||||
Discoveries and extensions | 2 | 43 | - | - | 9 | |||||||||||||||
Production | (1 | ) | (41 | ) | (21 | ) | (93 | ) | (122 | ) | ||||||||||
End of year 2017 | 44 | 641 | 473 | 946 | 1,570 | |||||||||||||||
Revisions | 4 | (66 | ) | 15 | 2,313 | 2,321 | ||||||||||||||
Improved recovery | - | - | - | - | - | |||||||||||||||
(Sale) purchase of reserves in place | - | - | - | - | - | |||||||||||||||
Discoveries and extensions | 16 | 110 | - | - | 34 | |||||||||||||||
Production | (2 | ) | (46 | ) | (22 | ) | (93 | ) | (125 | ) | ||||||||||
End of year 2018 | 62 | 639 | 466 | 3,166 | 3,800 | |||||||||||||||
Revisions | (20 | ) | (33 | ) | (27 | ) | (134 | ) | (187 | ) | ||||||||||
Improved recovery | - | - | - | - | - | |||||||||||||||
(Sale) purchase of reserves in place | - | (24 | ) | - | - | (4 | ) | |||||||||||||
Discoveries and extensions | 4 | 51 | - | - | 13 | |||||||||||||||
Production | (5 | ) | (52 | ) | (24 | ) | (93 | ) | (130 | ) | ||||||||||
End of year 2019 | 41 | 581 | 415 | 2,939 | 3,492 | |||||||||||||||
Net proved developed reserves included above, as of | ||||||||||||||||||||
January 1, 2017 | 19 | 263 | 564 | 436 | 1,063 | |||||||||||||||
December 31, 2017 | 9 | 282 | 473 | 591 | 1,120 | |||||||||||||||
December 31, 2018 | 24 | 273 | 466 | 2,861 | 3,396 | |||||||||||||||
December 31, 2019 | 22 | 291 | 415 | 2,609 | 3,095 | |||||||||||||||
Net proved undeveloped reserves included above, as of | ||||||||||||||||||||
January 1, 2017 | 16 | 232 | - | 265 | 319 | |||||||||||||||
December 31, 2017 | 35 | 359 | - | 355 | 450 | |||||||||||||||
December 31, 2018 | 38 | 366 | - | 305 | 404 | |||||||||||||||
December 31, 2019 | 19 | 290 | - | 330 | 397 | |||||||||||||||
| Liquids (b) | Natural gas | Synthetic oil | Bitumen | Total oil-equivalent basis (c) | ||||||||||||||||
| millions of barrels | billions of cubic feet | millions of barrels | millions of barrels | millions of barrels | ||||||||||||||||
Beginning of year 2018 | 44 | 641 | 473 | 946 | 1,570 | |||||||||||||||
Revisions | 4 | (66 | ) | 15 | 2,313 | 2,321 | ||||||||||||||
Improved recovery | - | - | - | - | - | |||||||||||||||
(Sale) purchase of reserves in place | - | - | - | - | - | |||||||||||||||
Discoveries and extensions | 16 | 110 | - | - | 34 | |||||||||||||||
Production | (2 | ) | (46 | ) | (22 | ) | (93 | ) | (125 | ) | ||||||||||
End of year 2018 | 62 | 639 | 466 | 3,166 | 3,800 | |||||||||||||||
Revisions | (20 | ) | (33 | ) | (27 | ) | (134 | ) | (187 | ) | ||||||||||
Improved recovery | - | - | - | - | - | |||||||||||||||
(Sale) purchase of reserves in place | - | (24 | ) | - | - | (4 | ) | |||||||||||||
Discoveries and extensions | 4 | 51 | - | - | 13 | |||||||||||||||
Production | (5 | ) | (52 | ) | (24 | ) | (93 | ) | (130 | ) | ||||||||||
End of year 2019 | 41 | 581 | 415 | 2,939 | 3,492 | |||||||||||||||
Revisions | (29 | ) | (348 | ) | (79 | ) | (2,757 | ) | (2,923 | ) | ||||||||||
Improved recovery | - | - | - | - | - | |||||||||||||||
(Sale) purchase of reserves in place | - | (10 | ) | - | - | (2 | ) | |||||||||||||
Discoveries and extensions | - | - | 133 | 1 | 134 | |||||||||||||||
Production | (5 | ) | (55 | ) | (25 | ) | (102 | ) | (141 | ) | ||||||||||
End of year 2020 | 7 | 168 | 444 | 81 | 560 | |||||||||||||||
Net proved developed reserves included above, as of | ||||||||||||||||||||
January 1, 2018 | 9 | 282 | 473 | 591 | 1,120 | |||||||||||||||
December 31, 2018 | 24 | 273 | 466 | 2,861 | 3,396 | |||||||||||||||
December 31, 2019 | 22 | �� | 291 | 415 | 2,609 | 3,095 | ||||||||||||||
December 31, 2020 | 7 | 167 | 311 | 76 | 422 | |||||||||||||||
Net proved undeveloped reserves included above, as of | ||||||||||||||||||||
January 1, 2018 | 35 | 359 | - | 355 | 450 | |||||||||||||||
December 31, 2018 | 38 | 366 | - | 305 | 404 | |||||||||||||||
December 31, 2019 | 19 | 290 | - | 330 | 397 | |||||||||||||||
December 31, 2020 | - | 1 | 133 | 5 | 138 | |||||||||||||||
| (a) | 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. |
| (b) | Liquids include crude, condensate and natural gas liquids (NGLs). NGL proved reserves are not material and are therefore included under liquids. |
| (c) | Gas converted to oil-equivalent at six million cubic feet per one thousand barrels. |
The information above describes changes during the years and balances of proved oil and gas reserves at2017, 2018, 2019 and 2019.2020. The definitions used are in accordance with the U.S. Securities and Exchange Commission’s Rule
year-end
4-10
(a) of RegulationS-X.
Proved oil and natural gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire. In some cases, substantial new investments in additional wells and other facilities will be required to recover these proved reserves.
In accordance with SEC rules, theprice for each month within such period. These reserves quantities were also used in calculatingdepreciation rates and in calculating the standardized measure of discounted net cash flow.
year-end
reserves volumes, as well as the reserves change categories shown in the proved reserves tables are required to be calculated on the basis of average prices during the12-month
period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of thefirst-day-of-the-month
unit-of-production
Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation oroil and natural gas prices and / or costs that are used in the estimation of reserves. Revisions can result from significant changes in either development strategy or production equipment / facility capacity.
re-evaluation
of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in the average offirst-day-of-the-month
At
year-end
2016, downward revisions of proved developed and undeveloped bitumen reserves were a result of low prices. The entire 2.5 billion barrels of bitumen at Kearl and approximately 0.2 billion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the U.S. Securities and Exchange Commission definition of proved reserves.At
year-end
2017, an additional 0.3 billion barrels of bitumen at Kearl and Cold Lake qualified as proved reserves resulting from improved prices in the year. Downward revisions of proved developed synthetic oil reserves were a result of higher royalty obligations driven by higher pricing and mine plan updates.As a result of improved prices in 2018, an additional 2.3 billion barrels of bitumen at Kearl qualified as proved reserves at2018.
year-end 2018.
In 2019, downward revisions to proved bitumen reserves were driven by technical and development plan updates at Kearl, resulting in a decrease of 0.2 billion barrels, partially offset by an increase of 0.1 billion barrels at Cold Lake associated with an end of field life change driven by pricing. Downward revisions to proved synthetic oil reserves were a result of higher royalty obligations at Syncrude driven by pricing. Changes to liquids and natural gas proved reserves were the result of updated development plans at the Montney and Duvernay unconventional assets and the divestment of conventional properties.
In 2020, downward revisions of proved bitumen reserves were a result of low prices. The 2.2 billion barrels of bitumen at Kearl and 0.6 billion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the U.S. Securities and Exchange Commission definition of proved reserves. Downward revisions to proved synthetic oil reserves were a result of lower prices, offset by the addition of proved undeveloped reserves associated with future development at Syncrude. Changes to the liquids and natural gas proved reserves were the result of updated development plans at the Montney and Duvernay unconventional assets and the divestment of conventional properties.
Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial. The company’s operating decisions andcompany does not expect its outlook for future production volumes are not impactedoperations to be affected by the downward revision of reported proved reserves as disclosed under the U.S. Securities and Exchange Commission (SEC) definition.
Net proved reserves are determined by deducting the estimated future share of mineral owners or governments or both. For liquids and natural gas, net proved reserves are based on estimated future royalty rates as of the date the estimate is made incorporating the applicable governments’ oil and gas royalty regimes. For bitumen, net proved reserves are based on the company’s best estimate of average royalty rates over the remaining life of each of the Cold Lake and Kearl fields, and they incorporate the Alberta government’s oil sands royalty regime. For synthetic oil, net proved reserves are based on the company’s best estimate of average royalty rates over the remaining life of the project, and they incorporate the Alberta government’s oil sands royalty regime. In all cases, actual future royalty rates may vary with production, price and costs.
110
Net proved developed reserves are those volumes that are expected to be recovered through existing wells and facilities with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well or facility. Net proved undeveloped reserves are those volumes that are expected to be recovered as a result of future investments to drill new wells, to recomplete existing wells and/and / or to install facilities to collect and deliver the production from existing and future wells and facilities.
Quarterly financial data
| 2019 | 2018 | |||||||||||||||||||||||||||||||
| three months ended | three months ended | |||||||||||||||||||||||||||||||
| Dec. 31 | Sept. 30 | June 30 | Mar. 31 | Dec. 31 | Sept. 30 | June 30 | Mar. 31 | |||||||||||||||||||||||||
Financial data (millions of Canadian dollars) | ||||||||||||||||||||||||||||||||
Total revenues and other income | 8,122 | 8,736 | 9,261 | 7,982 | 7,890 | 9,732 | 9,543 | 7,934 | ||||||||||||||||||||||||
Total expenses | 7,757 | 8,182 | 8,532 | 7,584 | 6,804 | 8,706 | 9,279 | 7,237 | ||||||||||||||||||||||||
Income (loss) before income taxes | 365 | 554 | 729 | 398 | 1,086 | 1,026 | 264 | 697 | ||||||||||||||||||||||||
Income taxes | 94 | 130 | (483 | ) | 105 | 233 | 277 | 68 | 181 | |||||||||||||||||||||||
Net income (loss) | 271 | 424 | 1,212 | 293 | 853 | 749 | 196 | 516 | ||||||||||||||||||||||||
Net income (loss) (millions of Canadian dollars) | ||||||||||||||||||||||||||||||||
Upstream | 96 | 209 | 985 | 58 | (310 | ) | 222 | (6 | ) | (44 | ) | |||||||||||||||||||||
Downstream | 225 | 221 | 258 | 257 | 1,142 | 502 | 201 | 521 | ||||||||||||||||||||||||
Chemical | (2 | ) | 38 | 38 | 34 | 55 | 69 | 78 | 73 | |||||||||||||||||||||||
Corporate and other | (48 | ) | (44 | ) | (69 | ) | (56 | ) | (34 | ) | (44 | ) | (77 | ) | (34 | ) | ||||||||||||||||
Net income (loss) | 271 | 424 | 1,212 | 293 | 853 | 749 | 196 | 516 | ||||||||||||||||||||||||
Per share information (Canadian dollars) | ||||||||||||||||||||||||||||||||
Net income (loss) per common share - basic (b) | 0.36 | 0.56 | 1.58 | 0.38 | 1.08 | 0.94 | 0.24 | 0.62 | ||||||||||||||||||||||||
Net income (loss) per common share - diluted (b) | 0.36 | 0.56 | 1.57 | 0.38 | 1.08 | 0.94 | 0.24 | 0.62 | ||||||||||||||||||||||||
Dividends per common share - declared | 0.22 | 0.22 | 0.22 | 0.19 | 0.19 | 0.19 | 0.19 | 0.16 | ||||||||||||||||||||||||
2020 | 2019 | |||||||||||||||||||||||||||||||
three months ended | three months ended | |||||||||||||||||||||||||||||||
Dec. 31 | Sept. 30 | June 30 | Mar. 31 | Dec. 31 | Sept. 30 | June 30 | Mar. 31 | |||||||||||||||||||||||||
Financial data (millions of Canadian dollars) | ||||||||||||||||||||||||||||||||
Total revenues and other income | 6,033 | 5,955 | 3,710 | 6,690 | 8,122 | 8,736 | 9,261 | 7,982 | ||||||||||||||||||||||||
Total expenses | 7,496 | 5,952 | 4,403 | 6,945 | 7,757 | 8,182 | 8,532 | 7,584 | ||||||||||||||||||||||||
Income (loss) before income taxes | (1,463 | ) | 3 | (693 | ) | (255 | ) | 365 | 554 | 729 | 398 | |||||||||||||||||||||
Income taxes | (317 | ) | - | (167 | ) | (67 | ) | 94 | 130 | (483 | ) | 105 | ||||||||||||||||||||
Net income (loss) | (1,146 | ) | 3 | (526 | ) | (188 | ) | 271 | 424 | 1,212 | 293 | |||||||||||||||||||||
Net income (loss) (millions of Canadian dollars) | ||||||||||||||||||||||||||||||||
Upstream | (1,192 | ) | (74 | ) | (444 | ) | (608 | ) | 96 | 209 | 985 | 58 | ||||||||||||||||||||
Downstream | 106 | 77 | (32 | ) | 402 | 225 | 221 | 258 | 257 | |||||||||||||||||||||||
Chemical | 23 | 27 | 7 | 21 | (2 | ) | 38 | 38 | 34 | |||||||||||||||||||||||
Corporate and other | (83 | ) | (27 | ) | (57 | ) | (3 | ) | (48 | ) | (44 | ) | (69 | ) | (56 | ) | ||||||||||||||||
Net income (loss) | (1,146 | ) | 3 | (526 | ) | (188 | ) | 271 | 424 | 1,212 | 293 | |||||||||||||||||||||
Per share information (Canadian dollars) | ||||||||||||||||||||||||||||||||
Net income (loss) per common share - basic (b) | (1.56 | ) | - | (0.72 | ) | (0.25 | ) | 0.36 | 0.56 | 1.58 | 0.38 | |||||||||||||||||||||
Net income (loss) per common share - diluted (b) | (1.56 | ) | - | (0.72 | ) | (0.25 | ) | 0.36 | 0.56 | 1.57 | 0.38 | |||||||||||||||||||||
Dividends per common share - declared | 0.22 | 0.22 | 0.22 | 0.22 | 0.22 | 0.22 | 0.22 | 0.19 | ||||||||||||||||||||||||
| (a) | Quarterly data has not been audited by the company’s independent auditors. |
| (b) | Computed using the average number of shares outstanding during each period. The sum of the four quarters may not add to the full year. |
Proxy information
section
| Table of contents | Page | |||
114 | ||||
119 | ||||
150 | ||||
181 | ||||
Nominees for director
The director nominee tables on the following pages provide information on the seven nominees proposed for election to the board of directors of the company. All of the nominees, with the exception of M.R. Crocker, are now directors and have been since the dates indicated. D.C. Brownell is a current director and has chosen not to stand for2019. Mr. Corson2019 and assumed the additional roles of chairman and chief executive officer on January 1, 2020, following R.M. Kruger’s retirement from the company and resignation from the board on December 31, 2019.
2020.re-election.
B.W. Corson was appointed to the board and as president of the company on September 17, Included in these tables is information relating to the director nominees’ biographies, independence status, expertise, committee memberships, attendance, public board memberships and shareholdings in the company. The information is as of February 12, 2020,16, 2021, the effective date of this circular, unless otherwise indicated.
For more information on our director nominees, please see the Statement of corporate governance practice starting on page 108.120.
  | David Calgary, Alberta, Canada Nonemployee director (independent) Age: Director since : November Skills and experience: Leadership of large organizations, Operations/technical, Project management, Strategy development, Audit committee financial expert, Financial expertise, Executive compensation, Environment and sustainability, Risk management | |
| David Cornhill is a director of AltaGas Ltd., and is the chairman of the board of directors of TriSummit Utilities Inc. (formerly AltaGas Canada Inc.), a privately owned corporation. Mr. Cornhill is a founding shareholder of AltaGas (and its predecessors). He was chief executive officer of AltaGas from 1994 to 2016 and served |
as interim
co-chief
executive officer from July to December 2018. Prior to forming AltaGas, Mr. Cornhill served in various capacities with Alberta and Southern Gas Co. Ltd, including vice-president, finance and administration, treasurer and president and chief executive officer. Mr. Cornhill is an experienced leader in the business community and is a strong supporter of communities and community collaboration, investment and enhancement. He is a member of the Ivey Advisory Board at Western University. Mr. Cornhill holds a BSc (Hons.) degree and a MBA degree from Western University, and he was awarded an honorary Doctor of Laws degree by the University in 2015. Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 16, 2021 (#) | 12,500 (<0.01%) | 8,184 | 20,684 | 11,600 | 32,284 | |||||
Total market value as at February 16, 2021 ($) | 332,125 | 217,449 | 549,574 | 308,212 | 857,786 | |||||
Year over year change (#) | 0 | 4,729 | 4,729 | 3,000 | 7,729 | |||||
*Meets the necessary share ownership requirements
Board and Committee Membership | Meeting Attendance 2020 | Public Company Directorships in the Past Five Years* | ||||
Imperial Oil Limited board Audit committee Executive resources committee Public policy and corporate responsibility committee Nominations and corporate governance committee (Chair) Community collaboration and engagement committee | 8 of 8 (100%) 4 of 5 (80%) 7 of 7 (100%) 3 of 3 (100%) 4 of 4 (100%) 2 of 2 (100%) | - AltaGas Ltd. (2010 – present) - AltaGas Canada Inc. (2018 – 2020) - Alterra Power Corp. (2008 – 2018) - Painted Pony Energy Ltd. (2015 – 2017) *no public board interlocks | ||||
Voting Results of 2020 Annual General Meeting: | Other Positions in the Past Five Years: (position, date office held, and status of employer) | |||||
Votes in Favour: 661,610,537 (98.90%) | Votes Withheld: 7,375,061 (1.10%) | - AltaGas Ltd., Chairman of the board (1994 – 2019) - AltaGas Ltd., Interim co-CEO (July to December 2018)- AltaGas Ltd., Chief executive officer (1994 – 2016) | ||||
114
 | Bradley W. Corson Calgary, Alberta, Canada Non-independent director Age: 59 Director since : September 17, 2019 Skills and experience: Leadership of large organizations, Operations/technical, Project management, Global experience, Strategy development, Financial expertise, Government relations, Executive compensation, | |
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 12, 2020 (#) | 0 | 0 | 0 | 0 | 0 | |||||
Total market value as at February 12, 2020 ($) | 0 | 0 | 0 | 0 | 0 | |||||
Year over year change (#) | 0 | 0 | 0 | 0 | 0 | |||||
Attendance 2019 | ||||||
 | ||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 12, 2020 (#) | 12,500 (<0.01%) | 3,455 | 15,955 | 8,600 | 24,555 | |||||
Total market value as at February 12, 2020 ($) | 399,500 | 110,422 | 509,922 | 274,856 | 784,778 | |||||
Year over year change (#) | 0 | 2,365 | 2,365 | 3,000 | 5,365 | |||||
Attendance 2019 | ||||
 | ||
| Mr. Corson was appointed as president and a director of Imperial Oil Limited on September 17, 2019, and assumed the additional roles of chairman and chief executive | ||
| officer on January 1, 2020. Mr. Corson has worked for Exxon Mobil Corporation and its predecessor companies since 1983 in various upstream | ||
and downstream assignments, with responsibilities in the United States, Hong Kong and London. In his previous position, Mr. Corson was vice-president of Exxon Mobil Corporation and president of ExxonMobil Upstream Ventures, a division of Exxon Mobil Corporation.
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
| Holdings as at February 12, 2020 (#) | 0 | 0 | 0 | 78,200 | 78,200 | |||||
| Total market value as at February 12, 2020 ($) | 0 | 0 | 0 | 2,499,272 | 2,499,272 | |||||
| Year over year change (#) | 0 | 0 | 0 | 78,200 | 78,200 | |||||
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 16, 2021 (#) | 0 | 0 | 0 | 156,400 | 156,400 | |||||
Total market value as at February 16, 2021 ($) | 0 | 0 | 0 | 4,155,548 | 4,155,548 | |||||
Year over year change (#) | 0 | 0 | 0 | 78,200 | 78,200 | |||||
*Has three years from appointment as chairman and chief executive officer to meet the necessary share ownership requirements
Board and Committee Membership | Meeting Attendance | Public Company Directorships in the Past Five Years* | ||||
Imperial Oil Limited board (Chair) Community collaboration and engagement committee | 8 (100%) 2 of 2 (100%) | None *no public board interlocks | ||||
Voting Results of | Other Positions in the Past Five Years: (position, date office held, and status of employer) | |||||
Votes in Favour: | Votes Withheld: | - President, Imperial Oil Limited (2019 – present) - President, ExxonMobil Upstream Ventures (2015 – 2019) (Affiliate) | ||||
 | Matthew R. Crocker Spring, Texas, United States of America Non-independent director Age: 47 Director since : Not currently a member of the board; f irst nomination for election as director Skills and experience: Leadership of large organizations, Operations/technical, Project management, Global experience, Strategy development, Financial expertise, Government relations, Executive compensation, Environment and sustainability, Risk management | |
M.R. (Matthew) Crocker is senior vice-president, fuels at ExxonMobil Fuels & Lubricants Company since September, 2020. He is responsible for the downstream global fuels value chain, from crude to customer. Mr. Crocker has also held leadership positions within refining, upstream business development, chemicals |
and controllers. Prior to his current position, Mr. Crocker was vice-president, strategy and portfolio management, covering the full scope of ExxonMobil’s upstream business.
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 16, 2021 (#) | 0 | 0 | 0 | 0 | 0 | |||||
Total market value as at February 16, 2021 ($) | 0 | 0 | 0 | 0 | 0 | |||||
Year over year change (#) | 0 | 0 | 0 | 0 | 0 | |||||
*No share ownership guidelines apply
Board and Committee Membership | Meeting Attendance 2020 | Public Company Directorships in the Past Five Years* | ||
Not currently a member of the board or any of its committees | n/a | None *no public board interlocks |
Voting Results of 2020 Annual General Meeting: | Other Positions in the Past Five Years: (position, date office held, and status of employer) | |||
Votes in Favour: n/a | Votes Withheld: n/a | - Senior vice president, fuels, ExxonMobil Fuels & Lubricants Company (2020 – Present) (Affiliate) - Vice-president, strategy and portfolio management, ExxonMobil Upstream Business Development Company (2019 – 2020) (Affiliate) - Special assignment, strategy and portfolio management, ExxonMobil Upstream Business Development Company (2019 ) (Affiliate) - Vice-president, intermediates, performance derivatives, ExxonMobil Chemical Company (2017 – 2019) (Affiliate) - Project executive, ExxonMobil Refining & Supply (2016 – 2017) (Affiliate) - Manager, Baytown refinery, Exxon Mobil Corporation (2014 – 2016) (Affiliate) | ||
 |
 | Krystyna T. Hoeg Toronto, Ontario, Canada | |
Nonemployee director (independent) Age 71 Director since : May 1, 2008 Skills and experience: Leadership of large organizations, Project management, Global experience, Strategy development, Audit committee financial expert, Financial expertise, Executive compensation, Environment and sustainability, Risk management | ||
Ms. Hoeg was the president and chief executive officer of Corby Distilleries Limited from 1996 until her retirement in February 2007. She previously held several positions in the finance and controllers functions of Allied Domecq PLC and Hiram Walker & Sons Limited. Prior to that, she spent five years in public practice as a | ||
chartered accountant with the accounting firm Touche Ross. She is currently a director of New Flyer Industries Inc. and is also a director of Samuel, Son & Co. Limited, Revera Inc. and Arterra Wines Canada Inc., privately owned corporations. Ms. Hoeg is a past chair of the board of the Michael Garron Hospital.
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
| IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 12, 2020 (#) | 0 | 38,746 | 38,746 | 14,200 | 52,946 | |||||
Total market value as at February 12, 2020 ($) | 0 | 1,238,322 | 1,238,322 | 453,832 | 1,692,154 | |||||
Year over year change (#) | 0 | 3,956 | 3,956 | 2,000 | 5,956 | |||||
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 16, 2021 (#) | 0 | 46,713 | 46,713 | 16,200 | 62,913 | |||||
Total market value as at February 16, 2021 ($) | 0 | 1,241,164 | 1,241,164 | 430,434 | 1,671,598 | |||||
Year over year change (#) | 0 | 7,967 | 7,967 | 2,000 | 9,967 | |||||
Board and Committee Membership | Meeting Attendance | Public Company Directorships in the Past Five Years* | ||||
Imperial Oil Limited board Audit committee (Chair) Executive resources committee Public policy and corporate responsibility committee Nominations and corporate governance committee Community collaboration and engagement committee | 8 of 8 (100%) 5 of 5 (100%) 7 of 7 (100%) 3 of 3 (100%) 4 of 4 (100%) 2 of 2 (100%) | - New Flyer Industries Inc. (2015 – Present) - Sun Life Financial Inc. (2002 – 2016) *no public board interlocks | ||||
Voting Results of | Other Positions in the Past Five Years: (position, date office held, and status of employer) | |||||
Votes in Favour: 662,212,058 (98.99%) | Votes Withheld: | None | ||||
 | ||
 | Miranda C. Hubbs Toronto, Ontario, Canada Nonemployee director (independent) Age: 54 Director since : July 26, 2018 Skills and experience: Global experience, Strategy development, Audit committee financial expert, Financial expertise, Information technology/cybersecurity oversight, Executive compensation, Environment and sustainability, Risk management | |
Miranda Hubbs is currently an independent director of Nutrien Ltd. and co-chair of the Canadian Red Cross Tiffany Circle—Women Leading Through | ||
Philanthropy. Prior to retirement in 2011, Ms. Hubbs was executive vice president and managing director of McLean Budden. Ms. Hubbs holds a BSc from Western University and an MBA from Schulich School of Business at York University and is a CFA charterholder and a National Association of Corporate Directors Governance Fellow. Ms. Hubbs serves on the ICD Climate Strategy Advisory Board and the Global Risk Institute Sustainable Finance Advisory Committee, holds the Fundamentals of Sustainability Accounting credential from the Sustainability Accounting Standards Board, and has received her CERT Certificate in Cybersecurity Oversight issued by the Software Engineering Institute at Carnegie Mellon University.
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 12, 2020 (#) | 0 | 4,607 | 4,607 | 6,000 | 10,607 | |||||
Total market value as at February 12, 2020 ($) | 0 | 147,240 | 147,240 | 191,760 | 339,000 | |||||
Year over year change (#) | 0 | 3,153 | 3,153 | 3,000 | 6,153 | |||||
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 16, 2021 (#) | 0 | 10,913 | 10,913 | 9,000 | 19,913 | |||||
Total market value as at February 16, 2021 ($) | 0 | 289,958 | 289,958 | 239,130 | 529,088 | |||||
Year over year change (#) | 0 | 6,306 | 6,306 | 3,000 | 9,306 | |||||
*Has five years from appointment as director to meetMeets the necessary share ownership requirements
Board and Committee Membership | Meeting Attendance | Public Company Directorships in the Past Five Years* | ||||
Imperial Oil Limited board Audit committee Executive resources committee Public policy and corporate responsibility committee Nominations and corporate governance committee Community collaboration and engagement committee (Chair) | 8 of 8 (100%) 5 of 5 (100%) 7 of 7 (100%) 3 of 3 (100%) 4 of 4 (100%) 2 of 2 (100%) | - Nutrien Ltd. (2018 – present) - Agrium Inc. (2016 – 2018) - Spectra Energy Corporation (2015 – 2017) *no public board interlocks | ||||
Voting Results of | Other Positions in the Past Five Years: (position, date office held, and status of employer) | |||||
Votes in Favour: 665,197,308 (99.43%) | Votes Withheld: | None | ||||
 | ||
 | Jack M. Mintz Calgary, Alberta, Canada Nonemployee director (independent) Age 69 Director since : April 21, 2005 Skills and experience: Global experience , Strategy development, Financial expertise, Government relations, Academic/research, Executive compensation, Environment and sustainability, Risk management | |
Dr. Mintz is currently the President’s Fellow at the University of Calgary’s School of Public Policy, a position he has held since July 2015. Dr. Mintz also serves as the national policy advisor for EY (formerly Ernst & Young), Senior Fellow at | ||
member of the Canada West Foundation. From 2006 to 2015, Dr. Mintz was the founding Director and Palmer Chair in Public Policy for the University of Calgary, and from 1999 to 2006, he was the president and chief executive officer of the C.D. Howe Institute. Prior to 2007, he also held professor positions at Queen’s University and the Joseph L. Rotman School of Management at the University of Toronto. Dr. Mintz also has published widely in the fields of public economics and fiscal federalism, has been an advisor to governments on fiscal matters, and has frequently published articles in national newspapers and magazines. Dr. Mintz received the Order of Canada in 2015.
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 12, 2020 (#) | 1,000 (<0.01%) | 34,448 | 35,448 | 14,200 | 49,648 | |||||
Total market value as at February 12, 2020 ($) | 31,960 | 1,100,958 | 1,132,918 | 453,832 | 1,586,750 | |||||
Year over year change (#) | 0 | 3,856 | 3,856 | 2,000 | 5,856 | |||||
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 16, 2021 (#) | 1,000 (<0.01%) | 42,205 | 43,205 | 16,200 | 59,405 | |||||
Total market value as at February 16, 2021 ($) | 26,570 | 1,121,387 | 1,147,957 | 430,434 | 1,578,391 | |||||
Year over year change (#) | 0 | 7,757 | 7,757 | 2,000 | 9,757 | |||||
Board and Committee Membership | Meeting Attendance | Public Company Directorships in the Past Five Years* | ||||
Imperial Oil Limited board Audit committee Executive resources committee Public policy and corporate responsibility committee (Chair) Nominations and corporate governance committee Community collaboration and engagement committee | 8 of 8 (100%) 5 of 5 (100%) 7 of 7 (100%) 3 of 3 (100%) 4 of 4 (100%) 2 of 2 (100%) | - Morneau Shepell Inc. (2010 – *no public board interlocks | ||||
Voting Results of | Other Positions in the Past Five Years: (position, date office held, and status of employer) | |||||
Votes in Favour: 659,539,737 (98.59%) | Votes Withheld: | None | ||||
 | ||
 | David S. Sutherland Scottsdale, Arizona, United States of America Nonemployee director (independent) Age 71 Director since : April 29, 2010 Skills and experience: Leadership of large organizations, Operations/technical, Global experience, Strategy development, Audit committee financial expert, Financial expertise, Government relations, Executive compensation, Environment and sustainability, Risk management | |
In July 2007, Mr. Sutherland retired as president and chief executive officer of the former IPSCO, Inc. after spending 30 years with the company and more than five years as president and chief executive officer. Mr. Sutherland is the chairman of the board of United States Steel Corporation and director of GATX Corporation. | ||
Mr. Sutherland is also chairman of Graham Group Ltd., an employee owned corporation and is a director of Steelcraft Inc., a privately owned corporation. Mr. Sutherland is a former chairman of the American Iron and Steel Institute and served as a member of the board of directors of the Steel Manufacturers Association, the International Iron and Steel Institute, the Canadian Steel Producers Association and the National Association of Manufacturers.
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 12, 2020 (#) | 55,000 (<0.01%) | 31,761 | 86,761 | 14,200 | 100,961 | |||||
Total market value as at February 12, 2020 ($) | 1,757,800 | 1,015,082 | 2,772,882 | 453,832 | 3,226,714 | |||||
Year over year change (#) | 0 | 3,792 | 3,792 | 2,000 | 5,792 | |||||
Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) | ||||||||||
IMO Common Shares (% of class) | IMO Deferred Share Units (DSU) | Total Vested Equity Holdings (Common + DSU) | Restricted Stock Units (RSU) | Total Holdings * (Common + DSU + RSU) | ||||||
Holdings as at February 16, 2021 (#) | 55,000 (<0.01%) | 39,388 | 94,388 | 16,200 | 110,588 | |||||
Total market value as at February 16, 2021 ($) | 1,461,350 | 1,046,539 | 2,507,889 | 430,434 | 2,938,323 | |||||
Year over year change (#) | 0 | 7,627 | 7,627 | 2,000 | 9,627 | |||||
Board and Committee Membership | Meeting Attendance | Public Company Directorships in the Past Five Years* | ||||
Imperial Oil Limited board Audit committee Executive resources committee (Chair) Public policy and corporate responsibility committee Nominations and corporate governance committee Community collaboration and engagement committee | 8 (100%) 5 of 5 (100%) 6 of 7 3 of 3 (100%) 4 of 4 (100%) 2 of 2 (100%) | - GATX Corporation (2007 – Present) - United States Steel Corporation (2008 – Present) *no public board interlocks | ||||
Voting Results of | Other Positions in the Past Five Years: (position, date office held, and status of employer) | |||||
Votes in Favour: 662,963,880 (99.10%) | Votes Withheld: | None | ||||
Footnotes to director nominee tables on pages 102114 through 105:117:
(a) | The information includes the beneficial ownership of common shares of Imperial Oil Limited, which information not being within the knowledge of the company has been provided by the nominees individually. |
(b) | The company’s plan for restricted stock units for nonemployee directors is described on page |
(c) | The numbers for the company’s restricted stock units represent the total of the outstanding restricted stock units received in |
(d) | The value for Imperial Oil Limited common shares, deferred share units and restricted stock units is based on the closing price for Imperial Oil Limited common shares on the Toronto Stock Exchange of |
Director | and nominee holdings in Exxon Mobil Corporation (a) |
| Director | XOM Common Shares (#) | XOM Restricted Stock (#)(b) | Total Common Shares and Restricted Stock (#) | Total Market Value of Common Shares and Restricted Stock ($)(c) | ||||
D.C. Brownell | 2,976 | 66,500 | 69,476 | 5,641,955 | ||||
B.W. Corson | 96,903 | 144,200 | 241,103 | 19,579,314 | ||||
D.S. Sutherland | 5,730 | - | 5,730 | 465,318 | ||||
Director | XOM Common Shares (#) | XOM Restricted Stock (#) (b) | Total Common Shares and Restricted Stock (#) | Total Market Value of Common Shares and Restricted Stock ($) (c) | ||||
D.C. Brownell (d) | 3,217 | 77,000 | 80,217 | 5,294,927 | ||||
B.W. Corson | 87,758 | 116,100 | 203,858 | 13,456,164 | ||||
M.R. Crocker | 17,915 | 77,600 | 95,515 | 6,304,710 | ||||
D.S. Sutherland | 5,730 | - | 5,730 | 378,223 | ||||
(a) | Holdings as at February |
(b) | The numbers for Exxon Mobil Corporation restricted stock include outstanding restricted stock and restricted stock units granted under its restricted stock plan which is similar to the company’s restricted stock unit plan. |
(c) | The value for Exxon Mobil Corporation common shares and restricted stock is based on the closing price for Exxon Mobil Corporation common shares on the New York Stock Exchange of |
(d) | D.C. Brownell is a current director and has chosen not to stand for re-election. Mr. Brownell does not hold any Imperial Oil Limited common shares, restricted stock units or deferred share units. |
In order to better align with the Canadian Coalition for Good Governance’s policy, “Governance Differences of Equity Controlled Corporations”, in 2012, the board of directors of the company passed a resolution adopting a majority voting policy. As of the date of this circular, Exxon Mobil Corporation holds 69.6 percent of the company’s shares. If Exxon Mobil Corporation’s shareholdings were ever to fall below 50 percent, the company’s policy provides that for any
non-contested
election of directors, any director nominee who receives a greater number of votes “withheld” from his or her election than votes “for” in such election shall tender his or her resignation. Within 90 days after certification of the election results, the board of directors will decide, through a process managed by the nominations and corporate governance committee and excluding the nominee in question, whether to accept the resignation. Absent a compelling reason for the director to remain on the board, the board shall accept the resignation. The board will promptly disclose its decision and, if applicable, the reasons for rejecting the tendered resignation.Controlled company | Yes | |||
Size of board | 7 | |||
Number of independent directors | 5 | |||
Women on board | 2 | |||
Average attendance of directors at board and committee meetings | 99% | |||
Independent chair of the executive sessions | Yes | |||
In camera sessions of independent directors at every board meeting | Yes | |||
Independent status of audit committee | 100% | |||
Audit committee members financially literate | All | |||
Independent status of executive resources committee | 83% | |||
Independent status of nominations and corporate governance committee | 83% | |||
Majority of independent directors on all committees | Yes | |||
Individual director elections | Yes | |||
Average tenure of director nominees (approximate) | ||||
Average age of director nominees (approximate) | 62 years | |||
Mandatory retirement age | 72 years | |||
Majority voting policy | Yes | |||
Separate board chair and CEO | No | |||
Number of board interlocks | None | |||
No director serves on more than two boards of another reporting issuer | Yes | |||
Share ownership requirements for independent directors | Yes | |||
Share ownership requirements for chairman and chief executive officer | Yes | |||
Board orientation and education program | Yes | |||
Code of business conduct and ethics | Yes | |||
Board and committee charters | Yes | |||
Position descriptions for the chairman and chief executive officer and the chair of each committee | Yes | |||
Skills matrix for directors | Yes | |||
Annual board evaluation process | Yes | |||
Annual advisory vote on executive compensation | No | |||
Dual-class shares | No | |||
Change of control agreements | No | |||
This section provides information pertaining to our board, the committees of the board, ethics, diversity and shareholder engagement. The company is committed to high corporate governance standards and best practices. The company’s corporate governance policies and practices comply with and in most cases exceed the requirements of(NI(NP(NI
National Instrument
52-110
Audit Committees52-110),
National Policy
58-201
Corporate Governance Guidelines58-201)
andNational Instrument
58-101
Disclosure of Corporate Governance Practices58-101).
The company’s common shares trade on the Toronto Stock Exchange and the NYSE American LLC and our corporate governance practices reflect the standards of these exchanges. In accordance with NYSE American LLC requirements fornon-U.S.
companies, the company is in compliance with NYSE American standards in all significant respects except as described on the company’s website atwww.imperialoil.ca
.
The company continually reviews its governance practices and monitors regulatory changes. |
More information on diversity, including on the board and among executive officers of the company, can be found at page 132.145.
The board charter provides that incumbent directors will not be
re-nominated
if they have attained the age of 72, except under exceptional circumstances and at the request of the chairman. The company does not have term limits for independent directors because it values the comprehensive knowledge of the company that long serving directors possess and independent directors are expected to remain qualified to serve for a minimum of five years. The following chart shows the current years of service of the nominees for the board of directors and the year they would normally be expected to retire from the board.Name of director nominee | Years of service on the board | Year of expected retirement from the board for independent directors | ||
| 3 years | 2026 | |||
B.W. Corson | 1 year | - | ||
M.R. Crocker (a) | ||||
| - | ||||
K.T. Hoeg | 2022 | |||
M.C. Hubbs | 2039 | |||
J.M. Mintz | 2023 | |||
D.S. Sutherland | 2022 | |||
| (a) | M.R. Crocker is being nominated for election as a director at the annual meeting of shareholders and is not currently a director. |
Our directors bring a wide range of skills, diversity and experience. |
The current directors and director nominees collectively have the experience and expertise required to ensure effective oversight, stewardship and governance of the company. The key areas of experience and skills for each of the nominees for election as directors can also be found in each of the nominees tables on pages 102114 through 105117 of this circular.
The table below sets out the diverse skill set required of the board and identifies the particular experience, qualifications, attributes, and skills of each director and nominee that led the board to conclude that such person should serve as a director of the company.
D.C. Brownell (a) | D.W. Cornhill | B.W. Corson | Crocker (b) | K.T. Hoeg | M.C. Hubbs | J.M. Mintz | D.S. Sutherland | |||||||||
Leadership of large organizations | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ||||||||||
Operations / technical | ∎ | ∎ | ∎ | ∎ | ∎ | |||||||||||
Project management | ∎ | ∎ | ∎ | ∎ | ∎ | |||||||||||
Global experience | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | |||||||||
Strategy development | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ||||||||
∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | |||||||||
Audit committee financial expert | ∎ | ∎ | ∎ | ∎ | ||||||||||||
Financial expertise | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ||||||||
Government relations | ∎ | ∎ | ∎ | ∎ | ∎ | |||||||||||
Academic / research | ∎ | |||||||||||||||
Information technology / cybersecurity oversight | ∎ | |||||||||||||||
Executive compensation | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ||||||||
∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | ∎ | |||||||||
(a) | re-election at the |
(b) | M.R. Crocker is being nominated for election as a director at the annual meeting of shareholders and is not currently a director. |
Independence of our board members
Five out of seven of the director nominees are independent. |
The board is currently composed of seven directors, and allsix of whom will be standing for1, 2020.4, 2021. D.C. Brownell is a current director and has chosen not to stand for
re-election
at the annual meeting of shareholders on May re-election.
M.R. Crocker is not currently a director and is being nominated for election as a director. The majority of the board and nominees (five out of seven) are independent. The independent directors are not employees of the company.The board determines independence on the basis of the standards specified by(NIthe U.S. Securities and Exchange Commission rules and the listing standards of the NYSE American LLC. The board has reviewed relevant relationships between the company and each nonemployee director and director nominee to determine compliance with these standards.
National Instrument
52-110
Audit Committees52-110)
,
Based on the directors’ responses to an annual questionnaire, the board determined that none of the independent directors has any interest, business or other relationship that could or could reasonably be perceived to constitute a material relationship with the company. B.W. Corson is a director and chairman, president and chief executive officer of the company and not considered to be independent. The board believes that Mr. Corson’s extensive knowledge of the business of the company and Exxon Mobil Corporation is beneficial to the other directors and his participation enhances the effectiveness of the board.
D.C. Brownell is also aofficeremployee of Exxon Mobil Corporation. Mr. Brownell has chosen not to stand forhistheir employment, can be viewed as independent of the company’s management and that histheir ability to reflect the perspective of the company’s shareholders enhances the effectiveness of the board.
non-independent
director as he is an re-election
at the annual meeting of shareholders. Director nominee, M.R. Crocker, holds the position of senior vice-president, fuels at ExxonMobil Fuels & Lubricants Company, a division of Exxon Mobil Corporation and if elected will also be anon-independent
director. The company believes that Mr. Brownell, and Mr. Crocker, although deemednon-independent
under the relevant standards by virtue of Name of director | Independent | Not independent | Reason for non-independent status | |||||||||
D.C. Brownell | ∎ | D.C. Brownell is an | Mr. Brownell has chosen not to stand for re-election and will cease to be a director on May 4, 2021. | |||||||||
D.W. Cornhill | ∎ | |||||||||||
B.W. Corson | ∎ | ∎ | B.W. Corson is a director and chairman, president and chief executive officer of Imperial Oil Limited. | |||||||||
M.R. Crocker | ∎ | M.R. Crocker is an employee of Exxon Mobil Corporation. Mr. Crocker is a nominee for election as a director at the annual meeting of shareholders. | ||||||||||
K.T. Hoeg | ∎ | |||||||||||
M.C. Hubbs | ∎ | |||||||||||
J.M. Mintz | ∎ | |||||||||||
D.S. Sutherland | ∎ | |||||||||||
Committee membership of our board
Each committee is chaired by a different independent director and all of the independent directors are members of each committee. |
The chart below shows the company’s current committee memberships and the chair of each committee.
and corporate governance committee | committee | and corporate responsibility committee | resources committee | collaboration and engagement committee | ||||||||
Nominations and corporate governance committee | Audit committee (b) | Public policy and corporate responsibility committee | Executive resources committee | Community | collaboration and engagement committee | |||||||
D.C. Brownell | ∎ | ∎ | ∎ | ∎ | ||||||||
D.W. Cornhill | ∎ Chair | ∎ | ||||||||||
B.W. Corson (a) | - | - | - | - | ∎ | |||||||
K.T. Hoeg (c) | ∎ | ∎ Chair | ∎ | ∎ | ∎ | |||||||
M.C. Hubbs (c) | ∎ | ∎ | ∎ | ∎ | ∎ Chair | |||||||
J.M. Mintz | ∎ | ∎ | ∎ | Chair | ∎ | ∎ | ||||||
D.S. Sutherland (c) | ∎ | ∎ | ∎ | ∎ Chair | ∎ | |||||||
(a) | Not independent directors. D.C. Brownell is a current director and has chosen not to stand for re-election. |
(b) | All members of the audit committee are independent and financially literate within the meaning of National Instrument 52-110 Audit Committees and the listing standards of the NYSE American LLC. |
(c) | Audit committee financial experts under U.S. regulatory requirements. |
The chart below shows the number of board, committee and annual meetings held in 2019.2020. This includes seven regular meetings and one additional special meeting of the board that was held in relation to
COVID-19
and market conditions that arose during 2020. Due to public health recommendations and restrictions related toCOVID-19
and for the health and safety of our directors and employees, all meetings from March 2020 onwards were conducted virtually. More information on the board’s activities in relation toCOVID-19
and market conditions can be found in the Risk oversight section starting on page 129.Board or committee | ||
Number of meetings held in | ||
Imperial Oil Limited board | ||
Audit committee | 5 | |
Executive resources committee | 7 | |
Public policy and corporate responsibility committee | 3 | |
Nominations and corporate governance committee | 4 | |
Community collaboration and engagement committee | ||
Annual meeting of shareholders | 1 | |
Attendance of our board members in 20192020
99% board and committee meeting attendance from all members. |
The following chart provides a summary of the attendance record of each of the directors in 2019.2020. The attendance record of each director nominee is also set out in his or her biographical information on pages 102114 through 105.117. The attendance chart also provides an overall view of the attendance per committee. Senior management directors and other members of management periodically attend committee meetings at the request of the committee chair.
| Director | Board | Audit committee | Executive resources committee | Public policy and corporate responsibility committee (e) | Nominations and corporate governance committee | Community collaboration and engagement committee (e) | Annual meeting | Total | Percentage by director | |||||||||
D.C. Brownell | 7 of 7 | - | 7 of 7 | 3 of 3 | 4 of 4 | 1 of 1 | 1 of 1 | 23 of 23 | 100% | |||||||||
D.W. Cornhill | 7 of 7 | 4 of 5 | 7 of 7 | 3 of 3 | 4 of 4 (chair) | 1 of 1 | 1 of 1 | 27 of 28 | 96% | |||||||||
B.W. Corson (a) | 3 of 3 (chair from January 1, 2020) | - | - | - | - | 1 of 1 | - | 4 of 4 | 100% | |||||||||
K.T. Hoeg | 7 of 7 | 5 of 5 (chair) | 7 of 7 | 3 of 3 | 4 of 4 | 1 of 1 | 1 of 1 | 28 of 28 | 100% | |||||||||
M.C. Hubbs | 7 of 7 | 5 of 5 | 7 of 7 | 3 of 3 | 4 of 4 | 1 of 1 (chair) | 1 of 1 | 28 of 28 | 100% | |||||||||
R.M. Kruger (b) | 7 of 7 (chair until December 31, 2019) | - | - | - | - | 1 of 1 | 1 of 1 | 9 of 9 | 100% | |||||||||
J.M. Mintz | 7 of 7 | 5 of 5 | 7 of 7 | 3 of 3 (chair) | 4 of 4 | 1 of 1 | 1 of 1 | 28 of 28 | 100% | |||||||||
D.S. Sutherland | 7 of 7 | 5 of 5 | 7 of 7 (chair) | 3 of 3 | 4 of 4 | 1 of 1 | 1 of 1 | 28 of 28 | 100% | |||||||||
S.D. Whittaker (c) | 3 of 3 | 3 of 3 | 3 of 3 | 1 of 1 | 1 of 1 | - | 1 of 1 | 12 of 12 | 100% | |||||||||
Percentage by committee | 100% | 96% | 100% | 100% | 100% | 100% | 100% | 187 of 188 | Overall attendance 99.5% | |||||||||
Director | Board | Audit committee | Executive resources committee | Public policy and corporate responsibility committee | Nominations and corporate governance committee | Community collaboration and engagement committee | Annual meeting | Total | Percentage by director | |||||||||
D.C. Brownell | 8 of 8 | - | 7 of 7 | 3 of 3 | 4 of 4 | 2 of 2 | 1 of 1 | 25 of 25 | 100% | |||||||||
D.W. Cornhill | 8 of 8 | 4 of 5 | 7 of 7 | 3 of 3 | 4 of 4 (chair) | 2 of 2 | 1 of 1 | 29 of 30 | 97% | |||||||||
B.W. Corson | 8 of 8 (chair) | - | - | - | - | 2 of 2 | - | 10 of 10 | 100% | |||||||||
K.T. Hoeg | 8 of 8 | 5 of 5 (chair) | 7 of 7 | 3 of 3 | 4 of 4 | 2 of 2 | 1 of 1 | 30 of 30 | 100% | |||||||||
M.C. Hubbs | 8 of 8 | 5 of 5 | 7 of 7 | 3 of 3 | 4 of 4 | 2 of 2 (chair) | 1 of 1 | 30 of 30 | 100% | |||||||||
J.M. Mintz | 8 of 8 | 5 of 5 | 7 of 7 | 3 of 3 (chair) | 4 of 4 | 2 of 2 | 1 of 1 | 30 of 30 | 100% | |||||||||
D.S. Sutherland | 8 of 8 | 5 of 5 | 6 of 7 (chair) | 3 of 3 | 4 of 4 | 2 of 2 | 1 of 1 | 29 of 30 | 97% | |||||||||
Percentage by committee | 100% | 96% | 98% | 100% | 100% | 100% | 100% | 183 of 185 | Overall attendance 98.9% | |||||||||
Other public company directorships of our board members
No director or nominee serves on more than two boards of another reporting issuer. |
The following table shows which directors and nominees serve on the boards of other reporting issuers and the committee memberships in those companies.
Name of director | Other reporting issuers of which director or nominee is also a | Type of company | Stock symbol: Exchange | Committee appointments | ||||||
D.C. Brownell (a) | - | - | - | - | ||||||
D.W. Cornhill | AltaGas Ltd. | Diversified energy company | ALA:TSX | No committees | ||||||
B.W. Corson | - | - | - | - | ||||||
M.R. Crocker (b) | - | - | - | - | ||||||
K.T. Hoeg | New Flyer Industries Inc. | Manufacturer of heavy duty transit buses | NFI:TSX | Audit committee | ||||||
M.C. Hubbs | Nutrien Ltd. | Fertilizer manufacturing | NTR:TSX, NYSE | Corporate governance and nominating committee and | ||||||
J.M. Mintz | - | |||||||||
D.S. Sutherland | GATX Corporation | Commercial rail vehicles and aircraft engines – shipping | GMT:NYSE | Compensation committee (chair) | ||||||
United States Steel Corporation | Iron and steel | X:NYSE | Chairman of the board | |||||||
(a) | D.C. Brownell is a current director and has chosen not to stand for re-election at the annual meeting of shareholders. |
(b) | M.R Crocker is not currently a director and is being nominated for election as a director at the annual meeting of shareholders. |
As of the date of this proxy circular, there are no interlocking public company directorships among the directors listed in this circular.
Director qualification and selection process
The nominations and corporate governance committee is responsible for identifying and recommending new candidates for board nomination. The committee identifies candidates from a number of sources, including executive search firms and referrals from existing directors. The process for selection is described in paragraph 10 (a) of the Board of Directors Charter found in Appendix A of this circular. The committee will consider potential future candidates as required.
In considering the qualifications of potential nominees for election as directors, the nominations and corporate governance committee considers the work experience and other areas of expertise of the potential nominees, with the objective of providing for diversity among the nonemployee directors. The following key criteria are considered to be relevant to the work of the board of directors and its committees:
Work experience
| ● | Experience in leadership of businesses or other large organizations (Leadership of large organizations) |
| ● | Operations/technical experience (Operations / technical) |
| ● | Project management experience (Project management) |
| ● | Experience in working in a global work environment (Global experience) |
| ● | Experience in development of business strategy (Strategy development) |
| ● | Experience with environmental, health, community relations and/or safety policy, practices and management (Environment and sustainability) |
Other expertise
| ● | Audit committee financial expert (also see the financial expert section in the audit committee table starting on page |
| ● | Expertise in financial matters (Financial expertise) |
| ● | Expertise in managing relations with government (Government relations) |
| ● | Experience in academia or in research (Academic / research) |
| ● | Expertise in information technology and cybersecurity oversight (Information technology / cybersecurity oversight) |
| ● | Expertise in executive compensation policies and practices (Executive compensation) |
| ● | Expertise in oversight of risk management policies and practices (Risk management) |
The nominations and corporate governance committee may consider the following additional factors in assessing potential nominees:
| ● | possessing expertise in any of the following areas: law, science, marketing, administration, social/political environment or community and civic affairs; |
| ● | individual competencies in business and other areas of endeavour in contributing to the collective experience of the directors; and |
| ● | providing diversity of age, regional association, gender and other diversity elements (including Aboriginal peoples, persons with disabilities and members of visible minorities). |
The nominations and corporate governance committee assesses the work experience and other expertise each existing director possesses and whether the candidate is able to fill any gaps in such experience, expertise and diversity of age, regional association, gender and other diversity elements. Consideration is also given to whether candidates possess the ability to contribute to the broad range of issues with which the board and its committees must deal, are able to devote the necessary amount of time to prepare for and attend board and committee meetings and are free of any potential legal impediment or conflict of interest.
Candidates are expected to remain qualified to serve for a minimum of five years and independent directors are expected to achieve ownership of no less than 15,000 common shares, deferred share units and restricted share units within five years of becoming an independent director.
When the committee is recommending candidates for
re-nomination,
it assesses such candidates against the criteria forre-nomination
as set out in paragraph 10 (b) of the Board of Directors Charter found in Appendix A of this circular. Candidates forre-nomination
are expected not to change their principal position, the thrust of their involvement or their regional association in a way that would significantly detract from their value as a director of the corporation. They are also expected to continue to be compatible with the criteria that led to their selection as nominees.Director orientation, education and development
The company regularly provides in-depth presentations to the directors on relevant and emerging issues and encourages continuing education opportunities. |
The corporate secretary organizes an orientation program for all new directors. In a series of meetings over several days, new directors are briefed by staff and functional managers on all significant areas of the company’s operations, industry specific topics, risk oversight and regulatory issues. New directors are also briefed on significant company policies, organizational structure, security, information technology management and on critical planning and reserves processes. They also receive key governance and disclosure documents and a comprehensive board manual which contains a record of historical information about the company,
by-laws,
company policies, the charters of the board and its committees, other relevant company business information, information on directors’ duties and additional board related activities and calendars.Continuing education is provided to board and committee members through regular presentations by management, which focus on providing moreEachSubject to exceptional circumstances, each year the board has an extended meeting that focuses on a particular area of the company’s operations and includes a visit to one or more of the company’s operating sites or a site of relevance. In September 2019,Due to public health recommendations and restrictions related tovisited Exxon Mobil Corporation’s Houston campus, including receiving presentationsactively engaged with management on pandemic specific topics such as response and mitigation plans and actions, health and safety initiatives, and site-specific issues throughout the pandemic. Further, the board focused on strategic financial and business actions in response to ExxonMobil’s chemical operations, fuelsthe pandemic and lubricants business, research challenging market conditions. It also held refresher reviews of key risk topics in connection with the pandemic, such as crisis communication. More information on the board’s activities in relation todevelopment and other areas of collaboration between ExxonMobil and Imperial. The board andmarket conditions can be found in the committees also receivedRisk oversight section starting on page 129.
in-depth
information about key aspects of the business. COVID-19,
a site visit was not possible in 2020. However, the board COVID-19
and Although 2020 was an unprecedented year with a number of unique challenges, the board and its committees continued to receive regular presentations in 2019and updates that focused on performance, strategy and opportunities for the business. Some of these presentations included an asset impairment review, an investor relations andreview, numerous environmental, social and governance review,reviews, climate risk and carbon policy updates, a review of environmental performance, community engagement and investment updates, ongoing reviews of upstream and downstream performance and improvement plans, a review on research and technology, and a competition and anti-corruption review. The board was also provided an information technology and cybersecurity update including strategic cybersecurity priorities, key security initiatives and mitigation efforts and system improvements with respect to business continuity planning.throughout the year.
Members of ExxonMobil’s management also provide reviews of various aspects of ExxonMobil’s global business. In 2019,2020, the directors received a presentation on ExxonMobil’s information technology and cybersecurity business continuity processes,framework and operations, as well as an overview of its downstream global business,ExxonMobil’s industry environment, energy outlook update and an overview of its research and development activities.corresponding strategic objectives.
Members of the board also receive an extensive package of materials prior to each board meeting that provides a comprehensive summary on each agenda item to be discussed. Similarly, the committee members also receive a comprehensive summary on each agenda item to be discussed by that particular committee. Informational communications and other written publications or reports of interest to the directors are also forwarded routinely.
The board members are canvassed as to whether there are any additional topics relevant to the board or to a specific committee that they would like to see addressed, and management schedules presentations covering these areas. In addition, at every meeting the board receives an extensive update from the chairman, president and chief executive officer on business environment trends, relevant geopolitical activities, federal government priorities, key provincial issues and competitor activities, as appropriate.
Directors are encouraged to participate in other continuing education programs and events to ensure their skills and knowledge remain current.
127
Board performance assessment
The board and its committees, as well as the performance of the directors, are assessed on an annual basis. In 2019,For 2020, the directors engaged in a performance assessment with the chairman, president and chief executive officer, during which the directors evaluatedincludes discussion and evaluation of the board and each committee’s effectiveness in various areas. The chairman, president and chief executive officer also meets regularly with directors individually to discuss any outstanding issues. The nominations and corporate governance committee discusseddiscuss a summary of these assessment outcomes at its January 2020 meeting.in the first quarter of each year.
Leadership structure
The company has chosen to combine the positions of chairman, president and chief executive officer. The board believes the interests of all shareholders are best served at the present time through a leadership model with a combined chairman and chief executive officer position. In connectionThrough more than 37 years of experience with ExxonMobil and Imperial, the announcement of R.M. Kruger’s intention to retire at the end of 2019, B.W. Corson was appointed to the board and as president of the company on September 17, 2019. Mr. Kruger continued to hold the positions of chairman andcurrent chief executive officer until his retirementpossesses anresignation fromdemand fundamentals and the array of challenges to be faced by the company. The board on December 31, 2019,believes that the extensive experience and Mr. Corson assumedother insights put the additional roles of chairman and chief executive officer on January 1, 2020.
in the best position to provide broad leadership for the board as it considers strategy and exercises its fiduciary responsibilities. Further, the board has demonstrated its commitment and ability to provide independent oversight of management.in-depth
knowledge of the evolving energy industry supply and The company does not have a lead director. While the chairman of the board is not an independent director, K.T. Hoeg, chair of the executive sessions of the board, provides leadership for the independent directors. The duties of the chair of the executive sessions include presiding at executive sessions, and reviewing and modifying, if necessary, the agenda of the meetings of the board in advance to ensure that the board may successfully carry out its duties.duties, and acting as a liaison with the chairman of the board, including the provision of feedback, as appropriate, from the executive sessions. The position description of the chair of the executive sessions, isas well as the purpose of those executive sessions, are fully described in paragraphparagraphs 9 (c) and (d) of the Board of Directors Charter attached as Appendix A.
Independent director executive sessions
The executive sessions of the board are in camera meetings of the independent directors and are held in conjunction with every board meeting. These meetings are held in the absence of management. The independent directors held seveneight executive sessions in 2019.2020. The purposes of the executive sessions of the board include the following:
| ● | raising substantive issues that are more appropriately discussed in the absence of management; |
| ● | discussing the need to communicate to the chairman of the board any matter of concern raised by any committee or director; |
| ● | addressing issues raised but not resolved at meetings of the board and assessing any follow-up needs with the chairman of the board; |
| ● | discussing the quality, quantity, and timeliness of the flow of information from management that is necessary for the independent directors to effectively and responsibly perform their duties, and advising the chairman of the board of any changes required; and |
| ● | seeking feedback about board processes. |
In camera sessions of the board committees
Various committees also regularly hold in camera sessions without management present. The audit committee regularly holds private sessions of the committee members as well as private meetings of the committee with each of the external auditor, the internal auditor and senior management as part of every regularly scheduled committee meeting.
128
Committee structure
The board has created five committees to help carry out its duties. Each committee is chaired by a different independent director and all of the independent directors are members of each committee. D.C. Brownell is also a member of each committee, with the exception of the audit committee, which is composed entirely of independent directors. Mr. Brownell has chosen not to stand forcommittee, and R.M. Kruger was a member of this committee until his retirement and resignation from the board on December 31, 2019. S.D. Whittaker retired from the board and its committees on April 26, 2019, and was chair of the nominations and corporate governance committee until retirement.
committee.re-election
at the annual meeting of shareholders. It is anticipated that if elected, director nominee M.R. Crocker will also be a member of each committee, with the exception of the audit committee. B.W. Corson is also a member of the community collaboration and engagement 
Board committees work on key issues in greater detail than would be possible at full board meetings, allowing directors to more effectively discharge their stewardship responsibilities. The independent chairs of the five committees are able to take a leadership role in executing the board’s responsibility with respect to a specific area of the company’s operations falling within the responsibility of the committee he or she chairs. The board and each committee have a written charter that can be found in Appendix A of this circular. The charters are reviewed and approved by the board annually. The charters set out the purpose, structure, position description for the chair, and the responsibility and authority of that committee.
Risk oversight
The company is governed by a comprehensive and well-established risk management system, and the company’s success in managing risk over time has been achieved through emphasis on execution of this disciplined management framework.
129
The company’s risk management system includes a process for identifying, prioritizing, measuring, and managing the principal risks across the company, as well as assessing the company’s response to these risks. The system is implemented through various policies, guidelines, processes and systems, including:
| ● | energy outlook scenarios; |
| ● | strategic planning; |
| ● | risk management guidelines; |
| ● | code of ethics and standards of business conduct; |
| ● | delegation of authority guidelines; |
| ● | credit risk assessment guidelines; |
| ● | controls and operations integrity management systems; |
| ● | capital project management systems; |
| ● | IT risk management (including information technology, systems and cybersecurity); |
| ● | guidelines for the management and protection of information; and |
| ● | business continuity plans. |
For a discussion on the company’s risk management in relation to executive compensation, see the Compensation discussion and analysis section starting on page 142.156.
The chairman, president and chief executive officer is charged with identifying the company’s principal risks and ensuring appropriate systems are in place to manage these risks. The board of directors is responsible for reviewing the principal risks and overseeing the implementation of the risk management system, with the various committees assisting in risk oversight for issues that fall under their responsibility. For example, the audit committee oversees the company’s system of internal accounting and financial controls, the executive resources committee oversees the compensation programs and practices in relation to risk management, and the public policy and corporate responsibility committee oversees the policies and practices that manage environment, health, safety and safetysecurity risk, including the risks of climate change. This integrated risk management approach facilitates recognition and oversight of risk.
The board and its committees carry out their risk oversight responsibility through regular reviews and assessments. The board carefully considers these risks in evaluating strategic plans and specific proposals for capital expenditures and budget additions. Topic-specific assessments, such as for compliance programs, controls, stewardship of business performance, and regulatory changes, the company’s energy outlook, and climate risk and sustainability are conducted regularly and as necessary. Members of the board ask questions of management to ensure risks are identified, assessed, mitigated, and monitored. Each typical year, the board also visits one or more of the company’s operating sites or locations of importance for the company to better understand issues associated with the company’s business. MembersHowever, a site visit was not possible in 2020 due to public health recommendations and restrictions related to
COVID-19.
COVID-19
and market conditions in 2020The
COVID-19
pandemic and market conditions within the energy industry in 2020 placed a significant emphasis on the board’s role in risk oversight. Throughout the year, the board continuously reviewed and discussed with management the impact ofCOVID-19
and market conditions on performance, business strategies, employees and the community through scheduled and special meetings andad-hoc
communication. The board also guided the company through prudent business and financial action in response to market conditions. This included significant adjustments to capital and operating expenditures, while maintaining focus on the health and safety of the company’s employees, contract partners, customers and communities and reliably supplying essential products to the company’s customers.Each committee supported the board ask questionsby holding reviews and discussions of managementensure risks are identified, assessed, mitigated,their responsibilities. For example, the audit committee was responsible for maintaining the integrity of the financial statements, as well as ensuring that the quality and monitored.effectiveness of internal controls and procedures was not compromised as company adapted to work from home requirements. The public policy and corporate responsibility committee oversaw the activation of pandemic and emergency response plans and safety protocols for mitigating risk and maintaining the company’s focus on the health and safety of employees, contractors and the community. The community collaboration and engagement committee oversaw numerous initiatives to support the community through this challenging period, including a free fuel promotion for healthcare workers, donations of computers for online learning and donations of isopropyl alcohol to be used in disinfectant products.
COVID-19
topics specific to 130
The following table provides additional oversight and other information about the board and its five committees:
Board of directors The board of directors is responsible for the stewardship of the corporation. The stewardship process is carried out by the board directly or through one or more of the committees of the board. The formal mandate of the board can be found within the Board of Directors Charter in Appendix A of this circular.
131 Audit committee The role of the audit committee includes selecting and overseeing the independent auditor, reviewing the scope and results of the audit conducted by the independent auditor, and assisting the board in overseeing the integrity of the company’s financial statements. In addition, the committee’s role includes overseeing the company’s compliance with legal and regulatory requirements and the quality and effectiveness of internal controls, approving any changes in accounting principles and practices, and reviewing the results of monitoring activity under the company’s business ethics compliance program. The formal mandate of the committee can be found within the Audit Committee Charter in Appendix A of this circular.
132 Executive resources committee 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. The formal mandate of the committee can be found within the Executive Resources Committee Charter in Appendix A of this circular. | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Committee members | ● D.S. Sutherland (chair)● D.W. Cornhill (vice-chair)● D.C. Brownell | ● K.T. Hoeg● M.C. Hubbs● J.M. Mintz | ||
| None of the members of the executive resources committee currently serves as a chief executive officer of another company. | ||||
Number of meetings | Seven meetings of the executive resources committee were held in | |||
Committee highlights in | ● Reviewed executive compensation program and principles.● Reviewed strategic work planning and talent strategy plans.● Reviewed workforce and organizational changes.● Reviewed harassment policy and ● Continued focus on succession planning for senior management positions.● | |||
Committee members relevant skills and experience | D.W. Cornhill, K.T. Hoeg, M.C. Hubbs and D.S. Sutherland had extensive and lengthy experience in managing and implementing their respective companies’ compensation policies and practices in their past role as chief executive officers or members of senior management. Mr. Cornhill, Ms. Hoeg, Dr. Mintz and Mr. Sutherland serve or have served on compensation committees of one or more public companies. Accordingly, committee members are able to use this experience and knowledge derived from their roles with other companies in judging the suitability of the company’s compensation policies and practices. | |||
Role in risk oversight | The executive resources committee oversees the compensation programs and practices that are designed to encourage appropriate risk assessment and risk management. | |||
Independence | The members of the executive resources committee are independent, with the exception of D.C. Brownell, who is not considered to be independent under the rules of the U.S. Securities and Exchange Commission, Canadian securities rules and the rules of the NYSE American LLC due to his employment with Exxon Mobil Corporation. However, the Canadian Coalition for Good Governance’s policy, “Governance Differences of Equity Controlled Corporations”, views Mr. Brownell as a related director and independent of management and who may participate as a member of the company’s executive resources committee. Mr. Brownell’s participation helps to ensure an objective process for determining compensation of the company’s officers and directors and assists the deliberations of this committee by bringing the views and perspectives of the majority shareholder. | ||||||
133
Public policy and corporate responsibility committee
The role of the public policy and corporate responsibility committee is to review and monitor the company’s policies and practices in matters of the environment, health, safety, security and sustainability. The committee monitors the company’s compliance with legislative, regulatory and corporate standards in these areas, and reviews trends and current and emerging public policy. It also assesses the potential impacts of public policy on corporate performance.
The committee reviews safety and environmental performance, incidents and trends on a regular basis to ensure the company’s focus on the safety of its employees, contractors and stakeholders and on operating in an environmentally responsible manner. It also provides oversight over sustainability and climate risk, including regular reviews and assessment of sustainability performance and initiatives, as well as climate risk within the company’s risk management system and the strategies to address these risks. The formal mandate of the committee can be found within the Public Policy and Corporate Responsibility Committee Charter in Appendix A of this circular.
Committee members | ● J.M. Mintz (chair)● D.S. Sutherland (vice-chair) ● D.C. Brownell | ● D.W. Cornhill● K.T. Hoeg● M.C. Hubbs | ||
Number of meetings | Three meetings of the public policy and corporate responsibility committee were held in | |||
Committee highlights in | ● Personnel and process safety ● ● COVID-19 pandemic response and economic recovery review (policy and regulations)● ● Review of climate change policies, risks, and ● | |||
Role in risk oversight | The public policy and corporate responsibility committee reviews and monitors the company’s policies and practices in matters of environment, health, personnel and process safety and security, which policies and practices are intended to mitigate and manage risk in these COVID-19 pandemic. The committee receives regular reports from management on these matters. | |||
Independence | The members of the public policy and corporate responsibility committee are independent, with the exception of D.C. Brownell. | |||
Nominations and corporate governance committee
The role of the nominations and corporate governance committee is to oversee issues of corporate governance as they apply to the company, including the overall performance of the board, review potential nominees for directorship and review the charters of the board and any of its committees. The formal mandate of the committee can be found within the Nominations and Corporate Governance Committee Charter in Appendix A of this circular.
Committee members | ● D.W. Cornhill (chair)● J.M. Mintz (vice-chair)● D.C. Brownell | ● K.T. Hoeg● M.C. Hubbs● D.S. Sutherland | ||
Number of meetings | Four meetings of the nominations and corporate governance committee were held in | |||
Committee highlights in | ● Approval of the statement of corporate governance practices.● ● ● Recommendation to amend the board charter to add Environment and sustainability and Risk management to the directors’ skills matrix. | |||
Role in risk oversight | The nominations and corporate governance committee oversees risk by implementing an effective program for corporate governance, including board composition and succession planning. | |||
Independence | The members of the nominations and corporate governance committee are independent, with the exception of D.C. Brownell, who is not considered to be independent under the rules of the U.S. Securities and Exchange Commission, Canadian securities rules and the rules of the NYSE American LLC due to his employment with Exxon Mobil Corporation. However, the Canadian Coalition for Good Governance’s policy, “Governance Differences of Equity Controlled Corporations”, views Mr. Brownell as a related director and independent of management and who may participate as a member of the company’s nominations and corporate governance committee. Mr. Brownell’s participation helps to ensure an objective nominations process and assists the deliberations of this committee by bringing the views and perspectives of the majority shareholder. | |||
Community collaboration and engagement committee
The role of the community collaboration and engagement committee is to oversee all of the company’s community investment activities, including charitable donations. The formal mandate of the committee can be found within the Community Collaboration and Engagement Committee Charter in Appendix A of this circular.
Committee members | ● M.C. Hubbs (chair)● K.T. Hoeg (vice-chair)● D.C. Brownell● D.W. Cornhill | ● B.W. Corson● J.M. Mintz● D.S. Sutherland | ||
Number of meetings | ||||
Committee highlights in | ● Imperial ● In ● COVID-19 pandemic¡ ¡ ¡ ¡ in-kind donations including 60 tonnes of isopropyl alcohol (IPA) to the ● | |||
Independence | The majority of the members of the community collaboration and engagement committee are independent (five out of seven) with the exception of B.W. Corson and D.C. Brownell. | |||
Director compensation
Director compensation discussion and analysis
Directors’ compensation is intended to align the long-term financial interests of the directors with those of the shareholders. |
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. The nominations and corporate governance committee decided not to use an external research firm to assemble the comparator data to determine compensation for the July 1, 20192020 - June 30, 20202021 period. The committee relied instead on an
internally-led
assessment to provide competitive compensation and market data for directors’ compensation, which assisted the committee in making a compensation recommendation for the company’s directors. Theinternally-led
assessment included a review of industry survey data, with a limited amount of this survey data being provided by an independent external consultant. The internal assessment maintained the compensation design philosophy, objectives and principles, and was consistent with previous methodology used in this analysis.Employees of the company or Exxon Mobil Corporation receive no extra pay for serving as directors. Nonemployee directors receive compensation consisting of cash and restricted stock units. Since 1999, the nonemployee directors have been able to receive all or part of their cash directors’ fees in 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 deferred share unit plan is described in more detail on page 125.138.
Compensation decision making process and considerations
The nominations and corporate governance committee relies on market comparisons with a group of 19 major Canadian companies with national and international scope and complexity. The company draws its nonemployee directors from a wide variety of industrial sectors and, as such, 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.
The 19 comparator companies included in the benchmark sample are as follows:
Energy | Non-Energy | ||
Canadian Natural Resources Limited | Air Canada | ||
Cenovus Energy Inc. | Bank of Nova Scotia | ||
Enbridge Inc. | BCE Inc. | ||
Husky Energy Inc. | Canadian National Railway Company | ||
Ovintiv Inc. | Nutrien Ltd. | ||
Parkland Fuel Corporation | Royal Bank of Canada | ||
Suncor Energy Inc. | Sun Life Financial Inc. | ||
TC Energy Corporation | Teck Resources Limited | ||
TELUS Corporation | |||
The Toronto-Dominion Bank | |||
Hedging policy
Company policy prohibits all employees, including executives, and directors, from being a party to derivative or similar financial instruments, including puts, calls, or other options, future or forward contracts, or equity swaps or collars, with respect to the company or Exxon Mobil Corporation stock.
For a discussion on the process by which the compensation of the company’s executive officers is determined, see the Compensation discussion and analysis section starting on page 142.156.
Compensation details
Board retainer
The compensation of the nonemployee directors is assessed annually.
In 2018, the board approved a change to the compensation paid to the nonemployee directors. Effective July 1, 2018, the nonemployee directors received an annual retainer for board membership of $110,000 per year. The retainer for each committee chaired was eliminated, and the grant of restricted stock units was increased from 2,600 to 3,000.
��
The following table summarizes the compensation terms for the nonemployee directors in 2019:2020:
Director compensation | ||
Annual retainer terms: (a) | ||
Cash retainer: | ||
Board membership | $110,000 annually | |
Committee chair | None | |
Equity based compensation: | ||
Restricted stock units | 3,000 units (which vest on the 5 th and 10th anniversary of date of grant) | |
(a) | The nonemployee directors may elect to take all or a portion of the cash retainer in the form of deferred share units. Nonemployee directors who are appointed to the board during any given year receive the full restricted stock unit grant and a prorated cash retainer based on the date of appointment. |
Equity based compensation
Deferred share units
In 1999, an additional form of long-term incentive compensation (“deferred share units”) was made available to nonemployee directors. Nonemployee directors may elect to receive all or a portion of their cash compensation in the form of deferred share units.
The following table shows the portion of the retainer each nonemployee director elected to receive in cash and deferred share units in 2019.2020.
| Director | Election for 2019 director’s fees in cash (%) | Election for 2019 director’s fees in deferred share units (%) | Election for 2020 director’s fees in cash (%) | Election for 2020 director’s fees in deferred share units (%) | ||||
D.W. Cornhill | 25 | 75 | 25 | 75 | ||||
K.T. Hoeg | 0 | 100 | 0 | 100 | ||||
M.C. Hubbs | 0 | 100 | 0 | 100 | ||||
J.M. Mintz | 0 | 100 | 0 | 100 | ||||
D.S. Sutherland | 0 | 100 | 0 | 100 | ||||
S.D. Whittaker (a) | 100 | 0 | ||||||
The number of deferred share units granted to a nonemployee director is determined at the end of each calendar quarter for that year, according to the following calculation:
| (i) | the dollar amount of the nonemployee director’s fees for that calendar quarter that the director elected to receive as deferred share units; |
divided by
| (ii) | the average of the closing price of the company’s shares on the Toronto Stock Exchange for the five consecutive trading days (“average closing price”) immediately prior to the last day of that calendar quarter. |
Those deferred share units are granted effective the last day of that calendar quarter.
A nonemployee director is also granted additional deferred share units to represent dividends on unexercised deferred share units. These additional units are granted on the dividend payment dates for the company’s common shares, according to the following calculation:
| (i) | the cash dividend payable for a common share of the company divided by the average closing price immediately prior to the payment date for that dividend; |
multiplied by
| (ii) | the number of unexercised deferred share units held by the nonemployee directors on the dividend record date. |
A nonemployee director may only exercise deferred share units by the end of the calendar year following the year of termination of service as a director of the company, including termination of service due to death. No deferred share units may be exercised unless all of the deferred share units are exercised on the same date. On the exercise date, the cash value to be received for the units is determined based on the company’s average closing price immediately prior to the date of exercise.
Restricted stock units
In addition to the cash fees described above, the company pays a significant portion of director compensation in restricted stock units to align director compensation with the long-term interests of shareholders. The restricted stock unit plan is described in more detail beginning on page 148.163.
Up until 2015, an award of 2,000 restricted stock units was granted annually with 50 percent vesting on the third anniversary of the grant date and the remaining 50 percent vesting on the seventh anniversary of the grant date. On the third anniversary, directors receive a cash payment for the units to be vested. On the seventh anniversary, directors may elect to receive one common share for each unit or a cash payment for the units.
In 2016, in order to better align the long-term financial interests of the directors with those of the shareholders, the vesting period of the restricted stock units was increased such that 50 percent vests on the fifth anniversary of the grant date and the remaining 50 percent vests on the tenth anniversary of the grant date. For all the units to be vested, directors may elect to receive one common share for each unit or a cash payment for the units. The vesting periods are not accelerated upon separation or retirement from the board, except in the event of death. In addition, in 2016, the number of restricted stock units granted annually was increased to 2,600 units. In 2018, the number of restricted stock units granted annually was increased to 3,000 units.
In contrast to the forfeiture provisions for restricted stock units held by employees of the company, the restricted stock units awarded to nonemployee directors are not subject to risk of forfeiture at the time a director leaves the company’s board. This provision is designed to reinforce the independence of these board members. 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 nonemployee director engages in direct competition with the company or otherwise engages in any activity detrimental to the company. The board agreed that the word “detrimental” shall not include any actions taken by a nonemployee director or former nonemployee director who acted in good faith and in the best interest of the company.Prior to vesting of the restricted stock units, the nonemployee directors receive amounts equivalent to the cash dividends paid to holders of common shares. The amount is determined for each cash dividend payment date by the following calculation:
| (i) | the cash dividend payable for a common share divided by the average closing price immediately prior to the payment date for that dividend; |
multiplied by
| (ii) | the number of unvested restricted stock units held by the nonemployee directors on the dividend record date. |
Other reimbursement
Nonemployee directors are also reimbursed for travel and other expenses incurred for attendance at board and committee meetings.
Components of director compensation
The following table sets out the details of compensation paid to the nonemployee directors in 2019.2020.
Director (a) | Annual retainer for board membership ($) (b) | Restricted stock units (RSU) (#) | Total fees paid in cash ($) (c) | Total value of deferred share units (DSU) ($) (d) | Total value of restricted stock units (RSU) ($) (e) | All other compen- sation ($) (f) | Total compensation ($) | |||||||
D.W. Cornhill | 110,000 | 3,000 | 27,500 | 82,500 | 97,140 | 5,713 | 212,853 | |||||||
K.T. Hoeg | 110,000 | 3,000 | 0 | 110,000 | 97,140 | 40,655 | 247,795 | |||||||
M.C. Hubbs | 110,000 | 3,000 | 0 | 110,000 | 97,140 | 4,145 | 211,285 | |||||||
J.M. Mintz | 110,000 | 3,000 | 0 | 110,000 | 97,140 | 37,055 | 244,195 | |||||||
D.S. Sutherland | 110,000 | 3,000 | 0 | 110,000 | 97,140 | 34,806 | 241,946 | |||||||
S.D. Whittaker | 35,659 | 0 | 35,659 | 0 | 0 | 57,662 | 93,321 | |||||||
Director (a) | Annual retainer for board membership ($) | Restricted stock units (RSU) (#) | Total fees paid in cash ($) (b) | Total value of deferred share units (DSU) ($) (c) | Total value of restricted stock units (RSU) ($) (d) | All other compen- sation ($) (e) | Total compensation ($) | |||||||
D.W. Cornhill | 110,000 | 3,000 | 27,500 | 82,500 | 72,780 | 11,664 | 194,444 | |||||||
K.T. Hoeg | 110,000 | 3,000 | 0 | 110,000 | 72,780 | 49,043 | 231,823 | |||||||
M.C. Hubbs | 110,000 | 3,000 | 0 | 110,000 | 72,780 | 10,962 | 193,742 | |||||||
J.M. Mintz | 110,000 | 3,000 | 0 | 110,000 | 72,780 | 45,185 | 227,965 | |||||||
D.S. Sutherland | 110,000 | 3,000 | 0 | 110,000 | 72,780 | 42,773 | 225,553 | |||||||
(a) | As directors employed by the company or Exxon Mobil Corporation in |
“Total fees paid in cash” is the portion of the “Annual retainer for board membership” that the director elected to receive as cash. This amount is reported as “Fees earned” in the Director compensation table on page |
(c) | “Total value of deferred share units” is the portion of the “Annual retainer for board membership” that the director elected to receive as deferred share units, as set out in the previous table on page |
(d) | The values of the restricted stock units shown are the number of units multiplied by the closing price of the company’s shares on the date of grant, which was |
(e) | Amounts under “All other compensation” consist of dividend equivalent payments on unvested restricted stock units and the value of additional deferred share units granted in lieu of dividends on unvested deferred share units. In |
Director compensation table
The following table summarizes the compensation paid, payable, awarded or granted for 20192020 to each of the nonemployee directors of the company.
Name (a) | Fees earned ($)(b) | Share- based awards ($) (c) | Option- based awards ($) | Non-equity incentive plan compensation ($) | Pension value ($) | All other compensation ($) (d) | Total ($) | |||||||
D.W. Cornhill | 27,500 | 179,640 | - | - | - | 5,713 | 212,853 | |||||||
K.T. Hoeg | 0 | 207,140 | - | - | - | 40,655 | 247,795 | |||||||
M.C. Hubbs | 0 | 207,140 | - | - | - | 4,145 | 211,285 | |||||||
J.M. Mintz | 0 | 207,140 | - | - | - | 37,055 | 244,195 | |||||||
D.S. Sutherland | 0 | 207,140 | - | - | - | 34,806 | 241,946 | |||||||
S.D. Whittaker | 35,659 | 0 | - | - | - | 57,662 | 93,321 |
Name (a) | Fees earned ($)(b) | Share- based awards ($) (c) | Option- based awards ($) | Non-equity incentive plan compensation ($) | Pension value ($) | All other compensation ($) (d) | Total ($) | |||||||
D.W. Cornhill | 27,500 | 155,280 | - | - | - | 11,664 | 194,444 | |||||||
K.T. Hoeg | 0 | 182,780 | - | - | - | 49,043 | 231,823 | |||||||
M.C. Hubbs | 0 | 182,780 | - | - | - | 10,962 | 193,742 | |||||||
J.M. Mintz | 0 | 182,780 | - | - | - | 45,185 | 227,965 | |||||||
D.S. Sutherland | 0 | 182,780 | - | - | - | 42,773 | 225,553 | |||||||
(a) | As directors employed by the company or Exxon Mobil Corporation in |
(b) | Represents all fees awarded, earned, paid or payable in cash for services as a director. The nonemployee directors are able to receive all or part of their directors’ fees in the form of deferred share units. |
(c) | Represents the value of the restricted stock units (calculated by multiplying the number of units by the closing price of the company’s shares on the date of grant), plus the value of deferred share units (calculated by the portion of the “Annual retainer for board membership” that the director elected to receive as deferred share units as noted on page |
(d) | Amounts under “All other compensation” consist of dividend equivalent payments on unvested restricted stock units and the value of additional deferred share units granted in lieu of dividends on unvested deferred share units. In |
Five-year look back at total compensation paid to nonemployee directors | ||
| Year | Amount ($) | |
2015 | 1,206,084 | |
2016 | 1,342,664 | |
2017 | 1,351,454 | |
2018 | 1,500,739 | |
2019 | 1,251,395 | |
Five-year look back at total compensation paid to nonemployee directors | ||
Year | Amount ($) | |
2016 | 1,342,664 | |
2017 | 1,351,454 | |
2018 | 1,500,739 | |
2019 | 1,251,395 | |
2020 | 1,073,527 | |
Outstanding share-based awards and option-based awards for directors
The following table sets forth all outstanding awards held by nonemployee directors of the company as at December 31, 20192020 and does not include common shares owned by the director.
| Option-based awards | Share-based awards | |||||||||||
Name (a) | Number of securities underlying unexercised options (#) | Option exercise price ($) | Option expiration date | Value of unexercised in-the- money options ($) | Number of shares or units of shares that have not vested (#) (b) | Market or payout value of share-based awards that have not vested ($) (c) | ||||||
D.W. Cornhill | - | - | - | - | 12,055 | 414,089 | ||||||
K.T. Hoeg | - | - | - | - | 52,946 | 1,818,695 | ||||||
M.C. Hubbs | - | - | - | - | 10,607 | 364,350 | ||||||
J.M. Mintz | - | - | - | - | 48,648 | 1,671,059 | ||||||
D.S. Sutherland | - | - | - | - | 45,961 | 1,578,760 | ||||||
S.D. Whittaker | - | - | - | - | 68,343 | 2,347,582 | ||||||
Option-based awards | Share-based awards | |||||||||||
Name (a) | 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 (#) (b) | Market or payout value of share-based awards that have not vested ($) (c) | ||||||
D.W. Cornhill | - | - | - | - | 19,784 | 477,981 | ||||||
K.T. Hoeg | - | - | - | - | 62,913 | 1,519,978 | ||||||
M.C. Hubbs | - | - | - | - | 19,913 | 481,098 | ||||||
J.M. Mintz | - | - | - | - | 58,405 | 1,411,065 | ||||||
D.S. Sutherland | - | - | - | - | 55,588 | 1,343,006 | ||||||
(a) | As directors employed by the company or Exxon Mobil Corporation in |
(b) | Represents restricted stock units and deferred share units held as of December 31, |
(c) | Value is based on the closing price of the company’s shares on December 31, |
Incentive plan awards for directors – Value vested or earned during the year
The following table sets forth the value of the awards that vested or were earned by each nonemployee director of the company in 2019.2020.
Name (a) | Option-based awards – Value vested during the year ($) | Share-based awards – Value vested during the year ($) (b) | Non-equity incentive plan compensation – Value earned during the year ($) | |||
D.W. Cornhill | - | - | - | |||
K.T. Hoeg | - | - | ||||
M.C. Hubbs | - | - | - | |||
J.M. Mintz | - | - | ||||
D.S. Sutherland | - | |||||
| - | ||||||
(a) | As directors employed by the company or Exxon Mobil Corporation in |
(b) | Represents restricted stock units granted in |
Share ownership guidelines of independent directors and chairman, president and chief executive officer
Independent 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. Independent directors are expected to reach this level within five years from the date of appointment to the board. The chairman, president and chief executive officer has separate share ownership requirements and must, within three years of his appointment, acquire shares of the company, including common shares and restricted stock units, of a value of no less than five times his base salary.
The board of directors believes that these share ownership guidelines will result in an alignment of the interests of board members with the interests of all other shareholders. As of the date of this circular, the independent directors currently have holdings of 238,717285,103 shares which is more than three times the required guideline.
Minimum share ownership requirement | Time to fulfill | |||
Chairman, president and chief executive officer | 5 x base salary | Within 3 years of appointment | ||
Independent directors | 15,000 shares | Within 5 years of initial appointment | ||
The chart below shows the shareholdings of the independent directors and the chairman, president and chief executive officer of the company as of February 12, 2020,16, 2021, the record date of the management proxy circular.
| Director | Director since | Amount acquired since last report (February 13, 2019 to February 12, 2020) (#) | Total holdings (includes common shares, deferred share units and restricted stock units) (#) | Market value of total holdings (a) ($) | Minimum shareholding requirement | Minimum requirement met | ||||||
D.W. Cornhill | November 29, 2017 | 5,365 | 24,555 | 784,778 | 15,000 | Yes | ||||||
B.W. Corson (b) | September 17, 2019 | 78,200 | 78,200 | 2,499,272 | Five times base salary | No (b) | ||||||
K.T. Hoeg | May 1, 2008 | 5,956 | 52,946 | 1,692,154 | 15,000 | Yes | ||||||
M.C. Hubbs (c) | July 26, 2018 | 6,153 | 10,607 | 339,000 | 15,000 | No (c) | ||||||
J.M. Mintz | April 21, 2005 | 5,856 | 49,648 | 1,586,750 | 15,000 | Yes | ||||||
D.S. Sutherland | April 29, 2010 | 5,792 | 100,961 | 3,226,714 | 15,000 | Yes | ||||||
Total accumulated holdings (#) and value of directors’ holdings ($) | 316,917 | 10,128,668 | ||||||||||
Director | Director since | Amount acquired since last report ( February 13, (#)2020 to February 16, 2021) | Total holdings (includes (#)common shares, deferred share units and restricted stock units) | Market value of total holdings (a) ($) | Minimum shareholding requirement | Minimum requirement met | ||||||
D.W. Cornhill | November 29, 2017 | 7,729 | 32,284 | 857,786 | 15,000 | Yes | ||||||
B.W. Corson (b) | September 17, 2019 | 78,200 | 156,400 | 4,155,548 | Five times base salary | No (b) | ||||||
K.T. Hoeg | May 1, 2008 | 9,967 | 62,913 | 1,671,598 | 15,000 | Yes | ||||||
M.C. Hubbs | July 26, 2018 | 9,306 | 19,913 | 529,088 | 15,000 | Yes | ||||||
J.M. Mintz | April 21, 2005 | 9,757 | 59,405 | 1,578,391 | 15,000 | Yes | ||||||
D.S. Sutherland | April 29, 2010 | 9,627 | 110,588 | 2,938,323 | 15,000 | Yes | ||||||
Total accumulated holdings (#) and value of directors’ holdings ($) | 441,503 | $11,730,734 | ||||||||||
(a) | The amount shown in the column “Market value of total holdings” is equal to the “Total holdings” multiplied by the closing price of the company’s shares on the proxy circular record date February |
(b) | B.W. Corson was appointed to the board and as president of the company on September 17, 2019, and assumed the additional roles of chairman and chief executive officer on January 1, 2020. Mr. Corson is expected to meet the share ownership guidelines of five times base salary within three years of appointment as chairman and chief executive officer. |
For information relating to compensation of the company’s named executive officers, see the Compensation discussion and analysis section starting on page 142.156.
Ethical business conduct
The company is committed to high ethical standards through its policies and practices . |
The company’s directors, officers and employees are responsible for developing, approving and implementing plans and actions designed to achieve corporate objectives. In doing so, they are expected to observe the highest standards of integrity in the conduct of the company’s business, with the methods employed to attain results being as important as the results themselves.
The board has adopted a written code of ethics and business conduct (the “Code”) which can be found on the company’s website atwww.imperialoil.ca.
www.imperialoil.ca/en-CA/Investors/Investor-relations
, including any applicable amendments. The Code is applicableapplies to each of the company’s directors, officers and employees, and consists of the ethics policy, the conflicts of interest policy, the corporate assets policy, the directorships policy and the procedures and open door communication. No person in the company has the authority to make exceptions or grant waivers with respect to its foundational policies. There have been no material change reports filed in the past 12 months pertaining to conduct of a director or executive officer that constitute a departure from the Code. In addition, the directors of the company must comply with the conflict of interest provisions of the, as well as the relevant securities regulatory instruments, in order to ensure that the directors exercise independent judgment in considering transactions and agreements in respect of which such director has a material interest.
Canada Business Corporations Act
Under the company’s procedures and open door communication, employees are encouraged and expected to refer suspected violations of the law, company policy or internal controls and procedures by various means, including to their supervisors.supervisors or the company’s ethics advisor, controller or general auditor. Imperial also has an ethics “hotline” that is operated by a third-party service provider and offers confidential, anonymous reporting 24 hours a day, seven days a week. Suspected violations involving a director or executive officer, as well as any concern regarding questionable accounting or auditing matters are to be referred directly to the internal auditor. The audit committee initially reviews all issues involving directors or executive officers, and then refers all issues to the board of directors. In the alternative, employees may also address concerns to individual nonemployee directors or to nonemployee directors as a group. In addition, the directors of the company must comply with the conflict of interest provisions of theCanada Business Corporations Act, as well as the relevant securities regulatory instruments,No action may be taken or threatened against employees for asking questions, voicing concerns, or making complaints or suggestions in order to ensure that the directors exercise independent judgment in considering transactions and agreements in respect of which such director has a material interest.good faith.
Management provides the board of directors with a review of corporate ethics and conflicts of interest on an annual basis. The company’s internal auditors audit each business line’s compliance with the program and report to the audit committee. Directors, officers and employees review the company’s standards of business conduct (which includes the Code) on an annual basis, with independent directors and all employees in positions where there is a higher risk of exposure to ethical or conflict of interest situations being required to sign a declaration card confirming that they have read and are familiar with the standards of business conduct. In addition, every four years a business practices review is conducted in which managers review the standards of business conduct with all employees in their respective work units.
The board, through its audit committee, examines the effectiveness of the company’s internal control processes and management information systems. The board consults with the external auditor, the internal auditor and the management of the company to ensure the integrity of the systems.
There are a number of structures and processes in place to facilitate the functioning of the board independently of management. The board has a majority of independent directors. Each committee is chaired by a different independent director and all of the independent directors are members of each committee. The audit committee is composed entirely of independent directors. Each other committee (except the community collaboration and engagement committee) is composed entirely of the independent directors and D.C. Brownell, who is an officeremployee of Exxon Mobil Corporation and although deemedtherefore,viewed as independent of the company’s management. The agendas of each of the board and its committees are not set by management alone, but by the board as a whole and by each committee. A significant number of agenda items are mandatory and recurring. Board meetings are scheduled at least one full year in advance. Any director may call a meeting of the board or a meeting of a committee of which the director is a member. There is a board-prescribed flow of financial, operating and other corporate information to all directors.
non-independent
under the relevant standards by virtue of his employment, is 144
The independent directors conduct executive sessions in the absence of members of management. These meetings are chaired by K.T. Hoeg, the independent director designated by the independent directors to chair and lead these discussions. SevenEight executive sessions were held in 2019.2020.
The company’s delegation of authority guide provides that certain matters of the company are reviewed by functional contacts within ExxonMobil. The company’s employees are regularly reminded that they are expected to act in the best interests of the company, and are reminded of their obligation to identify any instances where the company’s general interest may not be consistent with ExxonMobil’s priorities. If such situations ever occurred, employees are expected to escalate such issues with successive levels of the company’s management. Final resolution of any such issues is made by the company’s chairman, president and chief executive officer.
Commitment to stringent safeguards with trading restrictions and reporting for company insiders. |
Structures and processes are in place to caution, track and monitor reporting insiders, nonemployee directors and key employees with access to sensitive information with respect to personal trading in the company’s shares. The company has guidelines regarding insider trading prohibitions and trading bans that are availableapplicable to all directors, officers and employees.
Nonemployee directors are required tocompanycompany’s shares and advise the company within five days of any purchase of the company’s shares. Reporting insiders are required, under securities regulations, to publically disclose all transactions in the company’s shares on the System for Electronic Disclosure by Insiders (SEDI).
pre-clear
any trades in the company’s shares. Reporting insiders are required to give advance notice to the company of any sale of the From time to time, the company advises its directors and officers, and those of Exxon Mobil Corporation, and employees in certain positions not to trade in the company’s shares. Trading bans occur in connection with the directors’ pending consideration of the financial statements of the company, including the unaudited financial statements for each quarter, and in connection with undisclosed pending events that constitute material information about the business affairs of the company.
Diversity
The company has a long history of valuing diversity on the board and in its executive management. |
Board diversity
The company has a longstanding commitment to diversity amongst its directors, and has had at least one woman on its board continuously since 1977.
The company does not have a formal written policy relating to the identification and nomination of directors who are women, Aboriginal peoples, persons with disabilities or members of visible minorities (the “designated groups”, as defined under the), and has not adopted a target regarding members of the designated groups on its board. With the objective of fostering a diversity of expertise, viewpoint and competencies, the board charter provides that the nominations and corporate governance committee may consider a number of factors, including membership in a designated group, in assessing potential nominees. The nominations and corporate governance committee assesses the work experience, other expertise, individual competencies and diversity of age, regional association and the designated groups that each existing director possesses and whether each nominee is able to fill any gaps amongst the existing directors. Additionally, the committee may consider any other factors that it believes to be relevant. The company does not believe that any one of these dimensions should be considered in isolation and without due regard to all of the other factors, in determining the ability of potential directors to contribute to the work of the board of directors.
Canada Business Corporations Regulations, 2001
As of the date of this proxy circular, the number and percentage of directors and nominees who are members of the designated groups are:
Designated group (a) | ||||
Number | Percent (%) | |||
Women | 2 of 7 (board) 2 of 7 (nominees) 2 of 5 (independent directors) | 29 29 40 | ||
Aboriginal peoples | 0 of 7 | 0 | ||
Persons with disabilities | 0 of 7 | 0 | ||
Members of visible minorities | 0 of 7 | 0 | ||
(a) | Defined under the Employment Equity Act (Canada) |
The above diversity disclosure relies on voluntary self-identification by directors and nominees, and therefore only represents the information of individuals who have chosen to self-identify. The information has not been independently verified by the company. The board nominee composition charts on page 108120 show the diversity of our board nominees with respect to gender, experience and regional association, but do not reflect membership in other designated groups.
Executive officer diversity
The company believes inclusion and diversity are key competitive strengths that are critical to maintaining the company’s position as an industry leader. To ensure commitment at all levels of the company, inclusion and diversity, anti-harassment and equal employment opportunity performance is stewarded annually to the company’s management committee.senior management. There is an
in-depth
succession planning process, which includes the consideration of various aspects of diversity as well as plans to address gaps, if any, for key positions.The company’s internal training programs emphasize the value of collaboration, appreciating differences and sustaining an inclusive work environment, keeping inclusion and diversitywith all employees. Imperial also values external perspective and expertise, and collaborates with leading diversity organizations to help shape our future inclusion and diversity plans. The company also supports educational development and recruiting practices that facilitate the employment of Indigenous peoples.peoples, and was recognized in 2020 by the Canadian Centre for Diversity and Inclusion as western Canada’s “employer initiative of the year” with respect to work done in the Indigenous community space. Imperial maintains a supportive work environment though a range of development and networking programs, including
top-of-mind
employee-led
diversity networks that are focused on common interests. These programs continued in a virtual format in 2020 as a result of theCOVID-19
pandemic.In considering potential nominees for executive officer appointments, the executive resources committee considers diversity of gender and the other designated groups, work experience, other expertise, individual competencies and other dimensions of diversity in addition to the other factors described on page 145.160. The company has not adopted a target regarding members of the designated groups in executive officer positions. The company does not believe that any one of these dimensions should be considered, without due regard to all of these other factors, in determining the ability of potential nominees to fill executive officers positions.
146
As of the date of this proxy circular, the number and percentage of executive officers of the company and its major subsidiaries who are members of the designated groups are:
Designated group (a) | ||||
Number | Percent (%) | |||
Women | ||||
Aboriginal peoples | 0 of | 0 | ||
Persons with disabilities | 0 of | 0 | ||
Members of visible minorities | 0 of | 0 | ||
(a) | Defined under the Employment Equity Act (Canada) |
The above diversity disclosure relies on voluntary self-identification by executive officers, and therefore only represents the information of individuals who have chosen to self-identify. The information has not been independently verified by the company.
Shareholder engagement strategy focuses on wide-ranging dialogue between shareholders and management. |
The company’s senior management regularly meet with institutional investors and shareholders through industry conferences, roadshows and company hosted investor events. In response toourthe company’s website. For
COVID-19
and to ensure the health and safety of our employees, investors and shareholders, these meetings were held exclusively in a virtual format for the balance of 2020. Materials from these conferences and hosted events are available on Also in response toarewas held in a virtual only format. Shareholders were given the opportunity to register a proxyholder to attend and ask questions in real time, and the company encouraged engagement from shareholders prior to the event. This format also allowed shareholders who may not otherwise have been able to attend our annual meeting in person to log in as a guest and follow the company offers a webcast of the event.meeting. The webcast is available on the company website along with speeches and presentations from the annual general meeting and the outcome of the voting on each resolution.
COVID-19
and to ensure the health and safety of its shareholders, directors, officers and stakeholders, the company took a number of steps to ensure active engagement through the annual meeting that The company also hosts regular quarterly earnings calls in connection with earnings releases, and archives of these calls (including transcripts) are available on Imperial’s website for one year after each call. These calls allow the company to provide more insight and context regarding the company’s performance, as well as directly address questions from the investment community.
The company annually solicits questions and comments from shareholders through the annual meeting of shareholders. The comments received are reviewed by senior management providing them with an indication of areas of interest to our shareholders, and those requiring a response are answered individually. In addition, the company’s Investor Relations team proactively reaches out to shareholders to obtain their views on matters identified broadly by shareholders, including with respect to environment, social and governance topics and to solicit feedback on the company’s approach to executive compensation. The Investor Relations team is available to respond to shareholder and investor queries throughout the year.
147
Largest shareholder of the company, holding 69.6% of the company’s shares.
Exxon Mobil Corporation is the majority shareholder of the company, holding 69.6% of the company’s shares. |
To the knowledge of the directors and executive officers of the company, the only shareholder who, as of February 12, 2020,16, 2021, owned beneficially, or exercised control or direction over, directly or indirectly, more than five percent of the outstanding common shares of the company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard, Irving, Texas 75039-2298, which owns beneficially 514,498,911510,916,893 common shares, representing approximately 69.6 percent of the outstanding voting shares of the company. As a consequence, the company is a “controlled company” for purposes of the listing standards of the NYSE American LLC and a “majority controlled company” for purposes of the TSX Company Manual.
The company has written procedures and controls that require any transactions between the company and ExxonMobil and its subsidiaries to be reviewed by controllers, tax, treasurers and legal to ensure that each agreement meets the company’s policies and procedures, is fair, and complies with legal and tax requirements. These agreements may also be subject to review by the chairman, president, and chief executive officer. Annual training is provided for key individuals to ensure awareness of the requirements for identifying related party transactions, and procedures are in place to ensure reporting of these transactions is complete and accurate. Related party transactions with ExxonMobil and its subsidiaries are analyzed and reviewed by management on a quarterly basis to understand any significant variances from period to period, and reviewed with the board of directors on an annual basis.
On June 27, 2018,2019, the company implemented a20182019 and June 26, 2019,2020, the company purchased 12,280,4318,724,518 common shares on the open market and a corresponding 28,110,76519,972,996 common shares from ExxonMobil concurrent with, but outside of the program to maintain its shareholding at approximately 69.6 percent. In response to market conditions, the company announced the suspension of purchases under this program on April 1, 2020. On June 27, 2019,29, 2020, a furtherimplemented.implemented, primarily to eliminate dilution from shares issued in conjunction with Imperial’s restricted stock unit plan. Under the current program, the company may purchase up to 38,211,08650,000 common shares (five percent of its outstanding common shares as of June 13, 2019) from the open market, less the amount purchased from ExxonMobil concurrent with, but outside of the program to maintain its ownership percentage at approximately 69.6 percent.shares. As of February 12, 2020,16, 2021, under the current program, the company has purchased 7,159,9536,975 common shares on the open market and 16,390,978 common sharesnone from ExxonMobil.
12-month
“normal course” share purchase program. Between June 27, 12-month
normal course share purchase program was The amounts of purchases and sales by the company and its subsidiaries for other transactions in 20192020 with ExxonMobil and its affiliates were $3,245$2,424 million and $8,552$5,101 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 technical, engineering and research and development services.costs. 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. In addition, the company has existing agreements with affiliates of ExxonMobil to provide information technology 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 ExxonMobil in Canada to operate certain western Canada production properties owned by ExxonMobil. There are no asset ownership changes.
The company and that affiliate also have a contractual agreement to provide for equal participation in new upstream opportunities. During 2007, the company entered into agreements with ExxonMobil and one of its affiliated companies that provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil.
148
As at December 31, 2019,2020, the company had an outstanding loan of $4,447 million under an existing agreement with an affiliated company of ExxonMobil that provides for a long term, variable rate loan from ExxonMobil to the company of up to $7.75 billion (Canadian) at market interest rates. The agreement is effective until June 30, 2025, cancellable if ExxonMobil provides at least 370 days advance written notice. Additionally, the company had an outstanding short-term loansloan of $111 million from an affiliated company of ExxonMobil. This loan is borrowed under an arrangement with ExxonMobil that provides for a
non-interest
bearing, revolving demand loan from ExxonMobil to the company of up to $150 million and represents ExxonMobil’s share of a working capital facility required to support purchasing, marketing, transportation and derivative arrangements for crude oil and diluent products undertaken by the company on behalf of ExxonMobil.The named executive officers of the company at year end 20192020 are listed below. In connection with R.M. Kruger’s announcement of his intention to retire at the end of 2019, B.W. Corson was appointed to the board and as president of the company on September 17, 2019. Mr. Corson is reported as a named executive officer due to the compensation received for his position as president during 2019. Mr. Kruger continued to hold the positions of chairman2019 and chief executive officer until his retirement and resignation from the board on December 31, 2019. Mr. Corson assumed the additional roles of chairman and chief executive officer on January 1, 2020. T.B. Redburn retired from the company on January 1, 2021. All other named executive officers remain in their positions as of February 12, 2020.16, 2021.
Bradley W. Corson, 59 | ||
 Calgary, Alberta, Canada | ||
 | Position held at the end of Chairman, president and chief executive officer ( | |
Other positions in the past five years (position, date office held and status of employer): | ||
President (2019 – Present) | ||
President, ExxonMobil Upstream Ventures (2015 – 2019) (Affiliate) | ||
Daniel E. Lyons, 58
 Calgary, Alberta, Canada | ||
 | Position held at the end of Senior vice-president, finance and administration, and controller (2018 – Present) | |
Other positions in the past five years (position, date office held and status of employer): | ||
Vice-president, downstream business services and downstream treasurer, Exxon Mobil Corporation (2015 – 2018) (Affiliate) | ||
Theresa B. Redburn, 59 | ||
Calgary, Alberta, Canada | ||
 | ||
Position held at the end of 2020 (date office held): | ||
Senior vice-president, commercial and corporate development (2017 – 2020) | ||
Other positions in the past five years (position, date office held and status of employer): | ||
Vice-president, upstream commercial (2014 – 2016) | ||
Simon P. Younger, 45 | ||
Calgary, Alberta, Canada | Position held at the end of 2020 (date office held): | |
 | Senior vice-president, upstream (2020 – Present) | |
Other positions in the past five years (position, date office held and status of employer): | ||
Vice-president, (2019 – 2020) | ||
Senior planning advisor, corporate strategic planning, upstream, Exxon Mobil Corporation ( | ||
Vice-president, ( | ||
150
 Bruce A. Jolly, 53 | ||
Position held at the end of | ||
 | ( | |
Other positions in the past five years (position, date office held and status of employer): | ||
Upstream controller (2018 – 2019) | ||
Controller, United States upstream production, Exxon Mobil Corporation (2016 – 2018) (Affiliate) | ||
Manager, global downstream financial coordination, Exxon Mobil Corporation (2013 – 2016) (Affiliate) | ||
Other executive officers of the company
In addition to the named executive officers listed above and on the previous page (with the exception of T.B. Redburn), the following individuals are executive officers of the company as of February 16, 2021.
Jonathan R. Wetmore, 48 | ||
Calgary, Alberta, Canada | ||
Position held (date office held): | ||
 | Vice-president, downstream and Western Canada fuels manager (2018 – Present) | |
Other positions in the past five years (position, date office held and status of employer): | ||
Manager, supply and manufacturing (June 2017 – December 2017) | ||
Refinery manager, Fawley UK, UK Esso Petroleum Company Ltd (2013 – 2017) (Affiliate) | ||
Sherri L. Evers, 44 | ||
Calgary, Alberta, Canada | ||
Position held (date office held): | ||
 | Vice-president, commercial and corporate development (2021 – Present) | |
Other positions in the past five years (position, date office held and status of employer): | ||
( | ||
Product exchange and analysis manager, refining and supply, Exxon Mobil Corporation (2016 – 2018) (Affiliate) | ||
Midwest and northeast integrated business team lead, refining and supply, Exxon Mobil Corporation (2014 – 2016) (Affiliate) | ||
Kitty Lee, 44 | ||
Calgary, Alberta, Canada | Position held (date office held) : | |
 | Treasurer | |
(2020 – Present) | ||
Other positions in the past five years (position, date office held and status of employer) : | ||
Financial advisor, treasurer’s, Exxon Mobil Corporation | ||
(2019 – 2020) (Affiliate) | ||
Benefits finance manager, treasurer’s, Exxon Mobil Corporation | ||
(2018 – 2019) (Affiliate) | ||
Global coordination manager, controller’s, Exxon Mobil Corporation | ||
(2016 – 2018) (Affiliate) | ||
Financial advisor, treasurer’s, Exxon Mobil Corporation | ||
(2015 – 2016) (Affiliate) |
