IMPERIAL OIL LTD - Annual Report: 2019 (Form 10-K)

 

 

 

 

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act:

Common Shares (without par value)

 

Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act).

...... No ✓

✓

✓

S-T

✓

non-accelerated

12b-2

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act……

b-2

non-affiliates

The number of common shares outstanding, as of February 12, 2020, was 739,223,338.

 

 

Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans are forward-looking statements. Forward-looking statements can be identified by words such as believe, anticipate, intend, propose, plan, goal, seek, project, predict, target, estimate, expect, strategy, outlook, schedule, future, continue, likely, may, should, will and similar references to future periods. Forward-looking statements in this report include, but are not limited to, references to estimates, development, timing and recovery of reserves; the improvement of recovery through experimental operations; the development drilling program at Cold Lake; the timing, cost, efficiency and production of the Aspen project and expansion project at Cold Lake; the continued evaluation of other oil sands leases and unconventional assets; future activities with respect to Beaufort Sea licences; Kearl production outlook and growth activities, including the impact from supplemental crushing facilities; the ability of rail infrastructure to mitigate pipeline capacity constraints; anticipated capital, exploration and operating expenditures, including with respect to environmental protection; anticipated share purchases; being well positioned to participate in future investments and reduce commodity price risk; the company’s long-term business outlook including demand, supply and energy mix; segment growth, competitive strategies and benefits from an integrated business model; potential impacts from carbon policy and climate related regulations; Cold Lake production outlook and reservoir performance at Nabiye; the factors affecting a return to planned activity levels at Aspen; the impact on Chemical margins from continued industry capacity additions outpacing demand growth; the benefits to the Chemical business from integration with the Sarnia refinery and relationship with ExxonMobil; earnings sensitivities; risks associated with use of derivative instruments; capital structure and financial strength as a competitive advantage, for risk mitigation and meeting funding requirements; the impact of any pending litigation, accounting standards and unrecognized tax benefits; standardized measures of discounted future cash flows; and the Strathcona refinery expansion and cogeneration projects.

Forward-looking statements are based on the company’s current expectations, estimates, projections and assumptions at the time the statements are made. Actual future financial and operating results, including expectations and assumptions concerning demand growth and energy source, supply and mix; commodity prices, foreign exchange rates and general market conditions; production rates, growth and mix; project plans, timing, costs, technical evaluations and capacities and the company’s ability to effectively execute on these plans and operate its assets; production life, resource recoveries and reservoir performance; cost savings; the adoption and impact of new facilities or technologies, including on capital efficiency, production and reductions to greenhouse gas emissions intensity; product sales; applicable laws and government policies, including taxation, climate change and production curtailment; industry capacity additions; financing sources and capital structure; and capital and environmental expenditures could differ materially depending on a number of factors. These factors include global, regional or local changes in supply and demand for oil, natural gas, and petroleum and petrochemical products and resulting price, differential and margin impacts; general economic conditions; transportation for accessing markets; political or regulatory events, including changes in law or government policy, applicable royalty rates, tax laws and production curtailment; the receipt, in a timely manner, of regulatory and third-party approvals; third party opposition to operations, projects and infrastructure; environmental risks inherent in oil and gas exploration and production activities; environmental regulation, including climate change and greenhouse gas regulation and changes to such regulation; currency exchange rates; availability and allocation of capital; availability and performance of third party service providers; unanticipated technical or operational difficulties; management effectiveness; commercial negotiations; project management and schedules and timely completion of projects; reservoir analysis and performance; unexpected technological developments; the results of research programs and new technologies, and ability to bring new technologies to commercial scale on a cost-competitive basis; operational hazards and risks; cybersecurity incidents; disaster response preparedness; the ability to develop or acquire additional reserves; and other factors discussed in Item 1A risk factors and Item 7 management’s discussion and analysis of financial condition and results of operations of this annual report on Form

Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Imperial Oil Limited. Imperial Oil Limited’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them. Imperial Oil Limited undertakes no obligation to update any forward-looking statements contained herein, except as required by applicable law.

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.

 

3

Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the (the “CBCA”) by certificate of continuance dated April 24, 1978. The head and principal office of the company is located at 505 Quarry Park Boulevard S.E., Calgary, Alberta, Canada T2C 5N1. Exxon Mobil Corporation (“ExxonMobil”) owns approximately 69.6 percent of the outstanding shares of the company. In this report, unless the context otherwise indicates, reference to the “company” or “Imperial” includes Imperial Oil Limited and its subsidiaries, and reference to ExxonMobil includes Exxon Mobil Corporation and its affiliates, as appropriate.

The company is one of Canada’s largest integrated oil companies. It is active in all phases of the petroleum industry in Canada, including the exploration for, and production and sale of, crude oil and natural gas. In Canada, it is a major producer of crude oil, the largest petroleum refiner and a leading marketer of petroleum products. It is also a major producer of petrochemicals.

The company’s operations are conducted in three main segments: Upstream, Downstream and Chemical. Upstream operations include the exploration for, and production of, crude oil, natural gas, synthetic oil and bitumen. Downstream operations consist of the transportation and refining of crude oil, blending of refined products and the distribution and marketing of those products. Chemical operations consist of the manufacturing and marketing of various petrochemicals.

Financial information about segments and geographic areas for the company is contained in the “Financial section” of this report under note 3 to the consolidated financial statements: “Business segments”.

 

4

Summary of oil and gas reserves at

The table below summarizes the net proved reserves for the company, as at December 31, 2019, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the “Financial section”, starting on page 36 of this report.

12-month

oil-equivalent

 

The estimation of proved reserves, 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. Furthermore, the company only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, changes in the amount and timing of capital investments, royalty framework and significant changes in long-term oil and gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the company’s capital spending and also impact its partners’ capacity to fund their share of joint projects. The company’s operating decisions and its outlook for future production volumes are not impacted by proved reserves as disclosed under the U.S. Securities and Exchange Commission (SEC) definition.

Imperial’s proved reserves in 2019 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.

Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including seismic data, calibrated with available well control information. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis packages.

In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.

 

5

Imperial has a dedicated reserves management group that is separate from the base operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with the U.S. Securities and Exchange Commission rules and regulations, review of annual changes in reserves estimates and the reporting of Imperial’s proved reserves. This group also maintains the official reserves estimates for Imperial’s proved reserves. In addition, this group provides training to personnel involved in the reserve estimation and reporting processes within Imperial.

The reserves management group maintains a central database containing the company’s official reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations, commercial and market assessments, analysis of well and field performance, and long standing approval guidelines. No changes may be made to reserves estimates in the central database, including the addition of any new initial reserves estimates or subsequent revisions, unless those changes have been thoroughly reviewed and evaluated by duly authorized personnel within the base operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and endorsement by the operating organization and the reserves management group, culminating in reviews with and approval by senior management and the company’s board of directors.

The internal qualified reserves evaluator is a professional geoscientist registered in Alberta, Canada and has 21 years of petroleum industry experience, including 15 years of reserves related experience. The position provides leadership to the internal reserves management group and is responsible for filing a reserves report with the Canadian securities regulatory authorities. The company’s internal reserves evaluation staff consists of 42 persons with an average of 12 years of relevant technical experience in evaluating reserves, of whom 21 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 21 persons with an average of 11 years of relevant experience in evaluating and managing the evaluation of reserves.

oil-equivalent

oil-equivalent

oil-equivalent

oil-equivalent

oil-equivalent

oil-equivalent

One of the company’s requirements to report resources as proved reserves is that management has made significant funding commitments towards the development of the reserves. The company has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. The company made investments of about $328 million during the year to progress the development of proved undeveloped reserves at the Montney and Duvernay unconventional assets and at Cold Lake. These investments represented about 26 percent of the $1,248 million in total reported Upstream capital and exploration expenditures.

 

6

Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 40 of this report for a narrative discussion on the material changes.

The company’s average daily oil production by final products sold during the three years ended December 31, 2019 was as follows. All reported production volumes were from Canada.

 

The company’s average daily production and production available for sale of natural gas during the three years ended December 31, 2019 are set forth below. All reported production volumes were from Canada. All gas volumes in this report are calculated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 40 of this report for a narrative discussion on the material changes.

 

 

7

Total average daily basis production

oil-equivalent

oil-equivalent

 

The company’s average unit sales price and average unit production costs by product type for the three years ended December 31, 2019 were as follows.

 

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.

In 2018, Imperial’s average Canadian dollar realizations for bitumen declined generally in line with Western Canada Select, adjusted for changes in the exchange rate and transportation costs. The company’s average Canadian dollar realizations for synthetic crude increased, however the widening of the western Canadian light crude differential relative to West Texas Intermediate during the fourth quarter of 2018 negatively impacted synthetic crude realizations.

 

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.

In 2018, bitumen unit production costs were higher, primarily driven by Kearl costs associated with improving reliability, partly offset by the impact of higher production.

In 2018, synthetic oil unit production costs were higher, primarily driven by higher maintenance costs, including impacts of the June 20 site-wide power disruption at Syncrude.

 

8

The company has been involved in the exploration for and development of crude oil and natural gas in Canada only.

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.

 

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.

In 2017, wells were drilled to add productive capacity, associated primarily with the Montney and Duvernay unconventional assets.

At December 31, 2019, 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.

 

To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically. Additional wells were drilled on existing phases in 2019. In 2020, 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.

in-situ

(SA-SAGD)

in-situ

 

9

SA-SAGD

in-situ

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.

The company is continuing to evaluate, develop and produce resources in its Montney and Duvernay unconventional assets in the western provinces.

3-D

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.

Canada Petroleum Resources Act

(BR-SEA)

BR-SEA

BR-SEA

The company continues to evaluate other undeveloped, mineable oil sands acreage in the Athabasca region.

 

10

open-pit

During 2019, the company’s share of Kearl’s net bitumen production was about 140,000 barrels per day and gross production was about 145,000 barrels per day.

ramp-up

in-situ

During 2019, net bitumen production at Cold Lake was about 114,000 barrels per day and gross production was about 140,000 barrels per day.

open-pit

In 2019, the company’s share of Syncrude’s net production of synthetic crude oil was about 65,000 barrels per day and gross production was about 73,000 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.

 

11

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, 2019 and December 31, 2018, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

 

The total number of wells decreased in 2019 primarily due to the divestment of mature conventional properties.

At December 31, 2019 and December 31, 2018, 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.

 

in-situ

 

12

The company’s share of Syncrude joint venture leases covering about 63,000 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 948,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas. In 2019, the company divested mature conventional properties totalling 214,000 net acres.

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.

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.

Exploration licences on Atlantic offshore have a finite term. The Atlantic offshore acreage is continued by production or held by SDLs.

 

13

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 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, and the daily rated capacities of the refineries as at December 31, 2019, were as follows.

 

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.

Refinery 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.

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.

 

14

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, there were about 2,300 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, are set out in the following table.

 

In 2019, lower sales volumes were mainly due to lower refinery throughput.

In 2018, sales growth continued to be driven by optimization across the full downstream value chain, and the expansion of Imperial’s logistic capabilities.

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, were as follows.

 

In 2019, sales volumes decreased primarily due to lower aromatics and intermediates sales.

In 2018, sales volumes were higher primarily due to higher production in polymers and basic chemicals, driven by stronger reliability.

 

15

The company regards protecting the environment in connection with its various operations as a priority. The company works in cooperation with government agencies, industry associations and communities to address existing, and to anticipate potential, environmental protection issues. In the past five years, the company has made capital and operating expenditures of about $3.9 billion on environmental protection and facilities. In 2019, the company’s environmental capital 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.

 

About 6 percent of the company’s employees are members of unions.

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.

 

16

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/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.

Approvals and licences from relevant provincial or federalgovernmental 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.

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 impose production limits on large producers in Alberta. Mandatory production curtailments decreased as 2019 progressed, but continue to be imposed on larger producers. The duration of these regulations is uncertain.

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.

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 2019 gas production rates.

 

17

The Government of Canada has the authority to regulate the export price for natural gas and has a gas export pricing policy, which accommodates export prices for natural gas negotiated between Canadian exporters and U.S. importers.

Exports of natural gas from Canada require approval by the 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.

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.

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

The Act also requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s cultural heritage or national identity. 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.

The Competition Bureau ensures 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.

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.

www.imperialoil.ca

10-K,

10-Q

8-K

 

18

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:

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 and 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 impose temporary mandatory production curtailment in 2019. Although mandatory production curtailment decreased throughout 2019, it continues to be imposed on larger producers and the duration of these regulations is uncertain. 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.

 

19

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 party opposition to company or infrastructure projects, and duration of regulatory reviews could impact Imperial’s existing operations and planned projects. 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, and could have an adverse effect on the company’s business. Government intervention in free markets may introduce unintended consequences such as market volatility and uncertainty, misallocation of resources, and erosion of investor confidence.

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.

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, 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.

 

20

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 costs and damages.

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 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.

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 whom the company does not control.

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; 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.

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.

 

 

 

None.

 

 

 

Reference is made to Item 1 above.

 

 

 

None.

 

 

 

Not applicable.

 

25

 

 

 

 

 

 

 

 

 

Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to a Canadian withholding tax of 15 percent, but may vary from one tax convention to another.

There is no Canadian tax on gains from selling shares or debt instruments owned by 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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The company will continue to evaluate its share purchase program in the context of its overall capital activities.

 

 

 

 

 

 

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.

 

 

 

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 40 of this report.

 

 

 

Reference is made to the section entitled “Market risks and other uncertainties” in the “Financial section”, starting on page 54 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.

 

27

 

 

Reference is made to the table of contents in the “Financial section” on page 36 of this report:

 

 

 

 

 

 

 

 

 

 

None.

 

 

 

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. 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 61 of this report for “Management’s report on internal control over financial reporting” and page 62 for the “Report of independent registered public accounting firm” on the company’s internal control over financial reporting as of December 31, 2019.

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.

 

 

 

None.

 

28

 

 

 

 

 

 

 

 

 

·

“Director nominee tables”, on pages 102 to 105 of this report;

·

“Skills and experience of our board members”, on page 109 of this report.

·

“Other public company directorships of our board members”, on page 113 of this report.

·

The table entitled “Audit committee” under “Board and committee structure”, on page 119 of this report;

·

“Ethical business conduct”, starting on page 131 of this report; and

·

“Largest shareholder”, on page 134 of this report.

·

“Named executive officers of the company” and “Other executive officers of the company”, on pages 136 to 139 of this report.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(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.

(c)	R.M. Kruger was the company’s chairman, president and chief executive officer until September 16, 2019, and continued as chairman and chief executive officer until his retirement on December 31, 2019.

 

 

 

 

 

 

 

 

 

 

 

 

D.C. Brownell is deemed a 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.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

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 services to be performed by the external auditor after considering the effect of such services on their independence.

PART IV

 

 

 

 

The following exhibits, numbered in accordance with Item 601 of Regulation are filed as part of this report:

(3)   (i)		Restated certificate and articles of incorporation of the company (Incorporated herein by reference to Exhibit (3.1) to the company’s Form 8-K filed on May 3, 2006 (File No. 0-12014)).
(ii)		By-laws of the company (Incorporated herein by reference to Exhibit (3)(ii) to the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 0-12014)).
(4)  (vi)		Description of capital stock.
(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 (File No. 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 (File No. 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 (File No. 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 (File No. 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 (File No. 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 (File No. 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 (File No. 0-12014)).
(iii)(A)		(1)  Form of Letter relating to Supplemental Retirement Income (Incorporated herein by reference to Exhibit (10)(c)(3) of the company’s Annual Report on Form 10-K for the year ended December 31, 1980 (File No. 2-9259)).
		(2)  Deferred Share Unit Plan for Nonemployee Directors. (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)).
		(3)  Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2008 and subsequent years, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(5)] of the company’s Form 8-K filed on November 25, 2008 (File No. 0-12014)).
		(4)  Short Term Incentive Program for selected executives effective February 2, 2012 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on February 7, 2012 (File No. 0-12014)).
		(5)  Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2011 and subsequent years, as amended effective November 14, 2011 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on February 23, 2012 (File No. 0-12014)).

 

 

 

 

 

 

 

 

 

 

 

 

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, 2020 by the undersigned, thereunto duly authorized.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

35

 

 

36