# Imperial Oil Ltd: Form 10-K for the period ended Dec 31, 2017

- Company: [Imperial Oil Ltd](/companies/imo.md) (CIK 49938)
- Form: 10-K
- Filed: 2018-03-01
- Accepted by EDGAR: Feb 28, 2018, 18:54 ET
- Period: 2017-12-31
- Accession: 0001193125-18-064765
- Inline XBRL: yes
- Main document: https://www.sec.gov/Archives/edgar/data/49938/000119312518064765/d490359d10k.htm
- All documents and exhibits: https://www.sec.gov/Archives/edgar/data/49938/000119312518064765/

## Figures reported in this filing

Standardized XBRL line items for the period ended 2017-12-31.

| Line item | Period | Value | XBRL concept |
| --- | --- | ---: | --- |
| Research and development | 12 months, 2017-01-01 to 2017-12-31 | CAD 111.0m | us-gaap:ResearchAndDevelopmentExpense |
| Income tax | 12 months, 2017-01-01 to 2017-12-31 | CAD 92.0m | us-gaap:IncomeTaxExpenseBenefit |
| Net income | 12 months, 2017-01-01 to 2017-12-31 | CAD 490.0m | us-gaap:NetIncomeLoss |
| Diluted EPS | 12 months, 2017-01-01 to 2017-12-31 | CAD 0.58 | us-gaap:EarningsPerShareDiluted |
| Basic EPS | 12 months, 2017-01-01 to 2017-12-31 | CAD 0.58 | us-gaap:EarningsPerShareBasic |
| Diluted shares (weighted) | 12 months, 2017-01-01 to 2017-12-31 | 845,700,000 shares | us-gaap:WeightedAverageNumberOfDilutedSharesOutstanding |
| Capital expenditure | 12 months, 2017-01-01 to 2017-12-31 | CAD 993.0m | us-gaap:PaymentsToAcquireProductiveAssets |
| Dividends paid | 12 months, 2017-01-01 to 2017-12-31 | CAD 524.0m | us-gaap:PaymentsOfDividendsCommonStock |
| Share repurchases | 12 months, 2017-01-01 to 2017-12-31 | CAD 627.0m | us-gaap:PaymentsForRepurchaseOfCommonStock |
| Cash and equivalents | at 2017-12-31 | CAD 1.20bn | us-gaap:CashAndCashEquivalentsAtCarryingValue |
| Current assets | at 2017-12-31 | CAD 5.41bn | us-gaap:AssetsCurrent |
| Total assets | at 2017-12-31 | CAD 41.60bn | us-gaap:Assets |
| Current liabilities | at 2017-12-31 | CAD 4.14bn | us-gaap:LiabilitiesCurrent |
| Total liabilities | at 2017-12-31 | CAD 17.17bn | us-gaap:Liabilities |
| Long-term debt | at 2017-12-31 | CAD 4.45bn | us-gaap:LongTermDebtNoncurrent |
| Current portion of debt | at 2017-12-31 | CAD 202.0m | us-gaap:DebtCurrent |
| Shareholders' equity | at 2017-12-31 | CAD 24.43bn | us-gaap:StockholdersEquityIncludingPortionAttributableToNoncontrollingInterest |

## Business

As filed, 47,998 characters.

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

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

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

Financial information about segments and geographic areas for the company is contained in the “Financial section” of this report under note 2 to the consolidated financial statements: “Business segments”.

### Upstream

### Disclosure of reserves

#### Summary of oil and gas reserves at year-end

The table below summarizes the net proved reserves for the company, as at December 31, 2017, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the “Financial section”, starting on page 32 of this report.

All of the company’s reported reserves are located in Canada. The company has reported proved reserves based on the average of the first-day-of-the-month price for each month during the last 12-month period ending December 31. Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favourable or adverse event has occurred since December 31, 2017 that would cause a significant change in the estimated proved reserves as of that date.

| Net proved reserves: | Liquids (a) millions of barrels | Natural gas billions of cubic feet | Synthetic oil millions of barrels | Bitumen millions of barrels | Total oil-equivalent basis millions of barrels |
| --- | ---: | ---: | ---: | ---: | ---: |
| Developed | **9** | **282** | **473** | **591** | **1,120** |
| Undeveloped | **35** | **359** | **-** | **355** | **450** |
| Total net proved | **44** | **641** | **473** | **946** | **1,570** |

(a) Liquids include crude oil, condensate and natural gas liquids (NGLs). NGL proved reserves are not material and are therefore included under liquids.

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

As a result of improved prices in 2017, an additional 0.3 billion barrels of bitumen at Kearl and Cold Lake now qualify as proved reserves at year-end 2017. Among the factors that would result in additional amounts being recognized as proved reserves at some point in the future are a further recovery in yearly average price levels, a further decline in costs and additional planned investment in reliability improvements. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial.

#### Technologies used in establishing proved reserves estimates

Imperial’s proved reserves in 2017 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.

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

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

#### Preparation of reserves estimates

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

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

The internal qualified reserves evaluator is a professional geoscientist registered in Alberta, Canada and has over 19 years of petroleum industry experience, including 13 years of reserves related experience. The position provides leadership to the internal reserves management group and is responsible for filing a reserves report with the Canadian securities regulatory authorities. The company’s internal reserves evaluation staff consists of 39 persons with an average of 13 years of relevant technical experience in evaluating reserves, of whom 21 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 20 persons with an average of 14 years of relevant experience in evaluating and managing the evaluation of reserves.

### Proved undeveloped reserves

As at December 31, 2017, approximately 29 percent of the company’s proved reserves were proved undeveloped reserves reflecting volumes of 450 million oil-equivalent barrels. Most of the undeveloped reserves are associated with the Cold Lake field. This compared to 319 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2016. The increase of 131 million oil-equivalent barrels of proved undeveloped reserves includes 93 million oil-equivalent barrels at Cold Lake. Conversion of proved undeveloped reserves into proved developed was not material in 2017.

Proved undeveloped reserves that have remained undeveloped for five years or more represent about 65 percent (291 million oil-equivalent barrels) of proved undeveloped reserves and are associated with Cold Lake’s ongoing drilling program. These undeveloped reserves are planned to be developed in a staged approach to align with operational capacity and efficient capital spending commitment over the life of the field. The company is reasonably certain that these proved reserves will be produced; however the timing and amount recovered can be affected by a number of factors including completion of development projects, reservoir performance, regulatory approval, royalty framework, government policies, consumer preferences and significant changes in long-term oil and gas price levels.

One of the company’s requirements to report resources as proved reserves is that management has made significant funding commitments towards the development of the reserves. The company has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. The company made investments of about $150 million during the year to progress the development of proved undeveloped reserves in its Montney and Duvernay unconventional assets and at Cold Lake. These investments represented about 36 percent of the $416 million in total reported Upstream capital and exploration expenditures. Investments made by the company to develop quantities which no longer meet the SEC definition of proved reserves due to 2017 average prices are included in the $416 million of Upstream capital and exploration expenditures.

### Oil and gas production, production prices and production costs

Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 36 of this report for a narrative discussion on the material changes.

#### Average daily production of oil

The company’s average daily oil production by final products sold during the three years ended December 31, 2017 was as follows. All reported production volumes were from Canada.

| thousands of barrels per day (a) Bitumen: |  | 2017 | 2016 | 2015 |
| --- | --- | ---: | ---: | ---: |
| Cold Lake: | - gross (b) | **162** | 161 | 158 |
|  | - net (c) | **132** | 138 | 139 |
| Kearl: | - gross (b) | **126** | 120 | 108 |
|  | - net (c) | **123** | 118 | 106 |
| Total bitumen: | - gross (b) | **288** | 281 | 266 |
|  | - net (c) | **255** | 256 | 245 |
| Synthetic oil (d): | - gross (b) | **62** | 68 | 62 |
|  | - net (c) | **57** | 67 | 58 |
| Liquids: | - gross (b) | **5** | 15 | 16 |
|  | - net (c) | **4** | 13 | 15 |
| Total: | - gross (b) | **355** | 364 | 344 |
|  | - net (c) | **316** | 336 | 318 |

(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.

(b) Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.

(c) Net production is gross production less the mineral owners’ or governments’ share or both.

(d) The company’s synthetic oil production volumes were from the company’s share of production volumes in the Syncrude joint venture.

#### Average daily production and production available for sale of natural gas

The company’s average daily production and production available for sale of natural gas during the three years ended December 31, 2017 are set forth below. All reported production volumes were from Canada. All gas volumes in this report are calculated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 36 of this report for a narrative discussion on the material changes.

| millions of cubic feet per day (a) | 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Gross production (b) (c) | **120** | 129 | 130 |
| Net production (c) (d) (e) | **114** | 122 | 125 |
| Net production available for sale (f) | **80** | 87 | 94 |

(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.

(b) Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.

(c) Production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected.

(d) Net production is gross production less the mineral owners’ or governments’ share or both.

(e) Net production reported in the above table is consistent with production quantities in the net proved reserves disclosure.

(f) Includes sales of the company’s share of net production and excludes amounts used for internal consumption.

#### Total average daily oil-equivalent basis production

The company’s total average daily production expressed in an oil-equivalent basis is set forth below, with natural gas converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.

| thousands of barrels per day (a) Total production oil-equivalent basis: | 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| - gross (b) | **375** | 386 | 366 |
| - net (c) | **335** | 356 | 339 |

(a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.

(b) Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.

(c) Net production is gross production less the mineral owners’ or governments’ share or both.

#### Average unit sales price

The company’s average unit sales price and average unit production costs by product type for the three years ended December 31, 2017 were as follows.

| Canadian dollars per barrel | 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Bitumen | **39.13** | 26.52 | 32.48 |
| Synthetic oil | **67.58** | 57.12 | 61.33 |
| Liquids | **38.49** | 28.01 | 30.62 |
| dollars per thousand cubic feet |  |  |  |
| Natural gas | **2.58** | 2.41 | 2.78 |

In 2017, Imperial’s average Canadian dollar realizations for bitumen and synthetic crudes increased generally in line with the North American benchmarks, adjusted for changes in the exchange rate and transportation costs.

In 2016, Imperial’s average Canadian dollar realizations for bitumen and synthetic crudes declined essentially in line with the North American benchmarks, adjusted for changes in the exchange rate and transportation costs.

#### Average unit production costs

| Canadian dollars per barrel | 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Bitumen | **26.81** | 24.24 | 25.16 |
| Synthetic oil | **58.96** | 46.24 | 54.81 |
| Total oil-equivalent basis (a) | **32.96** | 28.52 | 30.60 |

(a) Includes liquids, bitumen, synthetic oil and natural gas.

In 2017, synthetic oil unit production costs were higher, primarily driven by impacts of the fire at the Syncrude Mildred Lake upgrader.

In 2016, synthetic oil unit production costs were lower, primarily driven by increased volumes and cost management.

### Drilling and other exploratory and development activities

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

#### Wells drilled

The following table sets forth the net exploratory and development wells that were drilled or participated in by the company during the three years ended December 31, 2017.

| wells | 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Net productive exploratory | **-** | - | - |
| Net dry exploratory | **-** | - | - |
| Net productive development | **5** | 6 | 46 |
| Net dry development | **-** | - | - |
| Total | **5** | 6 | 46 |

In 2017 and 2016, wells were drilled to add productive capacity, associated primarily with the Montney and Duvernay unconventional assets.

In 2015, the following wells were drilled to add productive capacity: 41 development wells at Cold Lake, of which 36 development wells relate to the Cold Lake Nabiye expansion project and five net other wells.

#### Wells drilling

At December 31, 2017, the company was participating in the drilling of the following exploratory and development wells, located primarily within the Montney and Duvernay unconventional assets. All wells were located in Canada.

| wells | 2017 Gross | Net |
| --- | ---: | ---: |
| Total | **21** | **9** |

#### Exploratory and development activities regarding oil and gas resources

#### Cold Lake

To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically.

The company also conducts experimental pilot operations to improve recovery of bitumen from wells by means of new drilling, production or recovery techniques.

#### Aspen, Cold Lake expansion and other oil sands activities

The company filed a regulatory application for a new in-situ oil sands project at Aspen in December 2013, using steam-assisted gravity drainage (SAGD) technology to develop the project in three phases producing about 45,000 barrels per day before royalties, per phase.

In 2015, the company amended the regulatory application to develop the Aspen project using solvent-assisted, steam-assisted gravity drainage (SA-SAGD) technology. The technology significantly improves capital efficiency and lowers greenhouse gas intensity versus the existing SAGD technologies. The project is proposed to be executed in two phases producing about 75,000 barrels per day before royalties, per phase. Development timing is subject to regulatory approvals and market conditions. In April 2016, Imperial was notified by the Alberta Energy Regulator that the project’s environment impact assessment was deemed complete. No final investment decision has been made.

In March 2016, Imperial filed a regulatory application for the Cold Lake Expansion project to develop the Grand Rapids interval using SA-SAGD technology. The project is proposed to produce 50,000 barrels per day, before royalties. Development timing is subject to regulatory approval and market conditions. In March 2017, Imperial was notified by the Alberta Energy Regulator that the project’s environmental impact assessment was deemed complete. No final investment decision has been made.

Work continues on technical evaluations to support potential Corner and Clyden in-situ development regulatory applications.

The company also has interests in other oil sands leases in the Athabasca and Peace River areas of northern Alberta. Evaluation wells completed on these leased areas established the presence of bitumen. The company continues to evaluate these leases to determine their potential for future development.

#### Other activities

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

A decision has been made not to proceed at this time with Horn River development which resulted in a 2017 impairment charge of $396 million, before tax, associated with the write-off of the net book value of the Horn River assets.

#### Mackenzie Delta

In 1999, the company and three other companies entered into an agreement to study the feasibility of developing Mackenzie Delta gas, anchored by three large onshore natural gas fields.

In 2017, a decision was made not to proceed at this time with the Mackenzie gas project (MGP) which resulted in an impairment charge of $379 million, before tax, associated with the write-off of the net book value of the MGP assets. The company retains a 100 percent interest in the largest of these fields.

#### Beaufort Sea

In 2007, the company acquired a 50 percent interest in an exploration licence in the Beaufort Sea. As part of the evaluation, a 3-D seismic survey was conducted in 2008 and the company has since carried out data collection programs to support environmental studies and safe exploration drilling operations.

In 2010, the company executed an agreement to cross-convey interests with another company to acquire a 25 percent interest in an additional Beaufort Sea exploration licence. As a result of that agreement, the company operates both licences and its interest in the original licence was reduced to 25 percent. The exploration licences are held through 2019 and 2020, respectively.

In 2013, the company and its joint venture partners filed a project description, initiating the formal regulatory review of the project.

In December 2016, the Federal Government of Canada declared Arctic waters off limits to new offshore oil and gas licences for five years subject to review at the end of that period. Existing licences will not be impacted. The Federal Government continues to consult with existing leaseholders, including Imperial. Current activities continue to focus on data gathering and community consultation. Imperial is seeking extended terms for the Beaufort Sea exploration licences with the Federal Government. No final investment decision has been made.

#### Liquefied natural gas (LNG) activity

WCC LNG Ltd., jointly owned by the company (20 percent) and ExxonMobil Canada Ltd. (80 percent), was granted an export licence in 2013 for up to 30 million tonnes of LNG per year for a period of 25 years. In 2016, the licence period was extended to 40 years. The project is currently in the pre-application phase in a British Columbia environmental assessment process. No final investment decision has been made.

#### Exploratory and development activities regarding oil and gas resources extracted by mining methods

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

### Present activities

#### Review of principal ongoing activities

#### Cold Lake

Cold Lake is an in-situ heavy oil bitumen operation. The product, a blend of bitumen and diluent, is shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation by pipeline and rail.

During 2017, net production at Cold Lake was about 132,000 barrels per day and gross production was about 162,000 barrels per day.

#### Kearl

Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, which is processed through extraction and froth treatment trains. The company holds a 70.96 percent participating interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. The product, a blend of bitumen and diluent, is shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties.

During 2017, the company’s share of Kearl’s net bitumen production was about 123,000 barrels per day and gross production was about 126,000 barrels per day. Increased 2017 production reflects improved reliability associated with the mining and ore preparation operations.

Imperial continues to progress work to increase Kearl annual average production to 240,000 barrels of bitumen per day (Imperial’s share would be about 170,000 barrels of bitumen per day), through planned investment including supplemental crushing capacity and flow distribution interconnects at Kearl to enhance reliability, increase redundancy and reduce downtime. The work is expected to be complete by year-end 2019.

#### Syncrude

Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. The company holds a 25 percent participating interest in the joint venture. The produced synthetic crude oil is shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties.

In 2017, the company’s share of Syncrude’s net production of synthetic crude oil was about 57,000 barrels per day and gross production was about 62,000 barrels per day.

The Province of Alberta, in its capacity as lessor of Cold Lake, Kearl and Syncrude oil sands leases, is entitled to a royalty on production. Royalties are subject to the oil sands royalty regulations which are based upon a sliding scale determined largely by the price of crude oil.

Total Upstream capital and exploration expenditures were $416 million in 2017. Investments were primarily related to sustaining activity in support of oil sands and unconventional assets.

### Delivery commitments

The company has no material commitments to provide a fixed and determinable quantity of oil or gas under existing contracts and agreements.

### Oil and gas properties, wells, operations and acreage

#### Production wells

The company’s production of liquids, bitumen and natural gas is derived from wells located exclusively in Canada. The total number of wells capable of production, in which the company had interests at December 31, 2017 and December 31, 2016, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

| wells | Year ended December 31, 2017 Crude Oil Gross (a) | Net (b) | Natural gas Gross (a) | Net (b) | Year ended December 31, 2016 Crude Oil Gross (a) | Net (b) | Natural gas Gross (a) | Net (b) |
| --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | ---: |
| Total (c) | **4,603** | **4,494** | **3,460** | **1,160** | 4,752 | 4,647 | 3,546 | 1,188 |

(a) Gross wells are wells in which the company owns a working interest.

(b) Net wells are the sum of the fractional working interest owned by the company in gross wells, rounded to the nearest whole number.

(c) Multiple completion wells are permanently equipped to produce separately from two or more distinctly different geological formations. At year-end 2017, the company had an interest in 17 gross wells with multiple completions (2016 - 16 gross wells).

#### Land holdings

At December 31, 2017 and December 31, 2016, the company held the following oil and gas rights, and bitumen and synthetic oil leases, all of which are located in Canada, specifically in the western provinces, in the Canada lands and in the Atlantic offshore.

| thousands of acres Western provinces (a): |  | Developed 2017 | 2016 | Undeveloped 2017 | 2016 | Total 2017 | 2016 |
| --- | --- | ---: | ---: | ---: | ---: | ---: | ---: |
| Liquids and gas | - gross (b) | **1,492** | 1,464 | **825** | 876 | **2,317** | 2,340 |
|  | - net (c) | **718** | 703 | **455** | 482 | **1,173** | 1,185 |
| Bitumen | - gross (b) | **197** | 197 | **674** | 674 | **871** | 871 |
|  | - net (c) | **182** | 182 | **319** | 319 | **501** | 501 |
| Synthetic oil | - gross (b) | **118** | 118 | **136** | 136 | **254** | 254 |
|  | - net (c) | **29** | 29 | **34** | 34 | **63** | 63 |
| Canada lands (d): |  |  |  |  |  |  |  |
| Liquids and gas | - gross (b) | **4** | 4 | **1,831** | 1,831 | **1,835** | 1,835 |
|  | - net (c) | **2** | 2 | **498** | 498 | **500** | 500 |
| Atlantic offshore: |  |  |  |  |  |  |  |
| Liquids and gas | - gross (b) | **65** | 65 | **288** | 288 | **353** | 353 |
|  | - net (c) | **6** | 6 | **46** | 46 | **52** | 52 |
| Total (e): | - gross (b) | **1,876** | 1,848 | **3,754** | 3,805 | **5,630** | 5,653 |
|  | - net (c) | **937** | 922 | **1,352** | 1,379 | **2,289** | 2,301 |

(a) Western provinces include British Columbia, Alberta and Saskatchewan.

(b) Gross acres include the interests of others.

(c) Net acres exclude the interests of others.

(d) Canada lands include the Arctic Islands, Beaufort Sea / Mackenzie Delta, and other Northwest Territories, Nunavut and Yukon regions.

(e) Certain land holdings are subject to modification under agreements whereby others may earn interests in the company’s holdings by performing certain exploratory work (farm-out) and whereby the company may earn interests in others’ holdings by performing certain exploratory work (farm-in).

#### Western provinces

The company’s bitumen leases include about 194,000 net acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company also has about 80,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company has interests in other bitumen oil sands leases in the Athabasca areas totalling about 193,000 net acres, which include about 62,000 net acres of oil sands leases in the Clyden area, about 34,000 net acres of oil sands leases in the Aspen area and about 30,000 net acres of oil sands leases in the Corner area. These 193,000 net acres are suitable for in-situ recovery techniques.

The company’s share of Syncrude joint venture leases covering about 63,000 net acres accounts for the entire synthetic oil acreage.

Oil sands leases have an exploration period of 15 years and are continued beyond that point by meeting the minimum level of evaluation, by payment of escalating rentals, or by production. The majority of the acreage in Cold Lake, Kearl and Syncrude is continued by production.

The company holds interests in an additional 1,173,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas.

Crude oil and natural gas leases and licences from the western provinces have exploration periods ranging from two to 15 years and are continued beyond that point by proven production capability.

#### Canada lands

Land holdings in Canada lands primarily include exploration licence (EL) acreage in the Beaufort Sea of about 252,000 net acres and significant discovery licence (SDL) acreage in the Mackenzie Delta and Beaufort Sea areas of about 183,000 net acres.

Exploration licences on Canada lands and Atlantic offshore have a finite term. If a significant discovery is made, a SDL may be granted that holds the acreage under the SDL indefinitely, subject to certain conditions.

The company’s net acreage in Canada lands is either continued by production or held through ELs and SDLs.

#### Atlantic offshore

The Atlantic offshore acreage is continued by production or held by SDLs.

### Downstream

### Supply

The company supplements its own production of crude oil, condensate and petroleum products with substantial purchases from a number of other sources at negotiated market prices. Purchases are made under both spot and term contracts from domestic and foreign sources, including ExxonMobil.

### Transportation

Imperial currently transports the company’s crude oil production and third party crude oil required to supply refineries by contracted pipelines, common carrier pipelines and rail. To mitigate uncertainty associated with the timing of industry pipeline projects and pipeline capacity constraints, the company has developed rail infrastructure. The Edmonton rail terminal commenced operation in 2015 and has total capacity to ship up to 210,000 barrels per day of crude oil.

### Refining

The company owns and operates three refineries, which process predominantly Canadian crude oil. In 2017, Imperial decided to discontinue manufacturing base stocks, associated waxes and finished lubricants at its Strathcona Refinery lube complex and lube oil blend plant. Continued operations are planned at the refinery lube complex until the end of February 2018 and at the blend plant until mid-2018. In addition to crude oil, the company purchases finished products to supplement its refinery production.

In 2017, capital expenditures of about $139 million were made at the company’s refineries. Capital expenditures focused mainly on refinery projects to improve reliability, feedstock flexibility, energy efficiency and environmental performance.

The approximate average daily volumes of refinery throughput during the three years ended December 31, 2017, and the daily rated capacities of the refineries as at December 31, 2017, were as follows.

| thousands of barrels per day | Refinery throughput (a) Year ended December 31 2017 | 2016 | 2015 | Rated capacities (b) at December 31 2017 |
| --- | ---: | ---: | ---: | ---: |
| Strathcona, Alberta | **185** | 168 | 181 | **191** |
| Sarnia, Ontario | **103** | 108 | 103 | **119** |
| Nanticoke, Ontario | **95** | 86 | 102 | **113** |
| Total | **383** | 362 | 386 | **423** |

(a) Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units.

(b) Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery atmospheric distillation units, the products to be obtained and the refinery process, adjusted to include an estimated allowance for normal maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities due to changes in refinery operation and the type of crude oil available for processing.

Refinery throughput averaged 383,000 barrels per day in 2017, up from 362,000 barrels per day in 2016. Capacity utilization increased to 91 percent from 86 percent in 2016, reflecting reduced turnaround maintenance activity.

Refinery throughput averaged 362,000 barrels per day in 2016, compared to 386,000 barrels per day in 2015. Capacity utilization decreased to 86 percent from 92 percent in 2015, reflecting the more significant scope of turnaround maintenance activity in 2016.

### Distribution

The company maintains a nationwide distribution system, to handle bulk and packaged petroleum products moving from refineries to market by pipeline, tanker, rail and road transport. The company owns and operates natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of one crude oil and two products pipeline companies.

### Marketing

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

Imperial supplies petroleum products to the motoring public through Esso and Mobil-branded retail sites and independent marketers. On average during the year, there were more than 1,800 retail sites operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate retail sites in alignment with Esso and Mobil brand standards. The Mobil fuels brand was launched in Canada in 2017 with the announcement of plans to convert more than 200 existing unbranded third party retail sites. Completion of this Mobil conversion is anticipated in 2018.

Imperial sells petroleum products to large industrial and transportation customers, independent marketers, resellers, as well as other refiners. The company serves agriculture, residential heating and commercial markets through branded resellers. In 2017, as part of Imperial’s truck transport business transition to a branded wholesaler model, the company announced plans to convert over 70 commercial third party sites to the Esso brand.

The approximate daily volumes of net petroleum products (excluding purchases / sales contracts with the same counterparty) sold during the three years ended December 31, 2017, are set out in the following table.

| thousands of barrels per day | 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Gasolines | **257** | 261 | 247 |
| Heating, diesel and jet fuels | **177** | 170 | 170 |
| Heavy fuel oils (a) | **18** | 16 | 16 |
| Lube oils and other products | **40** | 37 | 45 |
| Net petroleum product sales (a) | **492** | 484 | 478 |

(a) In 2017, carbon black product sales are reported under Net petroleum product sales – Heavy fuel oils; in 2016 and 2015, they were reported under Total petrochemical sales – Polymers and basic chemicals.

Total Downstream capital expenditures were $200 million in 2017.

### Chemical

The company’s Chemical operations manufacture and market benzene, aromatic and aliphatic solvents, plasticizer intermediates and polyethylene resin. Its petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the company’s petroleum refinery.

The company’s total sales volumes of petrochemicals during the three years ended December 31, 2017, were as follows.

| thousands of tonnes | 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Total sales of petrochemicals (a) | **774** | 908 | 945 |

(a) In 2017, carbon black product sales are reported under Net petroleum product sales – Heavy fuel oils; in 2016 and 2015, they were reported under Total petrochemical sales – Polymers and basic chemicals.

Lower sales volumes in 2017 were primarily due to the reclassification of carbon black product sales.

Total Chemical capital expenditures were $17 million in 2017.

### Research

The approximate total gross research expenditures, before credits, during the three years ended December 31, 2017, were as follows.

| millions of Canadian dollars | 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Gross research expenditures, before credits | **154** | 195 | 195 |

Research expenditures are mainly spent on developing technologies to improve bitumen recovery, reduce costs and reduce the environmental impact of upstream operations, including technologies to reduce greenhouse gas (GHG) emissions intensity, supporting environmental and process improvements in the refineries, as well as accessing ExxonMobil’s research worldwide.

The company has scientific research agreements with affiliates of ExxonMobil, which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licensing of patents, and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties.

### Environmental protection

The company regards protecting the environment in connection with its various operations as a priority. The company works in cooperation with government agencies, industry associations and communities to address existing, and to anticipate potential, environmental protection issues. In the past five years, the company has made capital and operating expenditures of about $5.7 billion on environmental protection and facilities. In 2017, the company’s environmental capital and operating expenditures totalled approximately $0.6 billion, which was spent primarily on activities to protect the air, land and water, including remediation projects. Capital and operating expenditures relating to environmental protection are expected to be about $0.6 billion in 2018.

### Human resources

| career employees (a) | 2017 | 2016 | 2015 |
| --- | ---: | ---: | ---: |
| Total | **5,400** | 5,600 | 5,700 |

(a) Rounded. Career employees are defined as active executive, management, professional, technical, administrative and wage employees who work full time or part time for the company and are covered by the company’s benefit plans.

About 7 percent of the company’s employees are members of unions.

### Competition

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

### Government regulation

### Petroleum and natural gas rights

Most of the company’s petroleum and natural gas rights were acquired from governments, either federal or provincial. These rights, in the form of leases or licences, are generally acquired for cash or work commitments. A lease or licence entitles the holder to explore for petroleum and / or natural gas on the leased lands for a specified period.

In western provinces, the lease holder can produce the petroleum or natural gas discovered on the leased lands and retains the rights based on continued production. Oil sands leases are retained by meeting the minimum level of evaluation, payment of rentals, or by production.

The holder of a licence relating to Canada lands and the Atlantic offshore can apply for a SDL if a discovery is made. If granted, the SDL holds the lands indefinitely subject to certain conditions. The holder may then apply for a production licence in order to produce petroleum or natural gas from the licenced land.

### Project approval

Approvals and licences from relevant provincial or federal governmental or regulatory bodies are required for the company to carry out, or make modifications to, its oil and gas activities. The project approval process for major projects can involve, among other things, environmental assessments (including relevant mitigation measures), stakeholder and Indigenous consultation and input regarding project concerns, and public hearings. Approval may be subject to various conditions and commitments arising through these processes.

### Crude oil

#### Production

The maximum allowable gross production of crude oil from wells in Canada is subject to limitations by various regulatory authorities on the basis of engineering and conservation principles.

#### Exports

Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require the prior approval of the National Energy Board (NEB) and the Government of Canada.

### Natural gas

#### Production

The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves and did not have a significant impact on Imperial’s 2017 gas production rates.

#### Exports

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

Exports of natural gas from Canada require approval by the NEB and the Government of Canada. The Government of Canada allows the export of natural gas by NEB order without volume limitation for terms not exceeding 24 months.

### Royalties

The Government of Canada and the provinces in which the company produces crude oil and natural gas, impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights.

Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed on crude oil, natural gas and natural gas liquids vary depending on a number of parameters, including well production volumes, selling prices and recovery methods. For information with respect to royalties for Cold Lake, Syncrude and Kearl, see “Upstream” section under Item 1.

### Investment Canada Act

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

The Act also requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s cultural heritage or national identity. The Government of Canada is also authorized to take any measures that it considers advisable to protect national security, including the outright prohibition of a foreign investment in Canada. By virtue of the majority stock ownership of the company by ExxonMobil, the company is considered to be an entity which is not controlled by Canadians.

### Competition Act

The Competition Bureau ensures that Canadian businesses and consumers prosper in a competitive and innovative marketplace. The Competition Bureau is responsible for the administration and enforcement of the Competition Act (the Act). A merger transaction, whether or not notifiable, is subject to examination by the Commissioner of the Competition Bureau to determine whether the merger will have, or is likely to have, the effect of preventing or lessening substantially competition in a definable market. The assessment of the competitive effects of a merger is made with reference to the factors identified under the Act.

An Advance Ruling Certificate (ARC) may be issued by the Commissioner to a party or parties to a proposed merger transaction who want to be assured that the transaction will not give rise to proceedings under section 92 of the Act. Section 102 of the Act provides that an ARC may be issued when the Commissioner is satisfied that there would not be sufficient grounds on which to apply to the Competition Tribunal for an order against a proposed merger. The issuance of an ARC is discretionary. An ARC cannot be issued for a transaction that has been completed, nor does an ARC ensure approval of the transaction by any agency other than the Competition Bureau.

### The company online

The company’s website **www.imperialoil.ca** contains a variety of corporate and investor information which is available free of charge, including the company’s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports, as well as required interactive data filings. These reports are made available as soon as reasonably practicable after they are filed or furnished to the SEC.

The public may read and copy any materials the company files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC’s website, www.sec.gov, contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC.

## Risk factors

As filed, 16,350 characters.

Imperial’s financial and operating results are subject to a variety of risks inherent in oil, gas and petrochemical businesses. Many of these risk factors are not within Imperial’s control and could adversely affect Imperial’s business, financial and operating results, or financial position. These risk factors include:

### Volatility of commodity prices

The company’s operations and earnings may be significantly affected by changes in oil, natural gas and petrochemical prices, and by changes in margins on refined products and petrochemicals. Crude oil, natural gas, petrochemical and product prices and margins depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity. Commodity prices have been volatile, and the company expects that volatility to continue. Any material decline in crude oil prices could have a material adverse effect on Imperial’s Upstream operations, financial position, proved reserves and the amount spent to develop reserves.

Demand related factors which could impact Imperial’s results include economic conditions, where periods of low or negative economic growth will typically have an adverse impact on results; technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for energy associated with heating and cooling; increased competitiveness of alternative energy sources; new product quality regulations; and changes in technology or consumer preferences that affect the market for petroleum products, such as technological advances in energy storage that make wind and solar more competitive for power generation or increased consumer demand for alternative fueled or electric vehicles.

Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity relative to demand tend to reduce margins on affected products. World oil, gas and petrochemical supply levels can also be affected by factors that reduce available supplies, such as adherence by member countries to Organization of the Petroleum Exporting Countries (OPEC) production quotas and the occurrence of wars, hostile actions, natural disasters, disruptions in competitors’ operations, or unexpected pipeline or rail constraints that may disrupt supplies. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.

A significant portion of the company’s production is bitumen, which is blended with diluent to create a marketable heavy crude oil. The market price for western Canadian heavy crude oil is typically lower than light and medium grades of oil principally due to the higher transportation and refining costs. Heavy crude oil may also be subject to limits on transportation capacity to markets to a larger extent than light crude oil. Future crude price differentials are uncertain and increases in the heavy crude oil discounts could have a material adverse effect on the company’s business. Increases to diluent prices, relative to heavy crude oil prices, could also have an adverse effect on the company’s business.

### Government and political factors

Imperial’s results can be adversely impacted by political or regulatory developments affecting operations. Changes in government policy or regulations, third party opposition to company or infrastructure projects, and duration of regulatory reviews could impact Imperial’s existing operations and planned projects. For example, increases in taxes or government royalty rates (including retroactive claims), changes in trade policies and agreements, changes in environmental regulations or other laws that increase the cost of compliance or reduce or delay available business opportunities, increasing and expanding stakeholder consultation (including Indigenous stakeholders) and adoption of regulations mandating efficiency standards, the use of alternative fuels or uncompetitive fuel components could affect the company’s operations.

### Environmental risks

All phases of the Upstream, Downstream and Chemical businesses are subject to environmental regulation pursuant to a variety of Canadian federal, provincial, territorial and municipal laws and regulations, as well as international conventions (collectively, “environmental legislation”).

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Environmental legislation also requires that wells, facility sites and other properties associated with the company’s operations be operated, maintained, monitored, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the cessation of operations, imposition of fines and penalties and liability for clean-up costs and damages.

The costs of complying with environmental legislation in the future could have a material adverse effect on the company’s financial condition or results of operations. The company anticipates that changes in environmental legislation may require, among other things, reductions in emissions from its operations to the air and water and may result in increased capital expenditures. Changes in environmental legislation (including, but not limited to, application of regulations related to air, water, land and biodiversity) may increase the cost of compliance or reduce or delay available business opportunities. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on the company’s financial condition or results of operations.

There are operational risks inherent in oil and gas exploration and production activities, as well as the potential to incur substantial financial liabilities, if those risks are not effectively managed. The ability to insure such risks is limited by the capacity of the applicable insurance markets, which may not be sufficient to cover the likely cost of a major adverse operating event. Accordingly, the company’s primary focus is on prevention, including through its rigorous operations integrity management system. The company’s future results will depend on the continued effectiveness of these efforts.

### Climate change and greenhouse gas restrictions

Due to concern over the risks of climate change, a number of provinces and the Government of Canada have adopted, or are considering the adoption of, regulatory frameworks to reduce GHG emissions. These include adoption of carbon emissions pricing, cap and trade regimes, carbon taxes, emissions limits, increased efficiency standards, low carbon fuel standards and incentives or mandates for renewable energy. These requirements could make Imperial’s products more expensive, reduce or delay available business opportunities, reduce demand for hydrocarbons, and shift hydrocarbon demand toward lower GHG emission energy sources. Current and pending GHG regulations or policies may also increase compliance and abatement costs, lengthen project evaluation and implementation times, and affect operations. Increased costs may not be recoverable in the market place and could reduce the global competitiveness of the company’s crude oil, natural gas and refined products.

### Currency

Prices for commodities produced by the company are commonly benchmarked in U.S. dollars. The majority of Imperial’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the value of the Canadian dollar strengthens, the company’s reported earnings will be negatively affected. The company does not currently make use of derivative instruments to offset exposures associated with foreign currency.

### Other business risks

Imperial is reliant on a number of key chemicals, catalysts and third party service providers, including input and output commodity transportation (pipelines, rail, trucking, marine) and utilities providing services, including electricity and water, to various company operations. The lack of availability and capacity, and proximity of pipeline facilities and railcars could negatively impact Imperial’s ability to produce at capacity levels. Transportation disruptions could adversely affect the company’s price realizations, refining operations and sales volumes, as well as potentially limit the ability to deliver production to market. A third party utilities outage could have an adverse impact on the company’s operations and ability to produce.

### Management effectiveness

In addition to external economic and political factors, Imperial’s future business results also depend on the company’s ability to manage successfully those factors that are at least in part within its control. The extent to which Imperial manages these factors will impact its performance relative to competition. For projects in which the company is not the operator, Imperial depends on the management effectiveness of one or more co-venturers whom the company does not control.

### Project management

The company’s results are affected by its ability to develop and operate projects and facilities as planned. The company’s results will, therefore, be affected by events or conditions that affect the advancement, operation, cost or results of such projects or facilities. These risks include the company’s ability to obtain the necessary environmental and other regulatory approvals; changes in regulations; changes in resources and operating costs including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; and the occurrence of unforeseen technical difficulties.

### Operational efficiency

An important component of Imperial’s competitive performance, especially given the commodity based nature of Imperial’s business, is the ability to operate efficiently, including the company’s ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technology improvements, cost control, productivity enhancements and regular reappraisal of the company’s asset portfolio. The company’s operations and results also depend on key personnel and subject matter expertise, the recruitment, development and retention of high caliber employees, and the availability of skilled labour.

### Research and development

Imperial relies upon the research and development organizations of the company and ExxonMobil, with whom the company conducts shared research. To maintain the company’s competitive position, especially in light of the technological nature of Imperial’s business and the need for continuous efficiency improvement, research and development organizations must be successful and able to adapt to a changing market and policy environment, including developing technologies to help reduce GHG emissions.

### Safety, business controls and environmental risk management

The scope and nature of the company’s operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, pipeline ruptures and crude oil spills. Imperial’s operations are also subject to the additional hazards of pollution, releases of toxic gas and environmental hazards and risks, such as severe weather, and geological events. The company’s results depend on management’s ability to minimize these inherent risks, to effectively control business activities and to minimize the potential for human error. Imperial applies rigorous management systems, including a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. The company also maintains a disciplined framework of internal controls and applies a controls management system for monitoring compliance with this framework. Substantial liabilities and other adverse impacts could result if the company’s management systems and controls do not function as intended.

### Cybersecurity

Imperial is regularly subject to attempted cybersecurity disruptions from a variety of threat actors. If systems for protecting against cybersecurity disruptions prove to be insufficient, the company, customers, employees or third parties could be adversely affected. Such cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost or stolen; result in employee, customer or third party information being compromised; or otherwise disrupt business operations. Imperial could incur significant costs to remedy the effects of such a cybersecurity disruption, as well as in connection with resulting regulatory actions and litigation.

### Preparedness

The company’s operations may be disrupted by severe weather events, natural disasters, human error, and similar events. Imperial’s ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of its rigorous disaster preparedness and response planning, as well as business continuity planning.

### Reputation

Imperial’s reputation is an important corporate asset. An operating incident, significant cybersecurity disruption or other adverse events, such as those described in Item 1A, may have a negative impact on Imperial’s reputation, which in turn could make it more difficult for Imperial to compete successfully for new opportunities, obtain necessary regulatory approvals, or could reduce consumer demand for the company’s branded products.

### Reserves

The company’s future production and cash flows from bitumen, synthetic oil, liquids and natural gas reserves are highly dependent upon the company’s success in exploiting its current reserve base. To maintain production and cash flows, the company must continue to replace produced reserves as they are depleted, which can be accomplished through exploration discovery of new resources, appraisal and investments in developing discovered resources, or acquisition of reserves. To the extent cash flows from operations are insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the company’s ability to make the necessary capital investments to maintain and expand oil and natural gas reserves will be adversely impacted. In addition, the company may be unable to find and develop or acquire additional reserves to replace oil and natural gas production at acceptable costs.

Estimates of economically recoverable oil and natural gas reserves and future net cash flows involve many uncertainties, including factors beyond the company’s control. Key factors with uncertainty include: geological and engineering estimates; the assumed effects of regulation or changes to regulation by government agencies including royalty frameworks; future commodity prices; and operating costs. Actual production, revenues, taxes, development costs, abandonment costs, and operating expenditures with respect to reserves will likely vary from such estimates, and such variances could be material.

## Management's discussion and analysis

As filed, 193 characters.

Reference is made to the section entitled “Management’s discussion and analysis of financial condition and results of operations” in the “Financial section”, starting on page 36 of this report.

## Market risk

As filed, 383 characters.

Reference is made to the section entitled “Market risks and other uncertainties” in the “Financial section”, starting on page 49 of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.

## Controls and procedures

As filed, 1,327 characters.

As indicated in the certifications in Exhibit 31 of this report, the company’s principal executive officer and principal financial officer have evaluated the company’s disclosure controls and procedures as of December 31, 2017. Based on that evaluation, these officers have concluded that the company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

Reference is made to page 56 of this report for “Management’s report on internal control over financial reporting” and page 57 for the “Report of independent registered public accounting firm” on the company’s internal control over financial reporting as of December 31, 2017.

There has not been any change in the company’s internal control over financial reporting during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting.

Filed Mar 1, 2018.
Source: SEC EDGAR, the filing index for accession 0001193125-18-064765. Last ingested by Listed: Nov 5, 2026, 13:58 ET. No prices; not investment advice.