|
Annual financial statements and management's |
discussion and analysis of financial condition and |
operating results |
For the year ended December 31, 2022 |
The fol owing annual financial statements and management’s discussion and analysis should be read in |
conjunction with the company’s annual report on Form 10-K for the year ended December 31, 2022. |
Reference to Item 1A. “Risk factors” and specific page numbers in this document indicate the section and |
page numbers found in the company’s annual report on Form 10-K. The company’s annual report on Form |
10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports are |
available online at www.sedar.com, www.sec.gov and the company’s website www.imperialoil.ca. |
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. |
Al dol ar amounts set forth in this report are in Canadian dol ars, except where otherwise indicated. |
Note that numbers may not add due to rounding. |
|
Forward-looking statements |
Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans are forward-looking statements. Similarly, discussion of emission-reduction roadmaps or future plans related to carbon capture, biofuel, hydrogen, plastics recycling and other plans to drive towards net -zero emissions are dependent on future market factors, such as continued technological progress and policy support, and represent 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, wil and similar references to future periods. Forward-looking statements in this report include, but are not limited to, references to being wel positioned to participate in future investments and reduce commodity price risk; the company’s long-term business outlook including demand, supply and energy mix and pathways related to greenhouse gas emissions; the impact of participation in the Pathways al iance; Imperial’s company-wide net-zero goal by 2050 (Scope 1 and 2) and the company’s greenhouse gas emissions intensity goal for 2030 for its oil sands operations; the extent of ongoing effects of current global economic uncertainty and geopolitical events affecting supply and demand, including inflation, and the company’s ability to mitigate cost impacts and offset inflationary pressure; segment growth, competitive strategies and benefits from an integrated business model; the ability of the company’s current investment strategy of value and select volume growth to deliver robust returns and support long term growth; continued evaluation of opportunities such as rail shipments and pace of the Aspen project; the impact of Downstream strategies and competitive position and the expected volatility of refining margins; potential impacts from environmental risks, carbon policy, climate related regulations and biofuels mandates; the timing and production from the renewable diesel facility at Strathcona; the benefits to the Chemical business from integration with the Sarnia refinery and relationship with ExxonMobil; capital structure and financial strength as a competitive advantage, for risk mitigation and meeting funding requirements; expected ful year capital expenditures of about $1.7 bil ion for 2023; earnings sensitivities; risks associated with use of derivative instruments; the impact of any pending litigation, accounting standards and unrecognized tax benefits; and standardized measures of discounted future cash flow and estimates, development, timing and recovery of reserves. |
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 future energy demand, supply and mix; commodity prices and foreign exchange rates; production rates, growth and mix across various assets; production life, resource recoveries and reservoir performance; project plans, timing, costs, technical evaluations and capacities, and the company’s ability to effectively execute on these plans and operate its assets, including its investment in the renewable diesel complex at Strathcona and the Leming, Grand Rapids and LASER projects at Cold Lake; the adoption and impact of new facilities or technologies on reductions to GHG emissions intensity, including technologies using solvents to replace energy intensive steam at Cold Lake, boiler flue gas technology at Kearl, Strathcona renewable diesel, carbon capture and storage including in connection with hydrogen for the renewable diesel project, recovery technologies and efficiency projects and any changes in the scope, terms, or costs of such projects; that any required support from policymakers and other stakeholders for various new technologies such as carbon capture and storage wil be provided; for renewable diesel, the availability and cost of local y-sourced and grown feedstock and the supply of renewable diesel to British Columbia in connection with its low-carbon fuel legislation; the amount and timing of emissions reductions, including the impact of lower carbon fuels; performance of third party service providers; receipt of regulatory and third party approvals in a timely manner; applicable laws and government policies, including with respect to climate change, GHG emissions reductions and low carbon fuels; refinery utilization and product sales; the ability to offset any ongoing inflationary pressures; cash generation, financing sources and capital structure, such as dividends and shareholder returns, including the timing and amounts of share repurchases; progression of COVID-19 and its impacts on Imperial’s ability to operate its assets; capital and environmental expenditures; the capture of efficiencies within and between business lines and the ability to maintain near-term cost reductions as ongoing efficiencies; and general market conditions could differ material y depending on a number of factors. |
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These factors include global, regional or local changes in supply and demand for oil, natural gas, petroleum and petrochemical products, feedstocks and other market factors, economic conditions or seasonal fluctuations and resulting demand, price, differential and margin impacts; transportation for accessing markets; political or regulatory events, including changes in law or government policy, applicable royalty rates, tax laws including taxes on share buybacks, and actions in response to COVID-19; environmental risks inherent in oil and gas activities; environmental regulation, including climate change and greenhouse gas regulation and changes to such regulation; government policies supporting lower carbon investment opportunities; failure or delay of supportive policy and market development for emerging lower-emission energy technologies; the receipt, in a timely manner, of regulatory and third-party approvals; third-party opposition to company and service provider operations, projects and infrastructure; availability and al ocation of capital; availability and performance of third-party service providers; unanticipated technical or operational difficulties; management effectiveness and disaster response preparedness; commercial negotiations; project management and schedules and timely completion of projects; unexpected technological developments; the results of research programs and new technologies, including with respect to greenhouse gas emissions, and the ability to bring new technologies to commercial scale on a cost-competitive basis; reservoir analysis and performance; the ability to develop or acquire additional reserves; operational hazards and risks; cybersecurity incidents; currency exchange rates; the impacts of COVID-19 or other public health crises, including the effects of government responses on people and economies; general economic conditions, including the occurrence and duration of economic recessions or downturns; and other factors discussed in Item 1A Risk factors and Item 7 Management’s discussion and analysis of financial condition and results of operations in this annual report on Form 10-K. |
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’s actual results may differ material y from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them. Imperial undertakes no obligation to update any forward-looking statements contained herein, except as required by applicable law. |
Forward-looking and other statements regarding Imperial's environmental, social and other sustainability efforts and aspirations are not an indication that these statements are necessarily material to investors or requiring disclosure in the company's filings with securities regulators. In addition, historical, current and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are stil developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future, including future rule-making. |
Energy demand models are forward-looking by nature and aim to replicate system dynamics of the global energy system, requiring simplifications. The reference to any scenario in this report, including any potential net-zero scenarios, does not imply Imperial views any particular scenario as likely to occur. In addition, energy demand scenarios require assumptions on a variety of parameters. As such, the outcome of any given scenario using an energy demand model comes with a high degree of uncertainty. For example, the International Energy Agency (IEA) describes its Net Zero Emissions (NZE) by 2050 scenario as extremely chal enging, requiring unprecedented innovation, unprecedented international cooperation and sustained support and participation from consumers. Third-party scenarios discussed in this report reflect the modeling assumptions and outputs of their respective authors, not Imperial, and their use by Imperial is not an endorsement by the company of their underlying assumptions, likelihood or probability. Investment decisions are made on the basis of Imperial’s separate planning process. Any use of the modeling of a third-party organization within this report does not constitute or imply an endorsement by Imperial of any or al of the positions or activities of such organization. |
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. |
| |
Financial section |
| |
| Table of contents | Page |
| Financial information (U.S. GAAP) | | 2 |
| Frequently used terms | | 3 |
| Management’s discussion and analysis of financial condition and results of operations | | 7 |
| | | | Overview | 7 |
| | | | Business environment | 8 |
| | | | Business results | 12 |
| | | | Liquidity and capital resources | 19 |
| | | | Capital and exploration expenditures | 22 |
| | | | Market risks | 23 |
| | | | Critical accounting estimates | 25 |
| Management’s report on internal control over financial reporting | | 30 |
| Report of Independent Registered Public Accounting Firm | | 31 |
| Consolidated statement of income (U.S. GAAP) | | 34 |
| Consolidated statement of comprehensive income (U.S. GAAP) | | 35 |
| Consolidated balance sheet (U.S. GAAP) | | 36 |
| Consolidated statement of shareholders’ equity (U.S. GAAP) | | 37 |
| Consolidated statement of cash flows (U.S. GAAP) | | 38 |
| Notes to consolidated financial statements | | 39 |
| | | | 1. Summary of significant accounting policies | 39 |
| | | | 2. Business segments | 45 |
| | | | 3. Income taxes | 47 |
| | | | 4. Employee retirement benefits | 48 |
| | | | 5. Other long-term obligations | 53 |
| | | | 6. Financial and derivative instruments | 54 |
| | | | 7. Share-based incentive compensation programs | 56 |
| | | | 8. Investment and other income | 57 |
| | | | 9. Litigation and other contingencies | 57 |
| | | | 10. Common shares | 58 |
| | | | 11. Miscel aneous financial information | 60 |
| | | | 12. Financing and additional notes and loans payable information | 61 |
| | | | 13. Leases | 62 |
| | | | 14. Long-term debt | 64 |
| | | | 15. Accounting for suspended exploratory wel costs | 64 |
| | | | 16. Transactions with related parties | 65 |
| | | | 17. Other comprehensive income (loss) information | 66 |
| | | | 18. Divestment activities | 66 |
| Supplemental information on oil and gas exploration and production activities (unaudited) | | 67 |
| | | | | 1 |
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Frequently used terms |
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. Certain measures included in this document are not prescribed by U.S. General y Accepted Accounting Principles (GAAP). These measures constitute “non-GAAP financial measures” under Securities and Exchange Commission Regulation G and Item 10(e) of Regulation S-K, and “specified financial measures” under National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure of the Canadian Securities Administrators. |
Reconciliation of these non-GAAP financial measures to the most comparable GAAP measure, and other information required by these regulations, have been provided. Non-GAAP financial measures and specified financial measures are not standardized financial measures under GAAP and do not have a standardized definition. As such, these measures may not be directly comparable to measures presented by other companies, and should not be considered a substitute for GAAP financial measures. |
Capital employed Capital employed is a non-GAAP financial measure that is a measurement 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. The most directly comparable financial measure that is disclosed in the financial statements is total assets within the company’s Consolidated balance sheet. 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. |
Reconciliation of capital employed |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
From the Consolidated balance sheet |
Business uses: asset and liability perspectiveTotal assets |
| | 43,524 | 40,782 | 38,031 |
Less: Total current liabilities excluding notes and loans payable | | (8,776) | (5,432) | (3,153) |
| | | | | Total long-term liabilities excluding long-term debt | | (8,180) | (8,439) | (8,276) |
Add: Imperial’s share of equity company debt | | 25 | 20 | 26 |
Total capital employed | | 26,593 | 26,931 | 26,628 |
Total company sources: Debt and equity perspectiveNotes and loans payable |
| | 122 | 122 | 227 |
Long-term debt | | 4,033 | 5,054 | 4,957 |
Shareholders’ equity | | 22,413 | 21,735 | 21,418 |
Add: Imperial’s share of equity company debt | | 25 | 20 | 26 |
Total capital employed | | 26,593 | 26,931 | 26,628 |
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| | | | | | 3 |
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Return on average capital employed (ROCE) ROCE is a non-GAAP ratio. From the perspective of the business segments, ROCE is annual business segment net income divided by average business segment capital employed (an average of the beginning and end-of-year amounts). 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. Capital employed is a non-GAAP financial measure and is disclosed and reconciled above. The company’s total ROCE is net income excluding the 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 one of the best measures of historical capital productivity in a capital-intensive, long-term industry. Additional measures, which are more cash flow based, are used to make investment decisions. |
Components of return on average capital employed |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
From the Consolidated statement of income |
Net income (loss) | | 7,340 | 2,479 | (1,857) |
Financing (after-tax) including Imperial’s share of equity companies | | 55 | 40 | 52 |
Net income (loss) excluding financing | | 7,395 | 2,519 | (1,805) |
Average capital employed | | 26,762 | 26,780 | 28,059 |
Return on average capital employed (percent) – corporate total | | 27.6 | 9.4 | (6.4) |
Cash flows from operating activities and asset sales Cash flows from operating activities and asset sales is a non-GAAP financial measure that 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 most directly comparable financial measure that is disclosed in the financial statements is cash flows from (used in) operating activities within the company’s Consolidated statement of cash flows. The company employs a long-standing and regular disciplined review process to ensure that 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. |
Reconciliation of cash flows from (used in) operating activities and asset sales |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
From the Consolidated statement of cash flows |
Cash flows from (used in) operating activities | | 10,482 | 5,476 | 798 |
Proceeds from asset sales | | 904 | 81 | 82 |
Total cash flows from (used in) operating activities and asset sales | | 11,386 | 5,557 | 880 |
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| | | | | 4 |
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Operating costs Operating costs is a non-GAAP financial measure that 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. It excludes the cost of raw materials, taxes and interest expense and are on a before-tax basis. The most directly comparable financial measure that is disclosed in the financial statements is total expenses within the company’s Consolidated statement of income. While the company is responsible for al 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 |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
From the Consolidated statement of incomeTotal expenses |
| | 50,186 | 34,307 | 24,796 |
Less: Purchases of crude oil and products |
| | 37,742 | 23,174 | 13,293 |
Federal excise tax and fuel charge | | 2,179 | 1,928 | 1,736 |
Financing | | 60 | 54 | 64 |
Subtotal | | 39,981 | 25,156 | 15,093 |
Imperial's share of equity company expenses | | 71 | 61 | 64 |
Total operating costs | | 10,276 | 9,212 | 9,767 |
Components of operating costs |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
From the Consolidated statement of incomeProduction and manufacturing |
| | 7,404 | 6,316 | 5,535 |
Sel ing and general | | 882 | 784 | 741 |
Depreciation and depletion (includes impairments) | | 1,897 | 1,977 | 3,293 |
Non-service pension and postretirement benefit | | 17 | 42 | 121 |
Exploration | | 5 | 32 | 13 |
Subtotal | | 10,205 | 9,151 | 9,703 |
Imperial's share of equity company expenses | | 71 | 61 | 64 |
Total operating costs | | 10,276 | 9,212 | 9,767 |
| | | | | 5 |
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Management’s discussion and analysis of financial condition and results of operations |
Overview |
The fol owing discussion and analysis of Imperial’s financial results, as wel 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 integrated business model involving exploration for, and production of, crude oil and natural gas, 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 wel -positioned to participate in substantial investments to develop new Canadian energy supplies. The company’s operating segments are Upstream, Downstream, Chemicals, and Corporate and other. The company’s integrated business model general y 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 operating and capital objectives, in addition to providing the economic assumptions used for investment evaluation purposes. The foundation for the assumptions supporting the Corporate Plan is ExxonMobil’s Outlook for Energy, and Corporate Plan volume projections are based on individual field production profiles, which are also updated annual y. Price ranges for crude oil, natural gas, including price differentials, refinery and chemical margins, volumes and operating costs including greenhouse gas emissions pricing, and foreign currency exchange rates are based on Corporate Plan assumptions developed annual y and are utilized for investment evaluation purposes. Major investment opportunities are evaluated over a range of potential market conditions. Once the company makes major investments, it completes a reappraisal process to ensure that it learns from the investment decision and incorporates the lessons 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. |
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Business environment |
Long-term business outlookThe “Long-term business outlook” is based on Exxon Mobil Corporation’s Outlook for Energy (the Outlook), which combined with the near-term pathways, is used to help inform the company’s long-term business strategies and investment plans. |
The company’s business planning is underpinned by a deep understanding of long-term market fundamentals. These fundamentals include supply and demand trends, the scale and variety of energy needs worldwide; capability, practicality and affordability of energy alternatives including low-carbon solutions; greenhouse gas emission-reduction technologies; and supportive government policies. The Outlook considers these fundamentals to form the basis for the company’s long-term business planning, investment decisions, and research programs. The Outlook reflects the company’s view of global energy demand and supply through 2050. It is a projection based on current trends in technology, government policies, consumer preferences, geopolitics, and economic development. |
The Outlook uses projections and scenarios from reputable third parties such as the International Energy Agency (IEA) and the Intergovernmental Panel on Climate Change (IPCC). The IEA describes the Net Zero Emissions by 2050 (NZE) as extremely chal enging, requiring al stakeholders - governments, businesses, investors, and citizens - to take immediate, unprecedented action. The IEA acknowledges that society is not currently on the IEA NZE pathway. No single transition pathway can be reasonably predicted, given the wide range of uncertainties. Key unknowns include yet-to-be-developed government policies, market conditions, and advances in technology that may influence the cost, pace, and potential availability of certain pathways. Scenarios that employ a ful complement of technology options are likely to provide the most economical y efficient pathways. |
By 2050, the world’s population is projected at around 9.7 bil ion people, or about 2 bil ion more than in 2021. Coincident with this population increase, the Outlook projects worldwide economic growth to average close to 2.5 percent per year, with economic output growing by around 110 percent by 2050 compared to 2021. As economies and populations grow, and as living standards improve for bil ions 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 almost 15 percent from 2021 to 2050. 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)). |
As expanding prosperity drives global energy demand higher, increasing use of energy-efficient technologies and practices, as wel as lower-emission products, wil continue to help significantly reduce energy consumption and CO2 emissions per unit of economic output over time. Substantial efficiency gains are likely in al key aspects of the world’s economy through 2050, affecting energy requirements for power generation, transportation, industrial applications, and residential and commercial needs. |
Under the Outlook, global electricity demand is expected to increase over 75 percent from 2021 to 2050, with developing countries likely to account for about 80 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 expected to decline substantial y and approach 15 percent of the world’s electricity in 2050, versus nearly 35 percent in 2021, in part due to policies to improve air quality as wel as reduce greenhouse gas emissions to address risks related to climate change. From 2021 to 2050, the amount of electricity supplied using natural gas, nuclear power and renewables is expected to more than double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal. Electricity from wind and solar is expected to increase more than 550 percent, helping total renewables (including other sources, e.g., hydropower) to account for over 80 percent of the increase in electricity supplies worldwide through 2050. Total renewables are expected to reach about 50 percent of global electricity supplies by 2050. Natural gas and nuclear are expected to be about 25 percent and 10 percent, respectively, of global electricity supplies by 2050. Supplies of electricity by energy type wil reflect significant differences across regions reflecting a wide range of factors including the cost and availability of various energy supplies and policy developments. |
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Under the Outlook, energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by over 30 percent from 2021 to 2050. Transportation energy demand is expected to account for around 65 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to peak by around 2025, and then decline to levels seen in the early-2000s by 2050, 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 almost 70 percent. By 2050, light-duty vehicles are expected to account for around 15 percent of global liquid fuels demand. During the same time period, nearly al the world’s commercial transportation fleets are expected to continue to run on liquid fuels, including biofuels, which are expected to be widely available and offer practical advantages in providing a large quantity of energy in smal volumes. |
Almost half of the world’s energy use is dedicated to industrial activity. As the global middle class continues to grow, demand for durable products, appliances, and consumable goods wil increase. Industry uses energy products both as a fuel and as a feedstock for chemicals, asphalt, lubricants, waxes, and other specialty products. The Outlook anticipates technology advances, as wel as the increasing shift toward cleaner forms of energy such as electricity and natural gas, with coal declining. Demand for oil wil continue to grow as a feedstock for industry. |
As populations grow and prosperity rises, more energy wil be needed to power homes, offices, schools, shopping centers, hospitals, etc. Combined residential and commercial energy demand is projected to rise by around 15 percent through 2050. Led by the growing economies of developing nations, average worldwide household electricity use wil rise about 75 percent between 2021 and 2050. |
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 2050, global demand for liquid fuels is projected to grow to approximately 110 mil ion oil-equivalent barrels per day, an increase of about 17 percent from 2021. The non-OECD share of global liquid fuels demand is expected to increase to nearly 70 percent by 2050, as liquid fuels demand in the OECD is expected to decline by around 20 percent. Much of the global liquid fuels demand today is met by crude production from conventional sources; these supplies wil 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 2050 as technology advances continue to expand the availability of more economic and lower-carbon supply options. However, timely investments wil remain critical to meeting global needs with reliable and affordable supplies. |
Natural gas is a 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 2021 to 2050, meeting about 40 percent of global energy demand growth. Global natural gas demand is expected to rise nearly 25 percent from 2021 to 2050, with around two thirds 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 – wil help meet these needs. In total, about 50 percent of the growth in natural gas supplies is expected to be from unconventional sources. At the same time, conventional y-produced natural gas is likely to remain the cornerstone of global supply, meeting around two-thirds of worldwide demand in 2050. Liquefied natural gas (LNG) trade wil expand significantly, meeting about 50 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 wil remain so through 2050. Oil is expected to remain the largest source of energy with its share remaining close to 30 percent in 2050. Coal and natural gas are the next largest sources of energy today, with the share of natural gas growing to more than 25 percent by 2050, while the share of coal fal s to about half that of natural gas. Nuclear power is projected to grow, as many nations are likely to expand nuclear capacity to address rising electricity needs as wel as energy security and environmental issues. Total renewable energy is expected to exceed 20 percent of global energy by 2050, with other renewables (e.g., biomass, hydropower, geothermal) contributing a combined share of more than 10 percent. Total energy supplied from wind and solar is expected to increase rapidly, growing over 480 percent from 2021 to 2050, when they are projected to be around 10 percent of the world energy mix. |
| 9 |
Decarbonization of industry activities will require a suite of nascent or future lower-carbon technologies and supporting policies. Lower-emission fuels, hydrogen-based fuels, and carbon capture and storage are three key lower-carbon solutions needed to support a lower-emission future, in addition to wind and solar. Along with electrification, lower-emission fuels are expected to play an important role in decarbonization of the transportation sector, particularly in hard-to-decarbonize areas, such as aviation. Low-carbon hydrogen will be a key enabler replacing traditional furnace fuel to decarbonize the industrial sector. Hydrogen and hydrogen-based fuels like ammonia are also expected to make inroads into commercial transportation as technology improves to lower its cost and policy develops to support the needed infrastructure development. Carbon capture and storage on its own, or in combination with hydrogen production, is among the few proven technologies that could enable CO2 emission reductions from high-emitting and hard-to-decarbonize sectors such as power generation and heavy industries, including manufacturing, refining and petrochemicals. |
To meet this projected demand under the Outlook and the IEA's Stated Policies Scenario (STEPS), 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 2050 will be significant, and would be needed to meet even the rapidly declining demand for oil and gas envisioned in the IEA's Net Zero Emissions by 2050 scenario. |
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 the Outlook as a foundation for estimating energy supply and demand requirements from various energy sources and uses, and the Outlook takes 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. The Outlook reflects an environment with increasingly stringent climate policies and is consistent with the global aggregation of Nationally Determined Contributions (NDCs), submitted by the nations that are signatories to the Paris Agreement, as available at the end of 2021. The Outlook seeks to identify potential impacts of climate related government policies, which often target specific sectors. 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 provided around COP 27 in Egypt in November 2022 as well as other policy developments in light of net-zero ambitions formulated by some nations, including Canada. |
The information provided in the Outlook includes ExxonMobil's internal estimates and projections based upon internal data and analyses, as well as publicly available information from external sources including the International Energy Agency. |
Progress | reducing emissions |
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 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. |
Imperial and its industry peers launched the Oil Sands Pathways to Net Zero alliance in 2021, with the goal of working collectively with the federal and Alberta governments to achieve net-zero greenhouse gas emissions from oil sands operations by 2050 to help Canada meet its climate goals. |
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Recent business environmentPrior to the COVID-19 pandemic, many companies in the industry invested below the levels needed to maintain or increase production capacity to meet anticipated demand. During the COVID-19 pandemic, this decline in investments accelerated as industry revenue col apsed, resulting in underinvestment and supply tightness as demand for petroleum and petrochemical products recovered. Across late 2021 and the first half of 2022, these reductions, along with supply chain constraints, and a continuation of demand recovery, led to a steady increase in oil and natural gas prices and refining margins. |
Demand for petroleum and petrochemical products grew in 2022, with the company's financial results benefiting from stronger prices and margins. Commodity and product prices are expected to remain volatile given the current global economic uncertainty and geopolitical events affecting supply and demand, including Russia's military action in Ukraine that has impacted global crude oil and gas supply levels and prices. |
The general rate of inflation in Canada and many other countries experienced a brief decline in the initial stage of the COVID-19 pandemic, before starting to increase steadily in 2021, due to an imbalance in supply and demand, and continued to increase in 2022. The underlying factors include, but are not limited to, time cycle of capacity investments, supply chain disruptions, shipping bottlenecks, labour constraints, and side effects from monetary and fiscal expansions. The company closely monitors market trends and works to mitigate both operating and capital cost impacts in al price environments. |
Business results |
Consolidated |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Net income (loss) (U.S. GAAP) | | 7,340 | 2,479 | (1,857) |
Identified items1 included in Net income (loss) |
| | | | | | |
Gain/(loss) on sale of assets | | 208 | — | — |
Impairments | | — | — | (1,171) |
Subtotal of identified items1 | | 208 | — | (1,171) |
| |
Net income (loss) excluding identified items1 | | 7,132 | 2,479 | (686) |
2022Net income in 2022 was $7,340 mil ion, or $11.44 per share on a diluted basis, up from $2,479 mil ion, or $3.48 per share in 2021. Current year results include favourable identified items1 of $208 mil ion after tax, related to the company’s gain on the sale of interests in XTO Energy Canada. |
2021 Net income in 2021 was $2,479 mil ion, or $3.48 per share on a diluted basis, compared to a net loss of $1,857 mil ion, or $2.53 per share in 2020. Prior year results include unfavourable identified items1 of $1,171 mil ion after tax, related to the company’s decision to no longer develop a significant portion of its unconventional portfolio. |
1 | non-GAAP financial measure - see "Frequently used terms" section on page 43 for definition and reconciliation. |
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|
Upstream OverviewImperial 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 improving asset reliability, accelerating development and application of high impact technologies, maximizing value by capturing new business opportunities and managing the existing portfolio, as wel 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’s current investment strategy is to invest for value and select volume growth, with focus on optimization within existing assets, cost reduction opportunities and productivity enhancements that aim to deliver robust returns at a wide range of prices. The company also continues to evaluate opportunities to support long-term growth. Although actual volumes wil vary from year to year, the focus is on value-add, long-term growth opportunities within the context of the factors described in Item 1A. “Risk factors”. Imperial continual y evaluates opportunities, including crude shipments by rail and the pace of the development of its Aspen in-situ oil sands project, as economical y justified. |
Prices for most of the company's crude oil sold are referenced to Western Canada Select (WCS) and West Texas Intermediate (WTI) oil markets. Additional y, the market price for WCS is typical y lower than light and medium grades of oil, and price differentials between WCS and WTI can fluctuate. |
Imperial believes prices over the long term wil be driven by market supply and demand, with the demand side largely being a function of general economic activity, alternative energy sources, levels of prosperity, technology advancements, consumer preference and government policies. On the supply side, prices may be significantly impacted by political events, logistics constraints, the actions of OPEC, governments, alternative energy sources, and other factors. To manage the risks associated with price, Imperial tests the resiliency of its annual plans and al major investments across a range of price scenarios. |
Key events Upstream assets demonstrated strong performance in 2022. The company continued to benefit from its actions implemented in prior years to manage the cost structure and improve the reliability of its assets, enabling the Upstream to capture significant value and take advantage of the improving business environment throughout 2022. |
Upstream ful -year production averaged 416,000 gross oil-equivalent barrels per day. |
At Kearl, gross production was about 242,000 barrels per day (172,000 barrels Imperial’s share), down 21,000 |
barrels per day (14,000 barrels Imperial's share) compared to 2021, as a result of extreme cold weather impacts |
in Q1 2022. |
At Cold Lake, annual production averaged 144,000 gross oil-equivalent barrels per day. |
At Syncrude, annual production averaged 77,000 gross oil-equivalent barrels per day, supported by the interconnect pipeline. |
On August 31, 2022, jointly with ExxonMobil Canada, Imperial sold its interests in XTO Energy Canada to Whitecap Resources Inc. |
As described in more detail in Item 1A. “Risk factors”, environmental risks and climate related regulations could have negative impacts on the upstream business. |
| 13 |
|
Results of operations 2022 Net income (loss) factor analysis mil ions of Canadian dol ars |
| | 3,140 |
| | | | | 208 | | 3,645 |
| | | (80) |
| 1,395 | | | (970) | | (48) |
| 2021 | Price | Volumes | Royalty | Identified | Other | 2022 |
| | | | | Items¹ |
Price – Higher realizations were general y in line with increases in marker prices, driven primarily by increased demand. Average bitumen realizations increased by $26.76 per barrel general y in line with WCS, and synthetic crude oil realizations increased by $43.85 per barrel. |
Volumes – Lower volumes were primarily the result of downtime at Kearl in the first half of the year, partly offset by higher production at Syncrude and Cold Lake. |
Royalty – Higher royalties primarily driven by improved commodity prices. |
Identified items1 – Current year results include favourable identified items1 related to the company's gain on the sale of interests in XTO Energy Canada. |
Other – Higher operating expenses of about $500 mil ion, primarily from higher energy prices, partial y offset by favourable foreign exchange impacts of about $270 mil ion, and higher electricity sales at Cold Lake of about $60 mil ion due to increased prices. |
2021 Net income (loss) factor analysis mil ions of Canadian dol ars |
| | |
| | | | | 1,171 |
| | | 550 |
| | 3,640 | | | | | 1,395 |
| | | | | | (968) |
| | | | (680) |
(2,318) |
| 2020 | Price | Volumes | Royalty | Identified | Other | 2021 |
| | | | | Items¹ |
Price – Higher realizations were primarily driven by average bitumen realizations increasing by $32.22 per barrel general y in line with WCS, and synthetic crude oil realizations increasing by $31.85 per barrel general y in line with WTI. |
Volumes – Higher volumes primarily driven by the absence of production balancing with market demands that occurred in 2020 increased net income by about $550 mil ion. |
Royalty – Higher royalties primarily driven by higher commodity prices. |
Identified items1 – Prior year results included unfavourable identified items1 of $1,171 mil ion related to the company's decision to no longer develop a significant portion of its unconventional portfolio. |
Other – Higher operating expenses of about $720 mil ion, unfavourable foreign exchange impacts of about $230 mil ion and lower Canada Emergency Wage Subsidy received by the company compared to prior year of about $60 mil ion, which includes Imperial's proportionate share of a joint venture. |
1 | non-GAAP financial measure - see "Frequently used terms" section on page 43 for definition and reconciliation. |
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|
Marker prices and average realizations |
Canadian dol ars, unless otherwise noted | | 2022 | 2021 | 2020 |
West Texas Intermediate (US$) (per barrel) | | 94.36 | 68.05 | 39.26 |
Western Canada Select (US$) (per barrel) | | 76.28 | 54.96 | 26.87 |
WTI/WCS Spread (US$) (per barrel) | | 18.08 | 13.09 | 12.39 |
Bitumen (per barrel) | | 84.67 | 57.91 | 25.69 |
Synthetic crude oil (per barrel) | | 125.46 | 81.61 | 49.76 |
Conventional crude oil (per barrel) | | 97.45 | 59.84 | 29.34 |
Natural gas liquids (per barrel) | | 64.92 | 35.87 | 13.85 |
Natural gas (per thousand cubic feet) | | 5.69 | 3.83 | 1.90 |
Average foreign exchange rate (US$) | | 0.77 | 0.80 | 0.75 |
Crude oil and natural gas liquids (NGL) - production and sales (a) |
thousands of barrels per day | | | | | 2022 | 2021 | | | | 2020 |
| | | | | gross | net | gross | net | | | gross | net |
Bitumen | | | | | | 316 | 263 | 326 | 292 | | | 290 | 279 |
Synthetic crude oil (b) | | | | | | 77 | 63 | 71 | 62 | | | 69 | 68 |
Conventional crude oil | | | | | | 8 | 8 | 10 | 9 | | | 11 | 10 |
Total crude oil production | | | | | | 401 | 334 | 407 | 363 | | | 370 | 357 |
NGLs available for sale | | | | | | 1 | 1 | | | | | | 1 | 1 | | | 2 | 2 |
Total crude oil and NGL production | | | | | | 402 | 335 | 408 | 364 | | | 372 | 359 |
Bitumen sales, including diluent (c) | | | | | | 424 | | 451 | | | | 401 |
NGL sales (d) | | | | | | 1 | | — | | | | 2 |
Natural gas - production and production available for sale (a) | | | | | |
| | | | | |
mil ions of cubic feet per day | | | | | 2022 | 2021 | | | | 2020 |
| | | | | gross | net | gross | net | | | gross | net |
Production (e) (f) | | | | | | 85 | 83 | 120 | 115 | | | 154 | 150 |
Production available for sale (g) | | | | | | | 50 | | | | | | | 81 | | | 115 |
(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. |
(b) The company’s synthetic crude oil production volumes were from the company’s share of production volumes in the Syncrude joint |
| | | | | | | | venture and include immaterial amounts of bitumen and other products exported to the operator's facilities using an existing |
| | | | | | | | interconnect pipeline. |
(c) Diluent is natural gas condensate or other light hydrocarbons added to crude bitumen to facilitate transportation to market by pipeline |
| | | | | | | | and rail. |
(d) 2021 NGL sales round to 0. |
(e) Gross production of natural gas includes amounts used for internal consumption with the exception of the amounts re-injected. |
(f) | | | | | | | | 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. |
(g) Includes sales of the company’s share of net production and excludes amounts used for internal consumption. |
2022Lower production at Kearl was primarily a result of downtime in the first half of the year. |
2021 Higher production at Kearl was primarily driven by the absence of prior year production balancing with marketdemands. |
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|
Downstream OverviewImperial’s Downstream serves predominantly Canadian markets with refining, trading, logistics and marketing activities. 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 wel 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 distil ation capacity of 433,000 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 considerations. While industry refining margins significantly impact earnings, strong operations performance, product mix optimization, and disciplined cost control are also critical to the company's strong financial performance. Imperial's integration across the value chain, from refining to marketing, enhances overal value across the fuels business. |
Key eventsRefining margins increased sharply in 2022 in the face of strengthening demand, low inventory levels, and supply uncertainty. While refining margins are anticipated to remain volatile in the near term, the company continues to closely monitor industry and global economic conditions. |
The company progressed the Strathcona renewable diesel project in 2022, culminating in a final investment decision in January 2023 to construct the largest such facility in Canada, designed to produce more than one bil ion litres of renewable diesel annual y. |
As described in more detail in Item 1A. “Risk factors”, proposed carbon policy and other climate related regulations, as wel as continued biofuels mandates, could have negative impacts on the downstream business. |
Imperial supplies petroleum products through Esso and Mobil-branded sites and independent marketers. At the end of 2022, there were about 2,400 sites operating under a branded wholesaler model, in alignment with Esso and Mobil brand standards, whereby Imperial supplies fuel to independent third parties. |
Results of operations 2022 Net income (loss) factor analysismil ions of Canadian dol ars |
| | | 377 | 3,622 |
| | 2,350 |
| 895 |
| 2021 | Margins | Other | 2022 |
Margins – Higher margins primarily reflect improved market conditions. |
Other – Lower turnaround impacts of about $140 mil ion, reflecting the absence of turnaround activities at Strathcona refinery, improved volumes of about $130 mil ion, favourable foreign exchange impacts of about $120 mil ion, and absence of the prior year unfavourable out-of-period inventory adjustment of $74 mil ion, partial y offset by higher operating expenses of about $190 mil ion. |
| | | | | 16 |
|
2021 Net income (loss) factor analysismil ions of Canadian dol ars |
| | 600 |
| | | | 895 |
| 553 |
| | | (258) |
| 2020 | Margins | Other | 2021 |
Margins – Higher margins reflect improved product demand. |
Other – Unfavourable foreign exchange impacts of about $150 mil ion and an unfavourable inventory adjustment of $74 mil ion1, partial y offset by lower operating expenses of about $50 mil ion. |
Refinery utilization |
thousands of barrels per day (a) | | | | | 2022 | 2021 | 2020 |
Total refinery throughput (b) | | | | | 418 | 379 | | | 340 |
Rated capacity at December 31 (c) | | | | | 433 | 428 | | | 428 |
Utilization of total refinery capacity (percent) | | | | | 98 | 89 | | | 80 |
(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. (b) Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distil ation units. (c) Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery |
| | | | | | | | atmospheric distil ation units, the products to be obtained and the refinery process, adjusted to include an estimated al owance 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. |
2022 |
|
Improved refinery throughput in 2022 was primarily driven by increased demand and reduced turnaround activity. |
2021 Improved refinery throughput in 2021 primarily reflects reduced impacts associated with the COVID-19 pandemic, partial y offset by a planned turnaround at Strathcona. |
Petroleum product sales |
thousands of barrels per day (a) | | | | | 2022 | 2021 | 2020 |
Gasolines | | | | | 229 | 224 | | | 215 |
Heating, diesel and jet fuels | | | | | 176 | 160 | | | 146 |
Lube oils and other products | | | | | 47 | 45 | | | 40 |
Heavy fuel oils | | | | | 23 | 27 | | | 20 |
Net petroleum product sales | | | | | 475 | 456 | | | 421 |
(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. |
2022 Improved petroleum product sales in 2022 primarily reflects increased demand. |
2021Improved petroleum product sales in 2021 primarily reflects reduced impacts associated with the COVID-19 pandemic. |
1 In 2021, the company recorded an unfavourable $74 mil ion ($82 mil ion, before tax) inventory adjustment (including the proportionate |
share of LIFO changes) related to reconciliations of additives and products inventory at equity and third-party terminals. The out-of-period |
impact of $57 mil ion ($63 mil ion, before tax) occurred over a number of years, and has been resolved. |
| | | | | | | | | 17 |
|
Chemical OverviewNorth America continued to benefit from abundant supplies of natural gas and gas liquids, providing both low cost energy and feedstock for steam crackers. |
Key eventsIn 2022, margins were adversely impacted by increased domestic supply of polyethylene. |
Imperial maintains a competitive advantage through continued operational excel ence, 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 2022 Net income (loss) factor analysismil ions of Canadian dol ars |
| 361 |
| | | | 204 |
| | (110) |
| | | (47) |
| 2021 | Margins | Other | 2022 |
Margins – Lower margins primarily reflect weaker industry polyethylene margins. |
2021 Net income (loss) factor analysismil ions of Canadian dol ars |
| | | 33 | 361 |
| | 250 |
| 78 |
| 2020 | Margins | Other | 2021 |
Margins – Improved margins were primarily due to stronger industry polyethylene margins. |
Sales |
thousands of tonnes | | | | | 2022 | 2021 | 2020 |
Polymers and basic chemicals | | | | | 635 | 599 | | | 574 |
Intermediates | | | | | 207 | 232 | | | 175 |
Total petrochemical sales | | | | | 842 | 831 | | | 749 |
Corporate and other |
mil ions of Canadian dol ars | | | | | 2022 | 2021 | 2020 |
Net income (loss) | | | | | (131) | (172) | (170) |
|
| | | | | | | | 18 |
|
Liquidity and capital resources |
Sources and uses of cashThe company issues long-term debt from time to time and maintains a commercial paper program. However, internal y generated funds cover the majority of its financial requirements. Cash that may be temporarily surplus to the company’s immediate needs is careful y 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 wel as petroleum and chemical product margins. In addition, to provide for cash flow in future periods, the company needs to continual y 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 overal 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, 2019. A valuation of the company’s registered retirement plans as at December 31, 2022 is expected to be completed in 2023. The company contributed $174 mil ion to the registered retirement plans in 2022. Future funding requirements are not expected to affect the company’s existing capital investment plans or its ability to pursue new investment opportunities. |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Cash provided by (used in) |
| | | | | | |
| | | | | | | Operating activities | | 10,482 | 5,476 | 798 |
| | | | | | | Investing activities | | (618) | (1,012) | (802) |
| | | | | | | Financing activities | | (8,268) | (3,082) | (943) |
Increase (decrease) in cash and cash equivalents | | 1,596 | 1,382 | (947) |
Cash and cash equivalents at end of year | | 3,749 | 2,153 | 771 |
Cash flow from operating activities |
2022 Cash flow generated from operating activities primarily reflects higher Upstream realizations, improved Downstream margins, and favourable working capital impacts. |
2021Cash flow generated from operating activities primarily reflects higher Upstream realizations and stronger Downstream margins. |
Cash flow used in investing activities |
2022 Cash flow used in investing activities primarily reflects higher additions to property, plant and equipment, which were partial y offset by proceeds from the sale of interests in XTO Energy Canada. |
2021Cash flow used in investing activities primarily reflects higher additions to property, plant and equipment. |
| | | | | | | | 19 |
|
Cash flow used in financing activities |
2022 At the end of 2022, total debt outstanding was $4,155 mil ion, compared with $5,176 mil ion at the end of 2021. |
During the third quarter of 2022, the company decreased its long-term debt by $1 bil ion by partial y repaying an existing facility with an affiliated company of ExxonMobil. |
During the second quarter of 2022, the company reduced its existing $500 mil ion committed long-term line of credit to $250 mil ion and extended the maturity date to June 30, 2023. Subsequently in the fourth quarter of 2022, this committed long-term line of credit was cancel ed in ful . The company also extended one of its $250 mil ion committed long-term lines of credit to June 30, 2024. |
In November 2022, the company extended the maturity date of an existing $250 mil ion committed short-term line of credit to November 2023. |
The company has not drawn on any of its outstanding $500 mil ion of available credit facilities. |
2021At the end of 2021, total debt outstanding was $5,176 mil ion, compared with $5,184 mil ion at the end of 2020. |
During the second quarter of 2021, the company extended the maturity date of two of its short-term lines of credit, total ing $750 mil ion, to May 2023, these facilities are now long-term. The company also extended its $300 mil ion committed short-term line of credit to June 2022. |
In November 2021, the company extended the maturity date of an existing $250 mil ion committed short-term line of credit to November 2022. |
The company has not drawn on these facilities. |
Share repurchases |
mil ions of Canadian dol ars, unless noted | | 2022 | 2021 | 2020 |
Share repurchases | | 6,395 | 2,245 | 274 |
Number of shares purchased (mil ions) (a) | | 93.9 | 56.0 | 9.8 |
(a) Share repurchases were made under the company’s normal course issuer bid program, and substantial issuer bids that commenced |
| | | | | on May 6, 2022 and November 4, 2022, and expired on June 10, 2022 and December 9, 2022, respectively. Includes shares |
| | | | | purchased from Exxon Mobil Corporation concurrent with, but outside of, the normal course issuer bid, and by way of a proportionate |
| | | | | tender under the company’s substantial issuer bids. |
2022On June 27, 2022, the company announced that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid. The program enabled the company to purchase up to a maximum of 31,833,809 common shares during the period June 29, 2022 to June 28, 2023. The program completed on October 21, 2022 as a result of the company purchasing the maximum al owable number of shares under the program. |
On May 6, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancel ation up to $2.5 bil ion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on June 15, 2022, with the company taking up and paying for 32,467,532 common shares at a price of $77.00 per share, for an aggregate purchase of $2.5 bil ion and |
| | | | |
4.9 percent of Imperial’s issued and outstanding shares at the close of business on May 2, 2022. This included 22,597,379 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent. |
| | | | | | 20 |
|
On November 4, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancel ation up to $1.5 bil ion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on December 14, 2022, with the company taking up and paying for 20,689,655 common shares at a price of $72.50 per share, for an aggregate purchase of $1.5 bil ion and 3.4 percent of Imperial's issued and outstanding shares at the close of business on October 31, 2022. This included 14,399,985 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent. |
2021On April 30, 2021, the company announced an amendment to its normal course issuer bid to increase the number of common shares that were available to be purchased. Under the amendment, the number of common shares available for purchase increased to a maximum of 29,363,070 common shares during the period June 29, 2020 to June 28, 2021. In 2021, the company purchased 29,356,095 shares under this amended program. |
On June 23, 2021, the company announced that it received final approval from the Toronto Stock Exchange for a new normal course issuer bid to continue its existing share purchase program. The program enabled the company to purchase up to a maximum of 35,583,671 common shares during the period June 29, 2021 to June 28, 2022. In accordance with the company’s announcement in November 2021 that it intended to accelerate purchases under the normal course issuer bid, the program was subsequently completed on January 31, 2022 as a result of the company purchasing the maximum al owable number of shares under the program. |
Dividends |
mil ions of Canadian dol ars, unless noted | | 2022 | 2021 | 2020 |
Dividends paid | | 851 | 706 | 649 |
Per share dividend paid (dol ars) | | 1.29 | 0.98 | 0.88 |
Financial strength |
The table below shows Imperial’s consolidated debt-to-capital ratio. The data demonstrates the company’s creditworthiness: |
percent |
At December 31 | | 2022 | 2021 | 2020 |
Debt to capital (a) | | 16 | 19 | 19 |
(a) Debt, defined as the sum of “Notes and loans payable” and “Long-term debt” (page 76), divided by capital, defined as the sum of debt |
| | | | | | and “Total shareholders’ equity” (page 76). |
Debt-related interest incurred in 2022, before capitalization of interest, was $111 mil ion, up from $63 mil ion in 2021. The weighted-average interest rate on the company’s debt was 2.2 percent in 2022, up from 1.2 percent in 2021. |
The company’s financial strength represents a competitive advantage of strategic importance providing it the opportunity to readily access capital markets across a range of market conditions and enables the company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value. |
Contractual obligations The company has contractual obligations involving commitments to third parties that impact its liquidity and capital resource needs. These contractual obligations are primarily for leases, debt, asset retirement obligations, pension and other postretirement benefits, other long-term obligations, and firm capital commitments. Further information on this topic can be found in notes 4, 5, 13 and 14 to the consolidated financial statements. |
Other long-term purchase agreements are commitments that are non-cancelable, or cancelable only under certain conditions, as wel as long-term commitments, other than unconditional purchase obligations. They include primarily transportation services agreements, raw material supply and community benefits agreements. The total obligation at year-end 2022 was $8.8 bil ion, of which $783 mil ion is due in 2023, and $670 mil ion is due in 2024. |
| | | | | 21 |
|
Litigation and other contingencies As discussed in note 9 to the consolidated financial statements on page 97, 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. |
Additional y, as discussed in note 9, Imperial was contingently liable at December 31, 2022, 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 |
Capital and exploration expenditures represent the combined total of additions at cost to property, plant and equipment, additions to finance leases, additional investments and acquisitions; 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 al investments and elements of net income, particular focus is placed on managing the control able aspects of this group of expenditures. |
mil ions of Canadian dol ars | | 2022 | 2021 |
Upstream (a) | | 1,128 | 632 |
Downstream | | 295 | 476 |
Chemical | | 10 | 8 |
Corporate and other | | 57 | 24 |
Total | | 1,490 | 1,140 |
(a) Exploration expenses included. |
For the Upstream segment, capital and exploration expenditures were primarily related to sustaining activity in support of the company’s in-situ and oil sands assets. |
For the Downstream segment, capital expenditures were primarily for enhancing the company’s distribution network as wel as refinery projects to improve environmental performance, reliability, feedstock flexibility, and energy efficiency. |
Total capital and exploration expenditures are expected to be approximately $1.7 bil ion in 2023. |
Expected capital and exploration expenditures for 2023 includes firm capital commitments of $407 mil ion for the construction and purchase of fixed assets and other permanent investments. An additional $211 mil ion of firm capital commitments have been made for years 2024 and beyond. |
Actual spending could vary depending on the progress of individual projects. |
| | | | 22 |
|
Market risks |
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 wel 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 differentials between North American crude benchmarks and western Canadian prices widen, 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. |
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 commodity prices and petroleum and chemical product prices are commonly benchmarked in U.S. dol ars. The majority of Imperial’s sales and purchases are related to these industry U.S. dol ar benchmarks. As the company records and reports its financial results in Canadian dol ars, to the extent that the Canadian / U.S. dol ar exchange rate fluctuates, the company’s earnings wil 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. Imperial has access to significant sources of long-term and short-term liquidity. Internal y 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. dol ar 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 wil 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 fol owing, only provide broad indicators of changes in the earnings experienced in any particular period. |
Earnings sensitivities (a) |
mil ions of Canadian dol ars, after-taxOne dol ar (U.S.) per barrel increase (decrease) in crude oil prices |
| + (-) | 105 |
One dol ar (U.S.) per barrel increase (decrease) in refining 2-1-1 margins (b) | + (-) | 140 |
One cent decrease (increase) in the value of the Canadian dol ar versus the U.S. dol ar | + (-) | 170 |
(a) Each sensitivity calculation shows the annual impact on net income resulting from a change in one factor, after tax and royalties, and |
| | | holding al other factors constant. These sensitivities have been updated to reflect current market conditions. They may not apply proportionately to larger fluctuations. |
(b) The 2-1-1 crack spread is an indicator of the refining margin generated by converting two barrels of crude oil into one barrel of |
| | | gasoline and one barrel of diesel. |
The demand for crude oil, petroleum products and petrochemical products are general y linked closely with economic growth. The occurrence of recessions or other periods of low or negative economic growth wil typical y have a direct adverse impact on the company’s financial results. Although price levels of crude oil may rise and fal significantly over the short to medium-term due to global economic conditions, political events, decisions by OPEC, governments and other factors, industry economics over the long-term wil continue to be driven by market supply and demand. The company evaluates investments over a range of prices, including estimated greenhouse gas emission costs. |
| | | | 23 |
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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 sel 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 wel as sales between refineries and the chemical plant related to raw materials, feedstocks and finished products. Al intersegment sales are at market based prices. Refer to note 2 for additional information on intersegment revenue. |
The company has an active asset management program in which nonstrategic assets are considered for divestment. The asset management program includes a disciplined, regular review to ensure that assets are contributing to the company’s strategic objectives. |
Risk management The company’s size, strong capital structure and the complementary nature of its business segments reduces 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 to generate returns from trading. 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 6 on page 94. The company maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. |
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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; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products; and pursuit of lower-emission business opportunities, including carbon capture and storage, hydrogen and lower-emission fuels. 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 79. |
Oil and natural 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 reserve volumes, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments, detailed analysis of wel information such as flow rates and reservoir pressures, and development and production costs, and other factors. The estimation of proved reserves is control ed by the company through long-standing approval guidelines. Reserves changes are made within a wel -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 economical y producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-day-of-the-month oil and natural gas prices during the reporting year. |
| Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wel s, facilities, or mining activities with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wel s, existing wel s, facilities, or mining activities, where a relatively major capital expenditure is required. Proved undeveloped reserves are recognized when a development plan has been adopted indicating that the reserves are scheduled to be developed within five years, unless specific circumstances support a longer period of time. |
| The company is reasonably certain that proved reserves wil be produced. However, 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 policies, consumer preferences, royalty frameworks and significant changes in oil and natural gas price levels. |
• | 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. |
Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in the average of first-day-of-the-month oil and natural gas prices and / or costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment and facility capacity. |
| | 25 |
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In 2020, downward revisions of proved bitumen reserves were a result of low prices. The 2.2 bil ion barrels of bitumen at Kearl and 0.6 bil ion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the SEC definition of proved reserves. Downward revisions to proved synthetic crude 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. |
In 2021, upward revisions of proved bitumen reserves were a result of improved prices. The 1.7 bil ion barrels of bitumen at Kearl and 0.5 bil ion barrels of bitumen at Cold Lake qualified as proved reserves under the SEC definition of proved reserves. Upward revisions to proved synthetic crude oil reserves were a result of improved prices. Changes to the liquids and natural gas proved reserves were the result of updated development plans and divestments at the Montney and Duvernay unconventional assets. |
In 2022, downward revisions of proved bitumen reserves were driven by a decrease of 0.2 bil ion barrels at Kearl as a result of higher royalty obligations associated with pricing, and a decrease of 0.2 bil ion barrels at Cold Lake due to an updated development plan. An increase to the bitumen reserves of 0.1 bil ion barrels is associated with extensions at Cold Lake for the Grand Rapids Phase 1 SA-SAGD and Leming SAGD projects. Downward revisions to proved synthetic crude oil reserves were a result of mine development plan updates and higher royalty obligations at Syncrude associated with pricing. Changes to the liquids and natural gas proved reserves were primarily a result of the sale of the company’s interest in the Montney and Duvernay unconventional assets. |
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 and its outlook for future production volumes are not impacted by proved reserves as disclosed under the SEC definition. |
Unit-of-production depreciation Oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation 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 actual production. The volumes produced and asset cost are known, while proved reserves are based on estimates that are subject to some variability. |
In the event that the unit-of-production method does not result in an equitable al ocation 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 ful y depreciated by the end of its useful life. |
To the extent that proved reserves for a property are substantial y de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable al ocation of cost over the expected life, assets wil be depreciated using a unit-of-production method 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 2021, with the corresponding effect on depreciation expense being immaterial compared to prior periods. For 2022 and 2023, al properties have sufficient reserves at current SEC prices which wil enable equitable al ocation of cost over the economic lives of the Upstream assets. |
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 that the carrying amounts may not be recoverable. 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 ASC 360 and ASC 932 and relies, in part, on the company’s planning and budgeting cycle. |
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|
Because the lifespans of the vast majority of the company’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices, industry margins, and development and production costs. Significant reductions in the company’s view of oil or natural gas commodity prices or margin ranges, especial y the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, including indicators outlined in ASC 360 can be indicators of potential impairment as wel . |
In general, Imperial does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices wil occasional y drop significantly, industry prices over the long term wil 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 technology 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, alternative energy sources and levels of prosperity. During the lifespan of its major assets, the company expects that oil and gas prices and industry margins wil experience significant volatility. Consequently, these assets wil experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether 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 and margins. |
Outlook for Energy and cash flow assessment The annual planning and budgeting process, known as the company plan, is the mechanism by which resources (capital, operating expenses and people) are al ocated across the company. The foundation for the energy supply and demand assumptions supporting the company plan begins with the Outlook, which contains demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. |
Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of required future policy and technology advancement and deployment for the world or the company, to meet net zero by 2050. As future policies and technology advancements emerge, they wil be incorporated into the Outlook, and consequently, the company’s business plans wil be updated accordingly. |
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 assumptions developed in the company plan, which is reviewed and approved by the board of directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the company’s assumptions of future capital al ocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs, including greenhouse gas emissions prices, and foreign currency exchange 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. The greenhouse gas emission prices reflect existing or anticipated policy actions of applicable provincial and federal governments. While third-party scenarios, such as the International Energy Agency Net Zero Emissions by 2050, may be used to test the resiliency of company’s businesses or strategies, they are not used as a basis for developing future cash flows for impairment assessments. |
Fair value of impaired assets 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 excess of the carrying value over fair value. The assessment of fair value is based on the views of a likely market participant. The principal parameters used to establish fair value 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. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices which are consistent with the average of third-party industry experts and government agencies, refining and chemical margins, dril ing and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group. |
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Other impairment estimates Unproved properties are assessed periodical y to determine whether they have been impaired. Significant unproved properties are assessed for impairment individual y, and valuation al owances against the capitalized costs are 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 individual y significant are aggregated by groups and amortized based on development risk and average holding period. |
Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sel . If the net book value exceeds the fair value less cost to sel , the assets are considered impaired and adjusted to the lower value. Judgment is required to determine if assets are held for sale, and to determine the fair value less cost to sel . |
Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value, which requires significant judgment. |
Recent impairments In 2020, the company announced its decision to not further develop a significant portion of its unconventional portfolio in Alberta, resulting in a non-cash, after-tax impairment charge of $1,171 mil ion in the company’s 2020 Upstream results. |
Factors which could put further assets at risk of impairment in the future include reductions in the company’s price or margin outlooks, changes in the al ocation of capital or development plans, reduced long-term demand for the company’s products and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price increases or margins. However, due to the inherent difficulty in predicting future commodity prices or margins, 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 fol owing the notes to consolidated financial statements. |
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. Al pension assumptions are reviewed annual y 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 4.3 percent used in 2022 compares to actual returns of 5.6 percent and 6.5 percent achieved over the last 10- and 20-year periods respectively, ending December 31, 2022. 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 pension plan benefits obligation, a reduction of 1 percent in the discount rate would increase the benefits obligation by approximately $1 bil ion. Similarly, a reduction of 1 percent in the long-term rate of return on plan assets would increase the annual pension expense by approximately $95 mil ion 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 1 percent of total expenses in 2022. |
| 28 |
|
Report of Independent Registered Public Accounting Firm |
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, 2022 and 2021, 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, 2022, including the related notes (col ectively referred to as the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). |
In our opinion, the consolidated financial statements referred to above present fairly, in al material respects, the financial position of the Company as of December 31, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles general y accepted in the United States of America. Also in our opinion, the Company maintained, in al material respects, effective internal control over financial reporting as of December 31, 2022, based on criteria established in Internal Control – Integrated Framework (2013) issued by the COSO. |
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 al 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 wel as evaluating the overal 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. |
| 31 |
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 matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. |
The Impact of Proved Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net |
As described in Notes 1 and 2 to the consolidated financial statements, the Company’s upstream property, plant and equipment (PP&E), net balance was $26,949 million as of December 31, 2022, and the related depreciation and depletion expense for the year ended December 31, 2022 was $1,673 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 reserve 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 reserve volumes is an ongoing process based on technical evaluations, commercial and market assessments, 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, reserves changes 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”). |
The principal considerations 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 are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved oil and natural gas reserve volumes, |
| as the reserve volumes are based on engineering assumptions and methods, |
which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserve volumes. |
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|
Consolidated statement of income (U.S. GAAP) |
mil ions of Canadian dol arsFor the years ended December 31 |
| | 2022 | 2021 | 2020 |
Revenues and other income | | | | | | |
Revenues (a) | | 59,413 | 37,508 | 22,284 |
Investment and other income (note 8, 18) | | 257 | 82 | 104 |
Total revenues and other income | | 59,670 | 37,590 | 22,388 |
|
Expenses |
| | | | | | |
Exploration (note 15) | | 5 | 32 | 13 |
Purchases of crude oil and products (b) | | 37,742 | 23,174 | 13,293 |
Production and manufacturing (c) (note 11) | | 7,404 | 6,316 | 5,535 |
Sel ing and general (c) | | 882 | 784 | 741 |
Federal excise tax and fuel charge | | 2,179 | 1,928 | 1,736 |
Depreciation and depletion (includes impairments) (note 2, 11) | | 1,897 | 1,977 | 3,293 |
Non-service pension and postretirement benefit | | 17 | 42 | 121 |
Financing (d) (note 12) | | 60 | 54 | 64 |
Total expenses | | 50,186 | 34,307 | 24,796 |
|
Income (loss) before income taxes | | 9,484 | 3,283 | (2,408) |
|
Income taxes (note 3) | | 2,144 | 804 | (551) |
|
Net income (loss) | | 7,340 | 2,479 | (1,857) |
|
Per share information (Canadian dol ars) |
| | | | | | |
Net income (loss) per common share - basic (note 10) | | 11.47 | 3.48 | (2.53) |
Net income (loss) per common share - diluted (note 10) | | 11.44 | 3.48 | (2.53) |
(a) Amounts from related parties included in revenues, (note 16). | | 17,042 | 8,777 | 5,107 |
(b) Amounts to related parties included in purchases of crude oil and products, (note 16). |
| | 3,795 | 2,737 | 2,484 |
(c) Amounts to related parties included in production and manufacturing, and sel ing and general expenses, (note 16). |
| | 460 | 420 | 579 |
(d) Amounts to related parties included in financing, (note 16). | | 78 | 28 | 61 |
The information in the notes to consolidated financial statements is an integral part of these statements. |
| | | | | | | 34 |
|
Consolidated balance sheet (U.S. GAAP) |
mil ions of Canadian dol arsAt December 31 |
| | 2022 | 2021 |
Assets |
| | | | |
Current assets |
| | | | |
Cash and cash equivalents | | 3,749 | 2,153 |
Accounts receivable - net (a) | | 4,719 | 3,869 |
Inventories of crude oil and products (note 11) | | 1,514 | 1,102 |
Materials, supplies and prepaid expenses | | 754 | 689 |
Total current assets | | 10,736 | 7,813 |
Investments and long-term receivables (b) | | 893 | 757 |
Property, plant and equipment, | | | | |
| |
less accumulated depreciation and depletion (note 2, 18) | | 30,506 | 31,240 |
Goodwil | | 166 | 166 |
Other assets, including intangibles - net | | 1,223 | 806 |
Total assets | | 43,524 | 40,782 |
|
Liabilities | | | | |
| |
Current liabilities | | | | |
| |
Notes and loans payable (note 12) | | 122 | 122 |
Accounts payable and accrued liabilities (a) (note 11) | | 6,194 | 5,184 |
Income taxes payable | | 2,582 | 248 |
Total current liabilities | | 8,898 | 5,554 |
Long-term debt (c) (note 14) | | 4,033 | 5,054 |
Other long-term obligations (note 5) | | 3,467 | 3,897 |
Deferred income tax liabilities (note 3) | | 4,713 | 4,542 |
Total liabilities | | 21,111 | 19,047 |
|
Commitments and contingent liabilities (note 9) | | | | |
| |
|
Shareholders’ equity | | | | |
| |
Common shares at stated value (d) (note 10) | | 1,079 | 1,252 |
Earnings reinvested | | 21,846 | 21,660 |
Accumulated other comprehensive income (loss) (note 17) | | (512) | (1,177) |
Total shareholders’ equity | | 22,413 | 21,735 |
|
Total liabilities and shareholders’ equity | | 43,524 | 40,782 |
(a) Accounts receivable - net included net amounts receivable from related parties of $1,108 mil ion (2021 – $1,031 mil ion), (note 16). (b) Investments and long-term receivables included amounts from related parties of $288 mil ion (2021 – $298 mil ion), (note 16). (c) Long-term debt included amounts to related parties of $3,447 mil ion (2021 – $4,447 mil ion), (note 16). (d) Number of common shares authorized and outstanding were 1,100 mil ion and 584 mil ion, respectively (2021 – 1,100 mil ion and 678 |
| | | | | mil ion, respectively), (note 10). |
The information in the notes to consolidated financial statements is an integral part of these statements. |
Approved by the directors. |
/s/ Bradley W. Corson | | | | | | /s/ Daniel E. Lyons |
Bradley W. Corson | | | | | | Daniel E. Lyons |
Chairman, president and | | | | | | Senior vice-president |
chief executive officer | | | | | | finance and administration, and control er |
| | | | | | 36 |
|
Consolidated statement of cash flows (U.S. GAAP) |
mil ions of Canadian dol arsFor the years ended December 31 |
| | 2022 | 2021 | 2020 |
Operating activities |
| | | | | | |
Net income (loss) | | 7,340 | 2,479 | (1,857) |
Adjustments for non-cash items: |
| | | | | | |
Depreciation and depletion (includes impairments) (note 2) | | 1,897 | 1,977 | 3,273 |
Impairment of intangible assets (note 11) | | — | — | 20 |
(Gain) loss on asset sales (note 8, 18) | | (158) | (49) | (35) |
Deferred income taxes and other | | (77) | 91 | (521) |
Changes in operating assets and liabilities: |
| | | | | | |
Accounts receivable | | (862) | (1,950) | 780 |
Inventories, materials, supplies and prepaid expenses | | (477) | 45 | 78 |
Income taxes payable | | 1,876 | 248 | (106) |
Accounts payable and accrued liabilities | | 948 | 2,020 | (1,087) |
Al other items - net (b) | | (5) | 615 | 253 |
Cash flows from (used in) operating activities | | 10,482 | 5,476 | 798 |
|
Investing activities |
| | | | | | |
Additions to property, plant and equipment | | (1,526) | (1,108) | (868) |
Proceeds from asset sales (note 8, 18) | | 904 | 81 | 82 |
Additional investments | | (6) | — | — |
Loans to equity companies - net | | 10 | 15 | (16) |
Cash flows from (used in) investing activities | | (618) | (1,012) | (802) |
|
Financing activities |
| | | | | | |
Short-term debt - net (note 12) | | — | (111) | — |
Long-term debt - reduction (note 14) | | (1,000) | — | — |
Finance lease obligations - reduction (note 14) | | (22) | (20) | (20) |
Dividends paid | | (851) | (706) | (649) |
Common shares purchased (note 10) | | (6,395) | (2,245) | (274) |
Cash flows from (used in) financing activities | | (8,268) | (3,082) | (943) |
|
Increase (decrease) in cash | | 1,596 | 1,382 | (947) |
Cash and cash equivalents at beginning of year | | 2,153 | 771 | 1,718 |
Cash and cash equivalents at end of year | | | | | | | (a) | | 3,749 | 2,153 | 771 |
(a) Cash is composed of cash in bank and cash equivalents at cost. Cash equivalents are al highly liquid securities with maturity of three months or less.(b) Included contributions to registered pension plans. |
| | (174) | (164) | (195) |
|
Income taxes (paid) refunded. | | (374) | 58 | (42) |
Interest (paid), net of capitalization. | | (60) | (43) | (62) |
The information in the notes to consolidated financial statements is an integral part of these statements. |
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Notes to consolidated financial statements |
The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Imperial Oil Limited. |
The company’s principal business involves exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen and lower-emission fuels. |
The consolidated financial statements have been prepared in accordance with United States General y 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 have been reclassified in certain cases to conform to the 2022 presentation basis. Al amounts are in Canadian dol ars unless otherwise indicated. |
1. Summary of significant accounting policies |
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 unilateral y determine strategic, operating, investing and financing policies. Imperial Oil Resources Limited and Canada Imperial Oil Limited are significant subsidiaries included in the consolidated financial statements and are whol y 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 its 70.96 percent interest in the Kearl joint venture and its 25 percent interest in the Syncrude joint venture. |
Revenues Imperial general y sel s 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 typical y 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 typical y due within 30 days. |
Revenues include amounts bil ed 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 “Sel ing 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 fulfil ed through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are ful y 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 - net” include revenue and receivables both within the scope of ASC 606 Revenue from Contracts with Customers, and those outside the scope of ASC 606. Long-term receivables are primarily from receivables outside the scope of ASC 606. Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments and accruals of expected volume discounts, and are not significant. |
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Consumer taxes Taxes levied on the consumer and col ected 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 may use derivative instruments for trading purposes and to offset exposures associated with commodity prices, currency exchange rates and interest rates that arise from existing assets, liabilities, firm commitments and forecasted transactions. Al 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. Col ateral 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” in the Consolidated statement of income. |
Fair value Fair value is the price that would be received to sel 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 alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period. |
Inventory costs include expenditures and other charges (including depreciation), directly or indirectly incurred in bringing the inventory to its existing condition and location. Sel ing 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 investments 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. |
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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 a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory wel costs are carried as an asset when the wel has found a sufficient quantity of reserves to justify its completion as a producing wel and where the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory wel 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 wel s and development dry holes, are capitalized. |
Interest costs incurred to finance expenditures during the construction phase of projects are capitalized as part of the historical cost of acquiring the constructed 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. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life of the related assets. |
Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized. |
Depreciation, depletion and amortization Depreciation, depletion and amortization are primarily determined under either the unit-of-production method 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. |
Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory dril ing and development costs associated with productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable al ocation 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 ful y depreciated by the end of its useful life. Investments in mining heavy equipment and certain ore processing plant assets at oil sands mining properties are depreciated on a straight-line basis over a maximum of 15 years and 50 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 substantial y de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable al ocation of cost over the expected life, assets wil be depreciated using a unit-of-production method 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 2021, with the corresponding effect on depreciation expense being immaterial compared to prior periods. For 2022 and 2023, al properties have sufficient reserves at current SEC prices which wil enable equitable al ocation of cost over the economic lives of the Upstream assets. |
Investments in refinery and chemical process manufacturing equipment are general y depreciated on a straight-line basis over a 25-year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired. |
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Impairment assessment The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that 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 fol owing: |
• | 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 current and projected reserve volumes; |
• | a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator; |
• | an accumulation of project costs significantly in excess of the amount original y 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 wil be sold or otherwise disposed of significantly before the end of its previously estimated useful life. |
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 ASC 360 and ASC 932 and relies, in part, on the company’s planning and budgeting cycle. Asset valuation analysis, profitability reviews and other periodic control processes assist the company in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable. |
Because the lifespans of the vast majority of the company’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices, industry margins, and development and production costs. Significant reductions in the company’s view of oil or natural gas commodity prices or margin ranges, especial y the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, including indicators outlined in ASC 360 can be indicators of potential impairment as wel . |
In general, Imperial does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices wil occasional y drop significantly, industry prices over the long term wil 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 technology 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, alternative energy sources and levels of prosperity. During the lifespan of its major assets, the company expects that oil and gas prices and industry margins wil experience significant volatility. Consequently, these assets wil experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether 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 and margins. |
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 average of first-day-of-month prices in the year. These prices represent discrete points in time and could be higher or lower than the company’s 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. |
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Outlook for Energy and cash flow assessment The annual planning and budgeting process, known as the company plan, is the mechanism by which resources (capital, operating expenses and people) are al ocated across the company. The foundation for the energy supply and demand assumptions supporting the company plan begins with Exxon Mobil Corporation’s Outlook for Energy (the Outlook), which contains demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. |
Reflective of the existing global policy environment, the Outlook does not project the degree of required future policy and technology advancement and deployment for the world or the company, to meet net zero by 2050. As future policies and technology advancements emerge, they wil be incorporated into the Outlook, and consequently, the company’s business plans wil be updated accordingly. |
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 assumptions developed in the company plan, which is reviewed and approved by the board of directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the company’s assumptions of future capital al ocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs, including greenhouse gas emissions prices, and foreign currency exchange 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. The greenhouse gas emission prices reflect existing or anticipated policy actions of applicable provincial and federal governments. |
Fair value of impaired assets 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 excess of the carrying value over fair value. The assessment of fair value is based on the views of a likely market participant. The principal parameters used to establish fair value 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. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices which are consistent with the average of third-party industry experts and government agencies, refining and chemical margins, dril ing and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group. |
Other impairment estimates Unproved properties are assessed periodical y to determine whether they have been impaired. Significant unproved properties are assessed for impairment individual y, and valuation al owances against the capitalized costs are 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 individual y significant are aggregated by groups and amortized based on development risk and average holding period. |
Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sel . If the net book value exceeds the fair value less cost to sel , the assets are considered impaired and adjusted to the lower value. 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. |
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Asset retirement obligations and other environmental liabilities The company incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typical y at the time the assets are instal ed. In the estimation of fair value, the company uses 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, discount rates and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value. |
Asset retirement obligations for downstream and chemical 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 generally 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. On page 93, note 5 to the consolidated financial statements provides a three-year continuity table detailing the changes in asset retirement obligations. |
The company accrues environmental liabilities 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. |
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| Upstream | Downstream | Chemical |
mil ions of Canadian dol ars | | | | | 2022 | | | | 2021 | 2020 | 2022 | | | | | 2021 | 2020 | 2022 | 2021 | | | | | | 2020 |
Revenues and other income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Revenues (a) (b) | | | | | 494 | 5,863 | | | | | 6,263 57,466 30,207 15,178 | 1,453 | 1,438 | | | | | | 843 |
Intersegment sales (c) | | | | 19,135 | 9,956 | | | | | 2,527 | 7,476 | | | | | 4,520 | 1,480 | 523 | | | | | | | | | 319 | 165 |
Investment and other income (note 8, 18) | | | | | 135 | | | | 12 | 7 | 43 | | | | | 59 | 78 | — | | | | | | | | | 1 | — |
| | | | 19,764 15,831 | | 8,797 64,985 34,786 16,736 | 1,976 | 1,758 | | | | | | 1,008 |
Expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exploration (note 15) | | | | | 5 | | | | 32 | 13 | — | | | | | — | — | — | | | | | | | | | — | — |
Purchases of crude oil and products (c) (note 11) | | | | | 7,971 | 7,492 | | | | | 4,834 55,569 29,505 12,047 | 1,330 | | | | | | | | | 966 | 579 |
Production and manufacturing (note 11) | | | | | 5,491 | 4,661 | | | | | 3,852 | 1,640 | | | | | 1,445 | 1,468 | 273 | | | | | | | | | 210 | 215 |
Sel ing and general | | | | | — | | | | — | — | 653 | | | | | 572 | 619 | 85 | | | | | | | | | 90 | 92 |
Federal excise tax and fuel charge | | | | | — | | | | — | — | 2,177 | | | | | 1,928 | 1,736 | 2 | | | | | | | | | — | — |
Depreciation and depletion (d) (note 11) | | | | | 1,673 | 1,775 | | | | | 3,084 | 179 | | | | | 158 | 166 | 18 | | | | | | | | | 18 | 19 |
Non-service pension and postretirement benefit | | | | | — | | | | — | — | — | | | | | — | — | — | | | | | | | | | — | — |
Financing (note 12) | | | | | 5 | | | | 15 | 3 | 1 | | | | | — | — | — | | | | | | | | | — | — |
Total expenses | | | | 15,145 13,975 11,786 60,219 33,608 16,036 | 1,708 | 1,284 | | | | | | 905 |
Income (loss) before income taxes (note 11) | | | | | 4,619 | 1,856 (2,989) | 4,766 | | | | | 1,178 | 700 | 268 | | | | | | | | | 474 | 103 |
Income tax expense (benefit) (note 3) | | | | | 974 | | | | 461 | (671) | 1,144 | | | | | 283 | 147 | 64 | | | | | | | | | 113 | 25 |
Net income (loss) (c) (note 11) | | | | | 3,645 | 1,395 (2,318) | 3,622 | | | | | 895 | 553 | 204 | | | | | | | | | 361 | 78 |
Cash flows from (used in) operating activities (c) | | | | | 5,834 | 4,913 | | | | | 286 | 4,415 | | | | | 179 | 470 | 276 | | | | | | | | | 421 | 114 |
Capital and exploration expenditures (e) | | | | | 1,128 | | | | 632 | 561 | 295 | | | | | 476 | 251 | 10 | | | | | | | | | 8 | 21 |
Property, plant and equipment | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost | | | | 45,784 48,200 47,693 | 6,926 | | | | | 6,772 | 6,321 | 995 | | | | | | | | | 984 | 975 |
Accumulated depreciation and depletion | | | | (18,835) (20,389) (18,786) (4,143) (4,096) (3,962) | (741) | | | | | | | | | (721) | (699) |
Net property, plant and equipment (f) | | | | 26,949 27,811 28,907 | 2,783 | | | | | 2,676 | 2,359 | 254 | | | | | | | | | 263 | 276 |
Total assets (c) | | | | 28,830 29,416 31,835 | 9,277 | | | | | 7,945 | 4,554 | 491 | | | | | | | | | 474 | 408 |
|
| Corporate and other | Eliminations | Consolidated |
mil ions of Canadian dol ars | | | | | 2022 | | | | 2021 | 2020 | 2022 | | | | | 2021 | 2020 | 2022 | 2021 | | | | | | 2020 |
Revenues and other income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Revenues (a) (b) | | | | | — | | | | — | — | — | | | | | — | — 59,413 37,508 22,284 |
Intersegment sales (c) | | | | | — | | | | — | — (27,134) (14,795) (4,172) | — | | | | | | | | | — | — |
Investment and other income (note 8, 18) | | | | | 79 | | | | 10 | 19 | — | | | | | — | — | 257 | | | | | | | | | 82 | 104 |
| | | | | 79 | | | | 10 | 19 (27,134) (14,795) (4,172) 59,670 37,590 22,388 |
Expenses | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Exploration (note 15) | | | | | — | | | | — | — | — | | | | | — | — | 5 | | | | | | | | | 32 | 13 |
Purchases of crude oil and products (c) (note 11) | | | | | — | | | | — | — (27,128) (14,789) (4,167) 37,742 23,174 13,293 |
Production and manufacturing (note 11) | | | | | — | | | | — | — | — | | | | | — | — | 7,404 | 6,316 | | | | | | 5,535 |
Sel ing and general | | | | | 150 | | | | 128 | 35 | (6) | | | | | (6) | (5) | 882 | | | | | | | | | 784 | 741 |
Federal excise tax and fuel charge | | | | | — | | | | — | — | — | | | | | — | — | 2,179 | 1,928 | | | | | | 1,736 |
Depreciation and depletion (d) (note 11) | | | | | 27 | | | | 26 | 24 | — | | | | | — | — | 1,897 | 1,977 | | | | | | 3,293 |
Non-service pension and postretirement benefit | | | | | 17 | | | | 42 | 121 | — | | | | | — | — | 17 | | | | | | | | | 42 | 121 |
Financing (note 12) | | | | | 54 | | | | 39 | 61 | — | | | | | — | — | 60 | | | | | | | | | 54 | 64 |
Total expenses | | | | | 248 | | | | 235 | 241 (27,134) (14,795) (4,172) 50,186 34,307 24,796 |
Income (loss) before income taxes (note 11) | | | | | (169) | | | | (225) | (222) | — | | | | | — | — | 9,484 | 3,283 (2,408) |
Income tax expense (benefit) (note 3) | | | | | (38) | | | | (53) | (52) | — | | | | | — | — | 2,144 | | | | | | | | | 804 | (551) |
Net income (loss) (c) (note 11) | | | | | (131) | | | | (172) | (170) | — | | | | | — | — | 7,340 | 2,479 (1,857) |
Cash flows from (used in) operating activities (c) | | | | | (59) | | | | (47) | (64) | 16 | | | | | 10 | (8) 10,482 | 5,476 | | | | | | 798 |
Capital and exploration expenditures (e) | | | | | 57 | | | | 24 | 41 | — | | | | | — | — | 1,490 | 1,140 | | | | | | 874 |
Property, plant and equipment | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Cost | | | | | 863 | | | | 806 | 782 | — | | | | | — | — 54,568 56,762 55,771 |
Accumulated depreciation and depletion | | | | | (343) | | | | (316) | (290) | — | | | | | — | — (24,062) (25,522) (23,737) |
Net property, plant and equipment (f) | | | | | 520 | | | | 490 | 492 | — | | | | | — | — 30,506 31,240 32,034 |
Total assets (c) | | | | | 5,312 | 3,196 | | | | | 1,632 | (386) | | | | | (249) | (398) 43,524 40,782 38,031 |
| | | | | 46 |
|
(a) Includes export sales to the United States of $12,394 mil ion (2021 - $7,228 mil ion, 2020 - $4,614 mil ion).(b) Revenues include both revenue within the scope of ASC 606 and outside the scope of ASC 606. Trade receivables in "Accounts |
receivable – net" reported on the Consolidated balance sheet include both receivables within the scope of ASC 606 and outside the scope of ASC 606. Revenue and receivables outside the scope of ASC 606 primarily relate to physical y settled commodity contracts accounted for as derivatives. Contractual terms, credit quality and type of customer are general y similar between contracts within the scope of ASC 606 and those outside it. |
| Revenuesmil ions of Canadian dol ars |
| | | 2022 | 2021 | 2020 |
| Revenue from contracts with customers | 52,265 34,275 22,199 |
| Revenue outside the scope of ASC 606 | | 7,148 | 3,233 | 85 |
| Total | 59,413 37,508 22,284 |
(c) In 2021, the Downstream segment acquired a portion of Upstream crude inventory for $444 mil ion. There was no earnings impact and |
the effects of this transaction have been eliminated for consolidation purposes. |
(d) In 2020, the Upstream segment included a non-cash impairment charge of $1,531 mil ion, before-tax, related to the company’s |
decision not to further develop a significant portion of its unconventional portfolio. |
(e) Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant and equipment, additions to |
finance leases, additional investments and acquisitions and the company’s share of similar costs for equity companies. CAPEX excludes the purchase of carbon emission credits. |
(f) | Includes property, plant and equipment under construction of $2,676 mil ion (2021 - $2,348 mil ion, 2020 - $1,874 mil ion). |
3. Income taxes |
mil ions of Canadian dol ars | | | | | | 2022 | 2021 | 2020 |
Current income tax expense (benefit) (a) | | | | | | 2,228 | 711 | (27) |
Deferred income tax expense (benefit) (a) | | | | | | (84) | 93 | (524) |
Total income tax expense (benefit) (a) | | | | | | 2,144 | 804 | (551) |
Statutory corporate tax rate (percent) | | | | | | 24.1 | 24.0 | 25.0 |
Increase (decrease) resulting from: |
| | | | | | | |
Enacted tax rate change (a) | | | | | | — | — | 0.1 |
Other (b) | | | | | | (1.5) | 0.5 | (2.2) |
Effective income tax rate (percent) | | | | | | 22.6 | 24.5 | 22.9 |
(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 December 9, 2020, the Alberta government enacted an accelerated decrease in the province’s general corporate income |
| tax rate from 10 percent to 8 percent, effective July 1, 2020. The cumulative effect of the 2020 legislative tax changes on the |
| company’s financial statements was immaterial. |
(b) Other primarily relates to disposals, prior year adjustments and re-assessments. In 2022, the company's sale of its interests in XTO |
| Energy Canada decreased the effective income tax rate by 1.3 percent. |
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 assets as at December 31 were: |
mil ions of Canadian dol ars | | | | | | 2022 | 2021 | 2020 |
Depreciation and amortization | | | | | | 5,388 | 5,284 | 5,319 |
Successful dril ing and land acquisitions | | | | | | 236 | 331 | 363 |
Pension and benefits | | | | | | (105) | (303) | (534) |
Asset retirement obligation | | | | | | (529) | (418) | (403) |
Capitalized interest | | | | | | 127 | 120 | 120 |
LIFO inventory valuation | | | | | | (454) | (413) | (150) |
Tax loss carryforwards | | | | | | (84) | (42) | (460) |
Valuation al owance | | | | | | 73 | — | — |
Other | | | | | | (53) | (101) | (154) |
Net deferred income tax liabilities | | | | | | 4,599 | 4,458 | 4,101 |
| | | | | | | | 47 |
|
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 fol owing table summarizes the movement in unrecognized tax benefits: |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Balance as of January 1 | | 47 | 36 | 35 |
Additions based on current year’s tax position | | 12 | 16 | 2 |
Additions for prior years’ tax positions | | 10 | — | — |
Settlements with tax authorities | | (9) | (5) | (1) |
Balance as of December 31 | | 60 | 47 | 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 general y would not increase the effective tax rate. The 2022, 2021 and 2020 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 2018 to 2022 are subject to examination by the tax authorities. Tax filings from 2007 to 2017 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 formal y disputing those matters to which the company disagrees. Many of these outstanding matters wil not be resolved until after 2023. 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. |
Unrecognized tax benefits are not classified as future commitments because the company does not expect there wil be any cash impact from the final settlements as sufficient funds have been deposited with the Canada Revenue Agency. |
4. Employee retirement benefitsRetirement benefits, which cover almost al 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 wel 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. |
| | | | | 48 |
|
The benefit obligations and plan assets associated with the company’s defined benefit plans are measured on December 31. |
| | Other postretirement |
| Pension benefits | | benefits |
|
| | | | 2022 | 2021 | | 2022 | | | 2021 |
Assumptions used to determine benefit obligations at December 31 (percent) |
| | | | | | | | | | | | | | |
Discount rate | | | | 5.10 | 3.00 | 5.10 | | | 3.00 |
Long-term rate of compensation increase | | | | 4.00 | 4.00 | 4.00 | | | 4.00 |
|
mil ions of Canadian dol arsChange in benefit obligation |
| | | | | | | | | | | | | | |
Benefit obligation at January 1 | | 9,850 | | | | 10,716 | | 818 | | | 873 |
Service cost | | | | 280 | 324 | | 23 | | | 28 |
Interest cost | | | | 295 | 271 | | 24 | | | 22 |
Actuarial loss (gain) (a) | | (2,528) | | | | (925) | | (248) | | | (83) |
Benefits paid (b) | | | | (523) | (536) | | (28) | | | (22) |
Benefit obligation at December 31 | | 7,374 | | | | 9,850 | | 589 | | | 818 |
|
| | | | | | | | |
Accumulated benefit obligation at December 31 | | 6,820 | | | | 8,885 |
(a) Actuarial loss (gain) primarily driven by changes in the year-end discount rate and salary experience.(b) Benefit payments for funded and unfunded plans. |
The discount rate for the purpose of calculating year-end postretirement benefits plan obligation is determined by using the Canadian Institute of Actuaries recommended spot yield 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 with 6.01 percent in 2023 and gradual y decline to 3.57 percent by 2040 and beyond. |
| | Other postretirement |
| Pension benefits | | benefits |
mil ions of Canadian dol ars | | | | 2022 | 2021 | | 2022 | | | 2021 |
Change in plan assets | | | | | | | | | | | | | | |
Fair value at January 1 | | 9,440 | | | | 9,426 |
| | | | | | | | |
Actual return (loss) gain | | (1,594) | | | | 319 |
| | | | | | | | |
Company contributions | | | | 174 | 164 |
| | | | | | | | |
Benefits paid (a) | | | | (479) | (469) |
| | | | | | | | |
Fair value at December 31 | | 7,541 | | | | 9,440 |
| | | | | | | | |
|
Plan assets in excess of (less than) projected benefit obligation at December 31 |
| | | | | | | | | | | | | | |
Funded plans | | | | 543 | 89 |
| | | | | | | | |
Unfunded plans | | | | (376) | (499) | | (589) | | | (818) |
Total (b) | | | | 167 | (410) | | (589) | | | (818) |
(a) Benefit payments for funded plans only. |
(b) 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 overfunded or underfunded status of the company’s defined benefit postretirement plans was recorded as an asset or 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. |
| 49 |
|
| | Other postretirement |
| Pension benefits | | benefits |
mil ions of Canadian dol ars | | | | 2022 | 2021 | | 2022 | | | 2021 |
Amounts recorded in the Consolidated balance sheetconsist of: |
| | | | | | | | | | | | | | |
Other assets, including intangibles - net | | | | 543 | 190 | | — | | | — |
Current liabilities | | | | (35) | (26) | | (28) | | | (30) |
Other long-term obligations | | | | (341) | (574) | | (561) | | | (788) |
Total recorded | | | | 167 | (410) | | (589) | | | (818) |
|
Amounts recorded in accumulated other |
comprehensive income consist of: |
| | | | | | | | | | | | | | |
Net actuarial loss (gain) | | | | 666 | 1,272 | | (84) | | | 173 |
Prior service cost | | | | 235 | 252 | | — | | | — |
Total recorded in accumulated other |
comprehensive income, before-tax | | | | 901 | 1,524 | | (84) | | | 173 |
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 al ocation percentages and the long-term return assumption for each asset class. The 2022 long-term expected return of 4.3 percent used in the calculations of pension expense compares to an actual rate of return of 5.6 percent and 6.5 percent over the last 10- and 20-year periods respectively, ending December 31, 2022. |
| | Other postretirement |
| Pension benefits | | benefits |
| | 2022 | | | | | | 2021 | 2020 | | 2022 | 2021 | | | 2020 |
Assumptions used to determine net periodicbenefit cost for years ended December 31 (percent) |
| | | | | | | | | | |
Discount rate | 3.00 | | | | | | 2.50 | 3.10 | 3.00 | 2.50 | | | 3.10 |
Long-term rate of return on funded assets | 4.30 | | | | | | 4.50 | 4.50 | — | | | | | | — | — |
Long-term rate of compensation increase | 4.00 | | | | | | 4.00 | 4.50 | 4.00 | 4.00 | | | 4.50 |
|
mil ions of Canadian dol ars |
| | | | | | | | | | |
Components of net periodic benefit cost |
| | | | | | | | | | |
Service cost | | 280 | | | | | | 324 | 305 | | 23 | | | | | | 28 | 24 |
Interest cost | | 295 | | | | | | 271 | 308 | | 24 | | | | | | 22 | 24 |
Expected return on plan assets | | (412) | | | | | | (427) | (391) | | — | | | | | | — | — |
Amortization of prior service cost | | 17 | | | | 17 | | | | 14 | | — | | | | | | — | — |
Amortization of actuarial loss (gain) | | 84 | | | | | | 143 | 153 | | 9 | | | | | | 16 | 13 |
Net periodic benefit cost | | 264 | | | | | | 328 | 389 | | 56 | | | | | | 66 | 61 |
|
Changes in amounts recorded in accumulated |
other comprehensive income |
| | | | | | | | | | |
Net actuarial loss (gain) | | (522) | | | | | | (817) | 129 | | (248) | | | | | | (83) | 152 |
Amortization of net actuarial (loss) gain included in |
net periodic benefit cost | | (84) | | | | | | (143) | (153) | | (9) | | | | | | (16) | (13) |
Amortization of prior service cost included in net |
periodic benefit cost | | (17) | | | | | | (17) | (14) | | — | | | | | | — | — |
Total recorded in other comprehensive income | | (623) | | | | | | (977) | (38) | | (257) | | | | | | (99) | 139 |
Total recorded in net periodic benefit cost and |
other comprehensive income, before-tax | | (359) | | | | | | (649) | 351 | | (201) | | | | | | (33) | 200 |
Costs for defined contribution plans, primarily the employee savings plan, were $43 mil ion in 2022 (2021 - $47 mil ion, 2020 - $47 mil ion). |
| 50 |
|
A summary of the change in accumulated other comprehensive income is shown in the table below: |
| Total pension and other postretirement benefits |
|
mil ions of Canadian dol ars | | | 2022 | 2021 | 2020 |
(Charge) credit to other comprehensive income, before-tax | | | 880 | 1,076 | (101) |
Deferred income tax (charge) credit (note 17) | | | (215) | (264) | 23 |
(Charge) credit to other comprehensive income, after-tax | | | 665 | 812 | (78) |
The company’s investment strategy for pension plan assets reflects a long-term view, a careful assessment of the risks inherent in plan assets and liabilities and broad diversification to reduce the risk of the portfolio. The pension plan assets are primarily invested in passive global equity and domestic fixed income index funds to diversify risk while minimizing costs. The fixed income funds are largely invested in investment grade corporate and government debt securities with interest rate sensitivity designed to approximate the interest rate sensitivity of plan liabilities. The target asset al ocation for the pension plan is reviewed periodical y and set based on considerations such as risk, diversification and liquidity. The target asset al ocation for equity securities is 30 percent with the remainder in fixed-income securities. |
The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment. |
The 2022 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, 2022, using: |
| | | | | Net Asset |
mil ions of Canadian dol ars | | | | | | | Total | Level 1 | Level 2 | Level 3 | Value |
Asset class |
| | | | | | | | | | |
Equity securities |
| | | | | | | | | | |
Canadian | | | | | | | | | 96 | | | | 96 |
| | | | | | | | | |
Non-Canadian | | | | | | | | | 2,215 | | | | 2,215 |
| | | | | | | | | |
Debt securities - Canadian |
| | | | | | | | | | |
Corporate | | | | | | | | | 1,156 | | | | 1,156 |
| | | | | | | | | |
Government | | | | | | | | | 3,842 | | | | 3,842 |
| | | | | | | | | |
Asset backed | | | | | | | | | 2 | | | | 2 |
| | | | | | | | | |
Equities – Venture capital | | | | | | | | | 199 | | | | 199 |
| | | | | | | | | |
Cash | | | | | | | | | 31 | 10 | | | | | | | | | 21 |
Total plan assets at fair value | | | | | | | | | 7,541 | 10 | | | | | | | | | 7,531 |
|
| | | | | | 51 |
|
The 2021 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, 2021, using: |
| | | | | | Net Asset |
mil ions of Canadian dol ars | | | Total | Level 1 | | Level 2 | Level 3 | Value |
Asset class |
| | | | | | | | | | |
Equity securities |
| | | | | | | | | | |
Canadian | | | 247 | | | | | | | | 247 |
| | | | | | | | | |
Non-Canadian | | | 2,539 | | | | | | | | 2,539 |
| | | | | | | | | |
Debt securities - Canadian |
| | | | | | | | | | |
Corporate | | | 1,496 | | | | | | | | 1,496 |
| | | | | | | | | |
Government | | | 4,865 | | | | | | | | 4,865 |
| | | | | | | | | |
Asset backed | | | 1 | | | | | | | | 1 |
| | | | | | | | | |
Equities – Venture capital | | | 249 | | | | | | | | 249 |
| | | | | | | | | |
| | | | | | | | | |
Cash | | | 43 | | | | | 36 | | | 7 |
| | | | | | | | | |
Total plan assets at fair value | | | 9,440 | | | | | 36 | | | 9,404 |
A summary of pension plans with accumulated benefit obligation and projected benefit obligation in excess of plan assets is shown in the table below: |
| | | | Pension benefits |
mil ions of Canadian dol ars | | | | | | | | | 2022 | 2021 |
For funded pension plans with projected benefit obligation in excess of plan assets: (a) (b) |
| | | | | |
Projected benefit obligation | | | | | — | | | | | 1,132 |
Fair value of plan assets | | | | | — | | | | | 1,031 |
Projected benefit obligation less fair value of plan assets | | | | | — | 101 |
|
For unfunded pension plans covered by book reserves: |
| | | | | |
Projected benefit obligation | | | | | | | | | 376 | 499 |
Accumulated benefit obligation | | | | | | | | | 353 | 461 |
(a) In 2022, the fair value of plan assets exceeded the projected benefit obligation for both the company sponsored plan |
| | | | | | | | | | | | and its proportionate share of a joint venture sponsored plan. |
(b) In 2021, projected benefit obligation exceeded the fair value of plan assets only for the company’s proportionate share |
| | | | | | | | | | | | of a joint venture sponsored pension plan. |
Cash flows Benefit payments expected in: |
| | | | | | | | | | Other postretirement |
mil ions of Canadian dol ars | | | | Pension benefits | | benefits |
2023 | | | | | 480 | | | | | | 29 |
2024 | | | | | 470 | | | | | | 30 |
2025 | | | | | 470 | | | | | | 30 |
2026 | | | | | 470 | | | | | | 31 |
2027 | | | | | 470 | | | | | | 31 |
2028 - 2032 | | | | | 2,360 | | | | | | 166 |
In 2023, the company expects to make cash contributions of about $180 mil ion to its pension plans. |
| | 52 |
|
5. Other long-term obligations |
mil ions of Canadian dol ars | | 2022 | 2021 |
Employee retirement benefits (a) (note 4) | | 902 | 1,362 |
Asset retirement obligations and other environmental liabilities (b) (c) | | 2,150 | 1,713 |
Share-based incentive compensation liabilities (note 7) | | 101 | 79 |
Operating lease liability (note 13) | | 151 | 147 |
Other obligations | | 163 | 596 |
Total other long-term obligations | | 3,467 | 3,897 |
(a) Total recorded employee retirement benefits obligations also included $63 mil ion in current liabilities (2021 – $56 mil ion). (b) Total asset retirement obligations and other environmental liabilities also included $116 mil ion in current liabilities (2021 – $102 |
| | | | mil ion). |
(c) For 2022, the asset retirement obligations were discounted at 6 percent (2021 - 6 percent). Asset retirement obligations incurred in |
| | | | the current period were level 3 fair value measurements. |
The fol owing table summarizes the activity in the liability for asset retirement obligations: |
| | | | mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
| | | | Balance as at January 1 | | 1,721 | 1,674 | 1,400 |
| | | | Additions (deductions) | | 415 | 6 | 265 |
| | | | Accretion | | 101 | 99 | 82 |
| | | | Settlement | | (59) | (58) | (73) |
| | | | Balance as at December 31 | | 2,178 | 1,721 | 1,674 |
Estimated cash payments for asset retirement obligations are $82 mil ion in 2023 and $64 mil ion in 2024. |
| | | | | | | 53 |
|
6. 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, 2022 and December 31, 2021, the fair value of long-term debt ($3,447 mil ion and $4,447 mil ion respectively, excluding finance lease obligations) was primarily a level 2 measurement. |
Derivative instruments The company’s size, strong capital structure and the complementary nature of its business segments 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 derivatives, to manage commodity price risk and to generate returns from trading. Commodity contracts held for trading purposes are presented in the Consolidated statement of income on a net basis in the line “Revenues”. 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, the net notional long / (short) position of derivative instruments was: |
thousands of barrels | | 2022 | 2021 |
Crude | | 1,800 | 7,390 |
Products | | (350) | (560) |
Realized and unrealized gain or (loss) on derivative instruments recognized in the Consolidated statement of income is included in the fol owing lines on a before-tax basis: |
mil ions of Canadian dol ars | | | | | 2022 | 2021 | 2020 |
Revenues | | | | | 148 | (46) | (13) |
Purchases of crude oil and products | | | | | — | (33) | (21) |
Total | | | | | 148 | (79) | (34) |
The estimated fair value of derivative instruments, and the related hierarchy level for the fair value measurement is as fol ows: |
At December 31, 2022mil ions of Canadian dol ars |
| | | | | | Fair value | Effect of | Effect of | Net |
| | | | | counterparty | col ateral | carrying |
| netting | netting | value | | | | | | | | Level 1 Level 2 Level 3 | Total |
Assets Derivative assets (a) |
| | | | | | | | 17 | 32 | — | 49 | (27) | | | | | | | — | 22 |
|
Liabilities Derivative liabilities (b) |
| | | | | | | | 21 | 20 | — | 41 | (27) | | | | | | | (4) | 10 |
(a) Included in the Consolidated balance sheet line: “Materials, supplies and prepaid expenses”, “Accounts receivable - net” and “Other |
| | | | | | | | | assets, including intangibles - net”. |
(b) Included in the Consolidated balance sheet line: “Accounts payable and accrued liabilities” and “Other long-term obligations”. |
| | | | | | 54 |
|
7. 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 incentive 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 the five-day average of the closing price of the company’s common shares on the Toronto Stock Exchange on and immediately prior to the vesting dates. For the majority of the units, 50 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. As a result of an employee stock program expansion implemented in 2022, some new participants wil be eligible for awards granted that vest 100 percent after three years. The company may also issue units to the chairman, president and chief executive officer where 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, except that for awards granted prior to 2020, the vesting of the tenth anniversary portion is delayed until retirement if later than 10 years. |
The deferred share unit plan is made available to nonemployee directors. The nonemployee directors can elect to receive al 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 dol ar 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 fol owing 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. |
Al units require settlement by cash payments with the fol owing 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 the tenth anniversary of grant, the recipient may receive one common share of the company per unit or elect to receive cash payment for al that vest. |
The company accounts for al 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 fol owing table summarizes information about these units for the year ended December 31, 2022: |
| Restricted | Deferred |
| stock units | share units |
Outstanding at January 1, 2022 | | 3,950,615 | 166,665 |
Granted | | 884,140 | 13,219 |
Vested / Exercised | | (787,110) | | — |
Forfeited and cancel ed | | (11,290) | | — |
Outstanding at December 31, 2022 | | 4,036,355 | 179,884 |
|
| | | | 56 |
|
In 2022, the before-tax compensation expense charged against income for these programs was $113 mil ion (2021 - $96 mil ion expense, 2020 - $2 mil ion benefit). Income tax benefit recognized in income related to compensation expense for the year was $27 mil ion (2021 - $23 mil ion, 2020 - $0 mil ion). Cash payments of $78 mil ion were made for these programs in 2022 (2021 - $52 mil ion, 2020 - $33 mil ion). |
As of December 31, 2022, there was $133 mil ion of total before-tax unrecognized compensation expense related to non-vested restricted stock units based on the company’s share price at the end of the current reporting period. The weighted-average vesting period of non-vested restricted stock units is 4.1 years. Al units under the deferred share programs have vested as of December 31, 2022. |
8. Investment and other income |
Investment and other income includes gains and losses on asset sales as fol ows: |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Proceeds from asset sales | | 904 | 81 | 82 |
Book value of asset sales | | 746 | 32 | 47 |
Gain (loss) on asset sales, before tax (a) | | 158 | 49 | 35 |
Gain (loss) on asset sales, after tax (a) | | 241 | 43 | 32 |
(a) 2022 included a gain of $116 mil ion ($208 mil ion, after tax) from the sale of interests in XTO Energy Canada, which included the |
| | | | | removal of a deferred tax liability. |
9. 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 wel as other matters which management believes should be disclosed. Based on a consideration of al relevant facts and circumstances, the company does not believe the ultimate outcome of any currently pending lawsuits against the company wil have a material adverse effect on the company’s operations, financial condition, or financial statements taken as a whole. |
Additional y, the company has other commitments arising in the normal course of business for operating and capital needs, al of which are expected to be fulfil ed 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 wil provide the contracted goods and services. The company has not 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, 2022, for guarantees relating to performance under contracts of other third-party obligations total ing $17 mil ion (2021 - $21 mil ion). |
|
| | | | | | 57 |
|
10. Common shares |
At December 31thousands of shares |
| | 2022 | 2021 |
Authorized | | 1,100,000 | | 1,100,000 |
Common shares outstanding | | 584,153 | 678,080 |
The most recent 12-month normal course issuer bid program came into effect June 29, 2022, under which Imperial continued its existing share purchase program. The program enabled the company to purchase up to a maximum of 31,833,809 common shares (5 percent of the total shares on June 15, 2022) which included shares purchased under the normal course issuer bid and from Exxon Mobil Corporation concurrent with, but outside of the normal course issuer bid. As in the past, Exxon Mobil Corporation advised the company that it intended to participate to maintain its ownership percentage at approximately 69.6 percent. The program completed on October 21, 2022 as a result of the company purchasing the maximum al owable number of shares under the program. |
On May 6, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancel ation up to $2.5 bil ion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on June 15, 2022, with the company taking up and paying for 32,467,532 common shares at a price of $77.00 per share, for an aggregate purchase of $2.5 bil ion and 4.9 percent of Imperial’s issued and outstanding shares at the close of business on May 2, 2022. This included 22,597,379 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent. |
On November 4, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancel ation up to $1.5 bil ion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on December 14, 2022, with the company taking up and paying for 20,689,655 common shares at a price of $72.50 per share, for an aggregate purchase of $1.5 bil ion and 3.4 percent of Imperial’s issued and outstanding shares at the close of business on October 31, 2022. This included 14,399,985 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent. |
The excess of the purchase cost over the stated value of shares purchased has been recorded as a distribution of earnings reinvested. |
The company’s common share activities are summarized below: |
| Thousands of | | Mil ions of |
| | shares | dol ars |
Balance as at January 1, 2020 | | 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 |
Issued under employee share-based awards | | 7 | — |
Purchases at stated value | | (56,004) | (105) |
Balance as at December 31, 2021 | | 678,080 | 1,252 |
Issued under employee share-based awards | | — | — |
Purchases at stated value | | (93,927) | (173) |
Balance as at December 31, 2022 | | 584,153 | 1,079 |
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|
The fol owing table provides the calculation of basic and diluted earnings per common share and the dividends declared by the company on its outstanding common shares: |
| | 2022 | 2021 | 2020 |
Net income (loss) per common share – basic |
| | | | | | |
Net income (loss) | | | | | | | (mil ions of Canadian dol ars) | | 7,340 | 2,479 | (1,857) |
Weighted-average number of common shares outstanding | | | | | | | | (mil ions of shares) | | 640.2 | 711.6 | 735.3 |
Net income (loss) per common share (dol ars) | | 11.47 | 3.48 | (2.53) |
|
Net income (loss) per common share – diluted |
| | | | | | |
Net income (loss) | | | | | | | (mil ions of Canadian dol ars) | | 7,340 | 2,479 | (1,857) |
Weighted-average number of common shares outstanding | | | | | | | | (mil ions of shares) | | 640.2 | 711.6 | 735.3 |
Effect of employee share-based awards (mil ions of shares) (a) | | 1.3 | 1.6 | — |
Weighted-average number of common shares outstanding, assuming dilution (mil ions of shares) |
| | 641.5 | 713.2 | 735.3 |
Net income (loss) per common share (dol ars) | | 11.44 | 3.48 | (2.53) |
|
Dividends per common share – declared (dol ars) | | 1.46 | 1.03 | 0.88 |
(a) For 2020, the Net income (loss) per common share – diluted excludes the effect of 1.9 mil ion employee share-based awards. Share- |
| | | | | | | | | based awards have the potential to dilute basic earnings per share in the future. |
| | | | | | | | 59 |
|
11. Miscellaneous financial information |
LIFO inventoryIn 2022, net income included an after-tax gain of $62 mil ion (2021 – $13 mil ion loss, 2020 – $19 mil ion loss) attributable to the effect of changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, 2022 by about $2 bil ion (2021 – $1.8 bil ion). Inventories of crude oil and products at year-end consisted of the fol owing: |
mil ions of Canadian dol ars | | 2022 | 2021 |
Crude oil | | 809 | 674 |
Petroleum products | | 471 | 310 |
Chemical products | | 76 | 73 |
Other | | 158 | 45 |
Total | | 1,514 | 1,102 |
In 2021, the company recorded an unfavourable $74 mil ion ($82 mil ion, before tax) inventory adjustment (including the proportionate share of LIFO changes) related to reconciliations of additives and products inventory at equity and third-party terminals. The out-of-period impact of $57 mil ion ($63 mil ion, before tax) occurred over a number of years, and has been resolved. The company determined that the adjustment was not material to the consolidated financial statements for the year ended December 31, 2021, or any of the prior periods related to the adjustment. Accordingly, comparative periods presented in the consolidated financial statements have not been restated. |
Research and developmentResearch 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 wel as accessing ExxonMobil’s research worldwide. |
The company has scientific research agreements with affiliates of ExxonMobil, which provide for technical and engineering work to be performed by al parties, the exchange of technical information and the assignment and licensing of patents, and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties. |
Net research and development costs charged to expenses in 2022 were $74 mil ion (2021 – $89 mil ion, 2020 – $105 mil ion). These costs are included in expenses due to the uncertainty of future benefits. |
Accounts payable and accrued liabilities“Accounts payable and accrued liabilities” included accrued taxes other than income taxes of $458 mil ion at December 31, 2022 (2021 – $415 mil ion). |
Goodwill impairmentIn the first quarter of 2020, the company assessed its goodwil balances for impairment and recognized a non-cash goodwil impairment charge of $20 mil ion in the company’s Upstream segment. The goodwil impairment was reflected in “Depreciation and depletion” on the Consolidated statement of income and “Goodwil ” on the Consolidated balance sheet. The remaining balance of goodwil is associated with the Downstream segment. |
Government assistanceThe company received subsidies as part of the Government of Canada’s COVID-19 Economic Response Plan, which included the company’s proportionate share of a joint venture. It was recognized as a reduction to expense (2020 – $155 mil ion before tax) and was included in the Consolidated statement of income, primarily as part of “Production and manufacturing”. |
In 2022, the company prospectively adopted the Financial Accounting Standards Board’s standard, Government Assistance (Topic 832). The standard requires the annual disclosure of certain types of government assistance not otherwise covered by authoritative accounting guidance. The company receives al owances from governments in the form of emission credits as a result of performing better than facility level expectations for emission targets and records these at a nominal amount in the Consolidated balance sheet. During 2022, government assistance was immaterial to the company’s financial results. |
| | | | 60 |
|
12. Financing and additional notes and loans payable information |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Debt-related interest (a) | | 111 | 63 | 102 |
Capitalized interest | | (57) | (24) | (41) |
Net interest expense | | 54 | 39 | 61 |
Other interest | | 6 | 15 | 3 |
Total financing (b) | | 60 | 54 | 64 |
(a) Includes related party interest with ExxonMobil. |
(b) The weighted-average interest rate on short-term borrowings in 2022 was 2.0 percent (2021 – 0.2 percent, 2020 – 0.8 percent) and |
| | | | | on long-term borrowings, with ExxonMobil, in 2022 was 1.9 percent (2021 – 0.6 percent, 2020 – 1.4 percent). |
During the second quarter of 2022, the company reduced its existing $500 mil ion committed long-term line of |
|
credit to $250 mil ion and extended the maturity date to June 30, 2023. Subsequently in the fourth quarter of 2022, this committed long-term line of credit was cancel ed in ful . The company also extended one of its $250 mil ion committed long-term lines of credit to June 30, 2024. |
In November 2022, the company extended the maturity date of an existing $250 mil ion committed short-term line of credit to November 2023. |
The company has not drawn on any of its outstanding $500 mil ion of available credit facilities. |
In 2021, the company repaid the $111 mil ion outstanding balance and terminated the non-interest bearing, revolving demand loan under an arrangement with an affiliate company of ExxonMobil. |
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|
13. Leases |
The company general y 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. Usual y, 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 al 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: |
| 2022 | 2021 | 2020 |
| | | | Operating | Finance | Operating | Finance | Operating | Finance |
mil ions of Canadian dol ars | leases | | | | leases | leases | | | | | leases | leases | | | | | | leases |
Operating lease cost | | | | | 119 | | | | | | 123 | | | | | | | 157 |
Short-term and other (net of sublease rental income) | 40 | | | | | | 19 | | | | | | | 40 |
|
Amortization of right of use assets | | | | | | 19 | | | | | | | 17 | | | | | | | 29 |
Interest on lease liabilities | | | | | | 30 | | | | | | | 33 | | | | | | | 38 |
Total lease cost | | | | | 159 | | | | | 49 | 142 | | | | | | 50 | 197 | | | | | | 67 |
The fol owing table summarizes the amounts related to operating leases and finance leases recorded on the Consolidated balance sheet, weighted-average remaining lease term and weighted-average discount rates applied at December 31: |
| | 2022 | 2021 |
|
| | | | | | Operating | Finance | | | | | | Operating | Finance |
mil ions of Canadian dol ars | | | | | | leases | leases | leases | | | | | | leases |
Right of use assets |
| | | | | | | | | | | | | | |
Included in Other assets, including intangibles - net | | | | | | | 245 | | | | | | | 245 |
Included in Property, plant and equipment, less | | | | | | | 618 | | | | | | | 637 |
accumulated depreciation and depletion |
| | | | | | | | | | | | | | |
Total right of use assets | | | | | | | 245 | | | | | 618 | 245 | | | | | | 637 |
|
Lease liability due within one year |
| | | | | | | | | | | | | | |
Included in Accounts payable and accrued liabilities | | | | | | | 100 | | | | | | — | 102 | | | | | | | — |
Included in Notes and loans payable | | | | | | | 22 | | | | | | | | 22 |
Long-term lease liability |
| | | | | | | | | | | | | | |
Included in Other long-term obligations | | | | | | | 151 | | | | | | — | 147 | | | | | | | — |
Included in Long-term debt | | | | | | | 586 | | | | | | | 607 |
Total lease liability | | | | | | | 251 | | | | | 608 | 249 | | | | | | 629 |
|
Weighted-average remaining lease term (years) | | 5 | | | | | | 37 | 4 | | | | | | | 38 |
Weighted-average discount rate (percent) | | 1.1 | | | | | 4.7 | 1.2 | | | | | | | 4.8 |
| 62 |
|
| The maturity analysis of the company’s lease liabilities as at December 31 are summarized below: |
| 2022 |
|
| Operating | Finance |
mil ions of Canadian dol ars | leases | leases |
Maturity analysis of lease liabilities |
| | | | |
2023 | | | | 102 | | | | 50 |
2024 | | | | 70 | | | | 49 |
2025 | | | | 15 | | | | 46 |
2026 | | | | 10 | | | | 44 |
2027 | | | | 10 | | | | 43 |
2028 and beyond | | | | 56 | 900 |
Total lease payments | | | | 263 | 1,132 |
|
Discount to present value | | | | (12) | (524) |
Total lease liability | | | | 251 | 608 |
In addition to the operating lease liabilities in the table immediately above, at December 31, 2022, additional undiscounted commitments for leases not yet commenced total ed $14 mil ion (2021 - $5 mil ion). |
Estimated cash payments for operating and finance leases not yet commenced are $5 mil ion in both 2023 and 2024. |
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: |
| | | | | | 2022 | 2021 | 2020 |
|
| | | | | | | Operating | Finance | | | Operating | Finance | Operating | Finance |
mil ions of Canadian dol ars | | | | | | | leases | leases | leases | leases | leases | leases |
Cash paid for amounts included in the measurement of lease liabilities |
| | | | | | | | | | | | | | |
Cash flows from operating activities | | | | | | | | 121 | | — | | 122 | — | | | 136 | 15 |
Cash flows from financing activities | | | | | | | | 22 | | 20 | | | | 20 |
| | | | | | | | | | |
|
Non-cash right of use assets recorded for lease liabilities |
| | | | | | | | | | | | | | |
In exchange for lease liabilities during the year | | | | | | | | 117 | | — | | 176 | 123 | 63 | 14 |
| | | | | | 63 |
|
14. Long-term debt |
At December 31 |
mil ions of Canadian dol ars | | 2022 | 2021 |
Long-term debt (a) (b) | | 3,447 | 4,447 |
Finance leases (c) | | 586 | 607 |
Total long-term debt | | 4,033 | 5,054 |
(a) Borrowed under an existing agreement with an affiliated company of ExxonMobil that provides for a long-term, variable-rate, |
| | | | Canadian dol ar loan from ExxonMobil to the company of up to $7.75 bil ion 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) During the third quarter of 2022, the company decreased its long-term debt by $1 bil ion, partial y repaying an existing facility with an |
| | | | affiliated company of ExxonMobil. |
(c) Finance leases are primarily associated with transportation facilities and services agreements. The average imputed interest rate was |
| | | | 4.7 percent in 2022 (2021 – 4.8 percent). Total finance lease obligations also include $22 mil ion in current liabilities (2021 - $22 mil ion). Principal payments on finance leases of approximately $20 mil ion on average per year are due in each of the next four years after December 31, 2023. |
15. Accounting for suspended exploratory well costs |
The company continues capitalization of exploratory wel costs when the wel has found a sufficient quantity of reserves to justify its completion as a producing wel 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. The company had no capitalized suspended exploratory wel costs as at December 31, 2022, 2021 and 2020. |
Exploration activity involves dril ing multiple wel s, over a number of years, to ful y evaluate a project. The company had no projects with exploratory wel s costs capitalized as at December 31, 2022, 2021 and 2020. |
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|
16. 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 wel 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 al ow the companies to consolidate duplicate work and systems; |
b) To operate certain western Canada production properties owned by ExxonMobil, as wel 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 option of equal participation in new upstream opportunities; and |
d) To enter into derivative agreements on each other’s behalf. |
The company had an existing agreement with ExxonMobil to provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil, which was terminated in connection with the transfer of operatorship of Syncrude on September 30, 2021. |
Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate. |
The amounts of purchases and revenues by Imperial in 2022, with ExxonMobil, were $3,719 mil ion and $17,042 mil ion respectively (2021 - $2,669 mil ion and $8,777 mil ion respectively). |
As at December 31, 2022, the company had an outstanding long-term loan of $3,447 million (2021 – $4,447 million) from ExxonMobil (see note 14, "Long-term debt", on page 104 and note 12, "Financing and additional notes and loans payable information", on page 101 for further details). The amount of financing costs with ExxonMobil were $78 million (2021 - $28 million). |
Imperial has other related party transactions not detailed above in note 16, as they are not significant. |
|
| 65 |
|
17. Other comprehensive income (loss) information |
Changes in accumulated other comprehensive income (loss): |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Balance at January 1 | | (1,177) | (1,989) | (1,911) |
Postretirement benefits liability adjustment: |
| | | | | | |
Current period change excluding amounts reclassified |
from accumulated other comprehensive income | | 582 | 679 | (212) |
Amounts reclassified from accumulated other comprehensive income | | 83 | 133 | 134 |
Balance at December 31 | | (512) | (1,177) | (1,989) |
Amounts reclassified out of accumulated other comprehensive income (loss) - before-tax income (expense): |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Amortization of postretirement benefits liability adjustment included in net benefit cost (a) |
| | (110) | (176) | (180) |
(a) This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 4). |
Income tax expense (credit) for components of other comprehensive income (loss): |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Postretirement benefits liability adjustments: |
| | | | | | |
Postretirement benefits liability adjustment (excluding amortization) | | 188 | 221 | (69) |
Amortization of postretirement benefits liability adjustment included in net benefit cost |
| | 27 | 43 | 46 |
Total | | 215 | 264 | (23) |
| | | | | | | |
18. Divestment activities |
Jointly with ExxonMobil Canada, Imperial signed an agreement in the second quarter of 2022 with Whitecap Resources Inc. |
| | | | | | | | for the sale of its interests in XTO Energy Canada which included assets in the Montney and |
Duvernay areas of central Alberta, for total cash consideration of approximately $1.9 bil ion ($0.9 bil ion Imperial's share). The transaction closed on August 31, 2022 and the company recognized a gain of approximately $0.2 bil ion, after tax. Imperial’s total assets associated with this transaction include about $0.9 bil ion (about $0.8 bil ion of property, plant and equipment) and about $0.2 bil ion total liabilities in the Upstream segment. |
| | | | | | | 66 |
|
Supplemental information on oil and gas exploration and production activities (unaudited) |
The information on pages 107 to 108 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 crude 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 (SEC) 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 |
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Revenue |
Sales to third parties (a) | | 7,154 | 5,081 | 2,066 |
Transfers (a) (b) | | 4,182 | 3,037 | 1,777 |
| | 11,336 | 8,118 | 3,843 |
Production expenses | | 5,521 | 4,728 | 3,977 |
Exploration expenses | | 5 | 32 | 13 |
Depreciation and depletion (includes impairments) | | 1,467 | 1,579 | 2,857 |
Income taxes | | 1,030 | 457 | (678) |
Results of operations | | 3,313 | 1,322 | (2,326) |
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 wel 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 |
|
mil ions of Canadian dol ars | | 2022 | 2021 | 2020 |
Property costs (c) |
Proved | | — | — | — |
Unproved | | — | — | — |
Exploration costs | | 5 | 32 | 13 |
Development costs | | 1,602 | 576 | 816 |
Total costs incurred in property acquisitions, exploration and |
development activities | | 1,607 | 608 | 829 |
(a) Sales to third parties or transfers do not include the sale of natural gas and natural gas liquids purchased for resale, as wel as royalty |
| | | | | payments or diluent costs. These items are reported gross in note 2 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-wel costs are included under “producing assets”). “Proved” represents areas where successful dril ing has delineated a field capable of production. “Unproved” represents al other areas. |
| | | | | | 67 |
|
Capitalized costs |
mil ions of Canadian dol ars | | 2022 | 2021 |
Property costs | | | | (a) |
Proved | | 1,840 | 2,045 |
Unproved | | 493 | 2,468 |
Producing assets | | 39,075 | 39,926 |
Incomplete construction | | 2,375 | 1,762 |
Total capitalized cost | | 43,783 | 46,201 |
Accumulated depreciation and depletion | | (18,512) | (20,112) |
Net capitalized costs | | 25,271 | 26,089 |
(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-wel costs are included under “producing assets”). “Proved” represents areas where successful dril ing has delineated a field capable of production. “Unproved” represents al 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 applying first-day-of-the-month average prices, 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, including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change. |
Standardized measure of discounted future net cash flows related to proved oil and gas reserves |
mil ions of Canadian dol ars | | | | | | | 2022 | 2021 | 2020 |
Future cash flows | | | | | | | 198,923 | 161,577 | 23,911 |
Future production costs | | | | | | | (104,765) | (101,580) | (18,787) |
Future development costs | | | | | | | (23,392) | (21,903) | (6,096) |
Future income taxes | | | | | | | (16,872) | (8,192) | (155) |
Future net cash flows | | | | | | | 53,894 | 29,902 | (1,127) |
Annual discount of 10 percent for estimated timing of cash flows | | | | | | | (28,340) | (15,732) | 1,065 |
Discounted future cash flows | | | | | | | 25,554 | 14,170 | (62) |
Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves |
mil ions of Canadian dol ars | | | | | | | 2022 | 2021 | 2020 |
Balance at beginning of year | | | | | | | 14,170 | (62) | 5,511 |
Changes resulting from: |
Sales and transfers of oil and gas produced, net of production costs | | | | | | | (6,113) | (3,841) | (447) |
Net changes in prices, development costs and production costs (a) | | | | | | | 23,215 | 7,681 | (8,661) |
Extensions, discoveries, additions and improved recovery, less related costs |
| | | | | | | 664 | 52 | 114 |
Development costs incurred during the year | | | | | | | 1,160 | 650 | 563 |
Revisions of previous quantity estimates | | | | | | | (4,431) | 13,482 | 459 |
Accretion of discount | | | | | | | 1,439 | 24 | 623 |
Net change in income taxes | | | | | | | (4,550) | (3,816) | 1,776 |
Net change | | | | | | | 11,384 | 14,232 | (5,573) |
Balance at end of year | | | | | | | 25,554 | 14,170 | (62) |
(a) SEC rules require the company’s reserves to be calculated on the basis of average first-day-of-the-month oil and natural gas prices |
| | | | | during the reporting year. Future net cash flows are determined based on the net proved reserves as outlined in the “Net proved reserves table”. |
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Net proved reserves (a) |
| | | | Total |
| | Synthetic | | | oil-equivalent |
| Liquids (b) Natural gas | crude oil | Bitumen | basis (c) |
| mil ions of | | | | | bil ions of | mil ions of | mil ions of | mil ions of |
| barrels | | | | | cubic feet | barrels | barrels | barrels |
Beginning of year 2020 | | | | | | | 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 |
Revisions | | | | | | | 13 | 165 | | 17 | 2,239 | 2,297 |
Improved recovery | | | | | | | — | | — | — | 2 | 2 |
(Sale) purchase of reserves in place | | | | | | | — | (10) | | — | — | (2) |
Discoveries and extensions | | | | | | | — | | — | — | — | — |
Production | | | | | | | (4) | (42) | | (23) | (106) | (140) |
End of year 2021 | | | | | | | 16 | 281 | | 438 | 2,216 | 2,717 |
Revisions | | | | | | | — | (41) | | (62) | (363) | (432) |
Improved recovery | | | | | | | — | | — | — | — | — |
(Sale) purchase of reserves in place | | | | | | | (9) | (141) | | — | — | (32) |
Discoveries and extensions | | | | | | | — | | 2 | — | 67 | 67 |
Production | | | | | | | (3) | (29) | | (23) | (96) | (127) |
End of year 2022 | | | | | | | 4 | | 72 | 353 | 1,824 | 2,193 |
Net proved developed reserves included above, as ofJanuary 1, 2020 |
| | | | | | | 22 | 291 | | 415 | 2,609 | 3,095 |
December 31, 2020 | | | | | | | 7 | 167 | | 311 | 76 | 422 |
December 31, 2021 | | | | | | | 14 | 205 | | 326 | 1,957 | 2,331 |
December 31, 2022 | | | | | | | 4 | | 60 | 248 | 1,691 | 1,953 |
Net proved undeveloped reserves included above, as ofJanuary 1, 2020 |
| | | | | | | 19 | 290 | | — | 330 | 397 |
December 31, 2020 | | | | | | | — | | 1 | 133 | 5 | 138 |
December 31, 2021 | | | | | | | 2 | | 76 | 112 | 259 | 386 |
December 31, 2022 | | | | | | | — | | 12 | 105 | 133 | 240 |
(a) Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both. Al 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 mil ion cubic feet per one thousand barrels. |
The information above describes changes during the years and balances of proved oil and gas reserves at year-end 2020, 2021 and 2022. The definitions used are in accordance with the SEC Rule 4-10 (a) of Regulation S-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 economical y 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 wel s and other facilities wil be required to recover these proved reserves. |
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In accordance with SEC rules, the year-end reserves volumes, as wel as the reserves change categories shown in the proved reserves tables are required to be calculated on the basis of average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserves quantities were also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. |
Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in the average of first-day-of-the-month oil and natural gas prices and / or costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment and facility capacity. |
In 2020, downward revisions of proved bitumen reserves were a result of low prices. The 2.2 bil ion barrels of bitumen at Kearl and 0.6 bil ion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the SEC definition of proved reserves. Downward revisions to proved synthetic crude 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. |
In 2021, upward revisions of proved bitumen reserves were a result of improved prices. The 1.7 bil ion barrels of bitumen at Kearl and 0.5 bil ion barrels of bitumen at Cold Lake qualified as proved reserves under the SEC definition of proved reserves. Upward revisions to proved synthetic crude oil reserves were a result of improved prices. Changes to the liquids and natural gas proved reserves were the result of updated development plans and divestments at the Montney and Duvernay unconventional assets. |
In 2022, downward revisions of proved bitumen reserves were driven by a decrease of 0.2 bil ion barrels at Kearl as a result of higher royalty obligations associated with pricing, and a decrease of 0.2 bil ion barrels at Cold Lake due to an updated development plan. An increase to the bitumen reserves of 0.1 bil ion barrels is associated with extensions at Cold Lake for the Grand Rapids Phase 1 SA-SAGD and Leming SAGD projects. Downward revisions to proved synthetic crude oil reserves were a result of mine development plan updates and higher royalty obligations at Syncrude associated with pricing. Changes to the liquids and natural gas proved reserves were primarily a result of the sale of the company’s interest in the Montney and Duvernay unconventional assets. |
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 and its outlook for future production volumes are not impacted by proved reserves as disclosed under the 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 crude 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 al cases, actual future royalty rates may vary with production, price and costs. |
Net proved developed reserves are those volumes that are expected to be recovered through existing wel s, facilities, or mining activities 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 wel or facility. Net proved undeveloped reserves are those volumes that are expected to be recovered as a result of future investments to dril new wel s, to recomplete existing wel s and / or to instal facilities to col ect and deliver the production from existing and future wel s, facilities, or mining activities. |
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