2019FYIMPERIAL OIL LTD0000049938--12-31false0.500.502021-11-302020-12-31CAABCAAmounts to related parties included in purchases of crude oil and products, (note 17). 3,305 4,092 2,687Amounts to related parties included in production and manufacturing, and selling and general expenses, (note 17). 628 566 544Amounts from related parties included in revenues, (note 17).8,569 6,383 4,110Accounts receivable, less estimated doubtful accounts included net amounts receivable from related parties of $1,007 million (2018 – $666 million), (note 17).Investments and long-term receivables included amounts from related parties of $296 million (2018 – $146 million), (note 17).Long-term debt included amounts to related parties of $4,447 million (2018 – $4,447 million), (note 17).Other long-term obligations included amounts to related parties of $0 million (2018 – $15 million), (note 17).Notes and loans payable included amounts to related parties of $111 million (2018 – $75 million), (note 17).Number of common shares authorized and outstanding were 1,100 million and 744 million, respectively (2018 – 1,100 million and 783 million, respectively), (note 11). The impact of carbon emission programs are included in Additions to property, plant and equipment, and All other items - net.Included contribution to registered pension plans. (211) (203) (212)Cash is composed of cash in bank and cash equivalents at cost. Cash equivalents are all highly liquid securities with maturity of three months or less when purchased.The Upstream segment in 2017 includes non-cash impairment charges of $396 million, before tax, associated with the Horn River development and $379 million, before tax, associated with the Mackenzie gas project. The impairment charges are recognized in the lines “Exploration” and “Depreciation and depletion” on the Consolidated statement of income, and the “Accumulated depreciation and depletion” line of the Consolidated balance sheet.As part of the implementation of Accounting Standard Update, Compensation – Retirement Benefits (Topic 715), beginning January 1, 2018, Corporate and other includes all non-service pension and postretirement benefit expense. Prior to 2018, the majority of these costs were allocated to the operating segments.Includes export sales to the United States of $7,190 million (2018 - $6,661 million, 2017 - $4,392 million). Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.In 2018, the Downstream segment included a non-cash impairment charge of $46 million, before tax, associated with the Government of Ontario’s revocation of its cap and trade legislation.Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant and equipment, additions to finance leases, additional investments and acquisitions. CAPEX excludes the purchase of carbon emission credits.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 November 2, 2017 the British Columbia government enacted a 1 percent increase in the provincial tax rate from 11 percent to 12 percent.2017 disposals were primarily associated with the sale of surplus property in Ontario.Other decreases in 2017 and 2018 were primarily related to prior year adjustments and re-assessments.Total recorded employee retirement benefits obligations also included $58 million in current liabilities (2018 – $55 million).Total asset retirement obligations and other environmental liabilities also included $124 million in current liabilities (2018 – $118 million).For 2019, the asset retirement obligations were discounted at 6 percent (2018 - 6 percent).Borrowed under an existing agreement with an affiliated company of ExxonMobil that provides for a long-term, variable-rate, Canadian dollar loan from ExxonMobil to the company of up to $7.75 billion at interest equivalent to Canadian market rates. The agreement is effective until June 30, 2025, cancelable if ExxonMobil provides at least 370 days advance written notice.This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 5).Includes related party interest with ExxonMobil.2017 included a gain of $174 million ($151 million after tax) from the sale of surplus property in Ontario.The amounts shown for funded pension plans with accumulated benefit obligations in excess of plan assets represent the company’s proportionate share of a joint venture sponsored pension plan. For the company sponsored funded plan, plan assets exceeded the accumulated benefit obligation in both 2019 and 2018.The company amortizes the net balance of actuarial loss (gain) as a component of net periodic benefit cost over the average remaining service period of active plan participants.The company amortizes prior service cost on a straight-line basis.In 2019, the company removed $570 million from Total assets and corresponding liabilities in the Downstream segment associated with the Government of Ontario’s revocation of its cap and trade legislation.Effective January 1, 2019, Imperial adopted the Financial Accounting Standards Board’s standard, Leases (Topic 842), as amended. As at December 31, 2019, Total assets include operating lease right of use assets of $260 million. An election was made not to restate prior periods. See note 14 for additional details.Benefit payments for funded plans only.Fair value of assets less projected benefit obligation shown above.Effective January 1, 2019, Imperial adopted the Financial Accounting Standards Board’s standard, Leases (Topic 842), as amended. The standard requires all leases to be recorded on the balance sheet as a right of use asset and liability. The long-term lease liability for operating leases is included in Other long-term obligations (see note 14).Finance leases are primarily associated with transportation facilities and services agreements. The average imputed rate was 7.5 percent in 2019 (2018 – 7.1 percent). Total finance lease obligations also include $18 million in current liabilities (2018 - $27 million). Principal payments on finance leases of approximately $13 million on average per year are due in each of the next four years after December 31, 2020.Amounts to related parties included in financing, (note 17). 98 89 60The weighted average interest rate on short-term borrowings in 2019 was 1.8 percent (2018 – 1.5 percent, 2017– 0.9 percent). Average effective rate on the long-term borrowings with ExxonMobil in 2019 was 2.2 percent (2018 – 2.0 percent, 2017 – 1.3 percent).Segment results in 2019 include a largely non-cash favourable impact of $662 million associated with the Alberta corporate income tax rate decrease, with the largest impact in the Upstream segment.Includes property, plant and equipment under construction of $2,149 million (2018 - $1,553 million, 2017 - $1,047 million). 0000049938 2019-01-01 2019-12-31 0000049938 2018-01-01 2018-12-31 0000049938 2017-01-01 2017-12-31 0000049938 2019-12-31 0000049938 2018-12-31 0000049938 2019-06-27 0000049938 2017-12-31 0000049938 2019-06-13 0000049938 2019-06-27 2019-06-27 0000049938 2019-01-01 0000049938 2020-02-12 0000049938 2019-06-30 0000049938 2016-12-31 0000049938 us-gaap:PensionPlansDefinedBenefitMember 2019-12-31 0000049938 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2019-12-31 0000049938 imo:FundedPensionPlansMember 2019-12-31 0000049938 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2017-12-31 0000049938 imo:DownstreamMember 2017-12-31 0000049938 imo:ChemicalMember 2017-12-31 0000049938 srt:ConsolidationEliminationsMember 2017-12-31 0000049938 us-gaap:RestrictedStockUnitsRSUMember imo:RestrictedStockUnitPlanOneMember 2019-01-01 2019-12-31 0000049938 imo:SyncrudeJointVentureMember 2019-01-01 2019-12-31 0000049938 imo:KearlJointVentureMember 2019-01-01 2019-12-31 0000049938 us-gaap:PensionPlansDefinedBenefitMember 2019-01-01 2019-12-31 0000049938 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2019-01-01 2019-12-31 0000049938 imo:UpstreamMember 2019-01-01 2019-12-31 0000049938 imo:AccumulatedDefinedBenefitPlansAdjustmentBeforeTaxMember 2019-01-01 2019-12-31 0000049938 imo:ExxonMobilCorporationMember 2019-01-01 2019-12-31 0000049938 srt:ConsolidationEliminationsMember 2019-01-01 2019-12-31 0000049938 imo:DownstreamMember 2019-01-01 2019-12-31 0000049938 imo:ChemicalMember 2019-01-01 2019-12-31 0000049938 srt:MaximumMember imo:MiningHeavyEquipmentMember 2019-01-01 2019-12-31 0000049938 srt:MaximumMember imo:OreProcessingPlantAssetsMember 2019-01-01 2019-12-31 0000049938 imo:RefineryAndChemicalProcessMember 2019-01-01 2019-12-31 0000049938 us-gaap:CommonStockMember 2019-01-01 2019-12-31 0000049938 imo:RestrictedStockUnitPlanTwoMember us-gaap:RestrictedStockUnitsRSUMember 2019-01-01 2019-12-31 0000049938 imo:RestrictedStockUnitPlanThreeMember us-gaap:RestrictedStockUnitsRSUMember 2019-01-01 2019-12-31 0000049938 us-gaap:RestrictedStockUnitsRSUMember 2019-01-01 2019-12-31 0000049938 us-gaap:DeferredCompensationShareBasedPaymentsMember 2019-01-01 2019-12-31 0000049938 country:US 2019-01-01 2019-12-31 0000049938 us-gaap:CorporateAndOtherMember 2019-01-01 2019-12-31 0000049938 us-gaap:RetainedEarningsMember 2019-01-01 2019-12-31 0000049938 imo:PostRetirementBenefitMember 2019-01-01 2019-12-31 0000049938 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2019-01-01 2019-12-31 0000049938 imo:OperatingLeasesMember 2019-01-01 2019-12-31 0000049938 imo:FinanceLeasesMember 2019-01-01 2019-12-31 0000049938 imo:AdoptionOfLeasesTopic842Member 2019-01-01 2019-12-31 0000049938 us-gaap:AccountsPayableAndAccruedLiabilitiesMember 2019-01-01 2019-12-31 0000049938 us-gaap:AccountingStandardsUpdate201602Member 2019-01-01 2019-12-31 0000049938 imo:AlbertaMember imo:UpstreamMember 2019-01-01 2019-12-31 0000049938 us-gaap:PensionPlansDefinedBenefitMember 2018-01-01 2018-12-31 0000049938 us-gaap:OtherPostretirementBenefitPlansDefinedBenefitMember 2018-01-01 2018-12-31 0000049938 imo:UpstreamMember 2018-01-01 2018-12-31 0000049938 imo:AccumulatedDefinedBenefitPlansAdjustmentBeforeTaxMember 2018-01-01 2018-12-31 0000049938 imo:ExxonMobilCorporationMember 2018-01-01 2018-12-31 0000049938 srt:ConsolidationEliminationsMember 2018-01-01 2018-12-31 0000049938 imo:DownstreamMember 2018-01-01 2018-12-31 0000049938 imo:ChemicalMember 2018-01-01 2018-12-31 0000049938 us-gaap:CommonStockMember 2018-01-01 2018-12-31 0000049938 country:US 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2017-01-01 2017-12-31 0000049938 imo:MackenzieGasProjectMember 2017-01-01 2017-12-31 0000049938 imo:SurplusPropertyMember 2017-01-01 2017-12-31 0000049938 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2017-01-01 2017-12-31 0000049938 imo:ExxonMobilCorporationMember us-gaap:RevolvingCreditFacilityMember 2019-11-30 0000049938 imo:LongTermLineOfCreditMember 2019-11-30 0000049938 imo:LongTermLineOfCreditMember 2019-11-01 2019-11-30 0000049938 imo:ShortTermLineOfCreditMember 2019-12-01 2019-12-31 0000049938 imo:BritishColumbiaGovernmentMember 2017-11-02 2017-11-02 0000049938 srt:MinimumMember imo:BritishColumbiaGovernmentMember 2017-11-02 2017-11-02 0000049938 srt:MaximumMember imo:BritishColumbiaGovernmentMember 2017-11-02 2017-11-02 0000049938 imo:AlbertaGovernmentMember 2019-06-28 2019-06-28 0000049938 srt:MaximumMember imo:AlbertaGovernmentMember 2019-06-28 2019-06-28 0000049938 srt:MinimumMember imo:AlbertaGovernmentMember 2019-06-28 2019-06-28 0000049938 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2016-12-31 0000049938 us-gaap:RetainedEarningsMember 2016-12-31 0000049938 us-gaap:AccumulatedOtherComprehensiveIncomeMember 2016-12-31 iso4217:CAD xbrli:shares xbrli:pure imo:Project iso4217:CAD xbrli:shares utr:bbl
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
☑
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
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☐
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number
0-12014
(Exact name of registrant as specified in its charter)
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(State or other jurisdiction of
incorporation or organization)
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505 QUARRY PARK BOULEVARD S.E., CALGARY, AB, CANADA
(Address of principal executive offices)
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(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
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Title of each class
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Trading symbol
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Name of each exchange on
which registered
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None
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None
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Securities registered pursuant to Section 12(g) of the Act:
Common Shares (without par value)
Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act).
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934. Yes...... No
✓
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past
90 days. Yes
✓
No......
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation
S-T
during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes
✓
No......
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a
non-accelerated
filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule
12b-2
of the Securities Exchange Act of 1934.
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Large accelerated filer
✓
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Smaller reporting company......
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Accelerated filer......
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Emerging growth company......
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Non-accelerated
filer......
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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act……
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12
b-2
of the Securities Exchange Act of 1934). Yes..... No ✓
As of the last business day of the 2019 second fiscal quarter, the aggregate market value of the voting stock held by
non-affiliates
of the registrant was Canadian $8,408,104,050 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date.
The number of common shares outstanding, as of February 12, 2020, was 739,223,338.
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4
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4
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5
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5
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6
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7
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9
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11
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11
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12
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14
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14
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14
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14
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14
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15
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15
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16
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16
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16
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17
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18
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19
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25
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25
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25
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25
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26
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26
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27
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27
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27
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28
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28
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28
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28
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29
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29
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30
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31
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32
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33
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34
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All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated. Note that numbers may not add due to rounding.
The following table sets forth (i) the rates of exchange for the Canadian dollar, expressed in United States (U.S.) dollars, in effect at the end of each of the periods indicated, (ii) the average of exchange rates in effect on the last day of each month during such periods, and (iii) the high and low exchange rates during such periods, in each case based on the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York.
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2019
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2018
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2017
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2016
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2015
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0.7715
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0.7329
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0.7989
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0.7448
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0.7226
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Average rate during period
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0.7558
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0.7693
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0.7714
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0.7559
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0.7748
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0.7715
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0.8143
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0.8243
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0.7972
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0.8529
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0.7358
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0.7326
|
|
|
|
0.7275
|
|
|
|
0.6853
|
|
|
|
0.7148
|
|
On February 12, 2020, the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $0.7551 U.S. = $1.00 Canadian.
Forward-looking statements
Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans are forward-looking statements. Forward-looking statements can be identified by words such as believe, anticipate, intend, propose, plan, goal, seek, project, predict, target, estimate, expect, strategy, outlook, schedule, future, continue, likely, may, should, will and similar references to future periods. Forward-looking statements in this report include, but are not limited to, references to estimates, development, timing and recovery of reserves; the improvement of recovery through experimental operations; the development drilling program at Cold Lake; the timing, cost, efficiency and production of the Aspen project and expansion project at Cold Lake; the continued evaluation of other oil sands leases and unconventional assets; future activities with respect to Beaufort Sea licences; Kearl production outlook and growth activities, including the impact from supplemental crushing facilities; the ability of rail infrastructure to mitigate pipeline capacity constraints; anticipated capital, exploration and operating expenditures, including with respect to environmental protection; anticipated share purchases; being well positioned to participate in future investments and reduce commodity price risk; the company’s long-term business outlook including demand, supply and energy mix; segment growth, competitive strategies and benefits from an integrated business model; potential impacts from carbon policy and climate related regulations; Cold Lake production outlook and reservoir performance at Nabiye; the factors affecting a return to planned activity levels at Aspen; the impact on Chemical margins from continued industry capacity additions outpacing demand growth; the benefits to the Chemical business from integration with the Sarnia refinery and relationship with ExxonMobil; earnings sensitivities; risks associated with use of derivative instruments; capital structure and financial strength as a competitive advantage, for risk mitigation and meeting funding requirements; the impact of any pending litigation, accounting standards and unrecognized tax benefits; standardized measures of discounted future cash flows; and the Strathcona refinery expansion and cogeneration projects.
Forward-looking statements are based on the company’s current expectations, estimates, projections and assumptions at the time the statements are made. Actual future financial and operating results, including expectations and assumptions concerning demand growth and energy source, supply and mix; commodity prices, foreign exchange rates and general market conditions; production rates, growth and mix; project plans, timing, costs, technical evaluations and capacities and the company’s ability to effectively execute on these plans and operate its assets; production life, resource recoveries and reservoir performance; cost savings; the adoption and impact of new facilities or technologies, including on capital efficiency, production and reductions to greenhouse gas emissions intensity; product sales; applicable laws and government policies, including taxation, climate change and production curtailment; industry capacity additions; financing sources and capital structure; and capital and environmental expenditures could differ materially depending on a number of factors. These factors include global, regional or local changes in supply and demand for oil, natural gas, and petroleum and petrochemical products and resulting price, differential and margin impacts; general economic conditions; transportation for accessing markets; political or regulatory events, including changes in law or government policy, applicable royalty rates, tax laws and production curtailment; the receipt, in a timely manner, of regulatory and third-party approvals; third party opposition to operations, projects and infrastructure; environmental risks inherent in oil and gas exploration and production activities; environmental regulation, including climate change and greenhouse gas regulation and changes to such regulation; currency exchange rates; availability and allocation of capital; availability and performance of third party service providers; unanticipated technical or operational difficulties; management effectiveness; commercial negotiations; project management and schedules and timely completion of projects; reservoir analysis and performance; unexpected technological developments; the results of research programs and new technologies, and ability to bring new technologies to commercial scale on a cost-competitive basis; operational hazards and risks; cybersecurity incidents; disaster response preparedness; the ability to develop or acquire additional reserves; and other factors discussed in Item 1A risk factors and Item 7 management’s discussion and analysis of financial condition and results of operations of this annual report on Form
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 Oil Limited’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them. Imperial Oil Limited undertakes no obligation to update any forward-looking statements contained herein, except as required by applicable law.
The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.
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, and reference to ExxonMobil includes Exxon Mobil Corporation and its affiliates, as appropriate.
The company is one of Canada’s largest integrated oil companies. It is active in all phases of the petroleum industry in Canada, including the exploration for, and production and sale of, crude oil and natural gas. In Canada, it is a major producer of crude oil, the largest petroleum refiner and a leading marketer of petroleum products. It is also a major producer of petrochemicals.
The company’s operations are conducted in three main segments: Upstream, Downstream and Chemical. Upstream operations include the exploration for, and production of, crude oil, natural gas, synthetic oil and bitumen. Downstream operations consist of the transportation and refining of crude oil, blending of refined products and the distribution and marketing of those products. Chemical operations consist of the manufacturing and marketing of various petrochemicals.
Financial information about segments and geographic areas for the company is contained in the “Financial section” of this report under note 3 to the consolidated financial statements: “Business segments”.
Summary of oil and gas reserves at
year-end
The table below summarizes the net proved reserves for the company, as at December 31, 2019, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the “Financial section”, starting on page 36 of this report.
All of the company’s reported reserves are located in Canada. The company has reported proved reserves based on the average of the
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, 2019 that would cause a significant change in the estimated proved reserves as of that date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids
(a)
|
|
|
Natural gas
|
|
|
Synthetic oil
|
|
|
Bitumen
|
|
|
|
|
|
|
|
millions of
barrels
|
|
|
|
|
|
millions of
barrels
|
|
|
millions of
barrels
|
|
|
millions of
barrels
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
22
|
|
|
|
291
|
|
|
|
415
|
|
|
|
2,609
|
|
|
|
3,095
|
|
|
|
|
|
19
|
|
|
|
290
|
|
|
|
-
|
|
|
|
330
|
|
|
|
397
|
|
|
|
|
|
41
|
|
|
|
581
|
|
|
|
415
|
|
|
|
2,939
|
|
|
|
3,492
|
|
|
(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, changes in the amount and timing of capital investments, royalty framework and significant changes in long-term oil and gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the company’s capital spending and also impact its partners’ capacity to fund their share of joint projects. The company’s operating decisions and its outlook for future production volumes are not impacted by proved reserves as disclosed under the U.S. Securities and Exchange Commission (SEC) definition.
Technologies used in establishing proved reserves estimates
Imperial’s proved reserves in 2019 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.
Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including seismic data, calibrated with available well control information. The tools used to interpret the data included proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis packages.
In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.
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 rules and regulations, review of annual changes in reserves estimates and the reporting of Imperial’s proved reserves. This group also maintains the official reserves estimates for Imperial’s proved reserves. In addition, this group provides training to personnel involved in the reserve estimation and reporting processes within Imperial.
The reserves management group maintains a central database containing the company’s official reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations, commercial and market assessments, analysis of well and field performance, and long standing approval guidelines. No changes may be made to reserves estimates in the central database, including the addition of any new initial reserves estimates or subsequent revisions, unless those changes have been thoroughly reviewed and evaluated by duly authorized personnel within the base operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and endorsement by the operating organization and the reserves management group, culminating in reviews with and approval by senior management and the company’s board of directors.
The internal qualified reserves evaluator is a professional geoscientist registered in Alberta, Canada and has 21 years of petroleum industry experience, including 15 years of reserves related experience. The position provides leadership to the internal reserves management group and is responsible for filing a reserves report with the Canadian securities regulatory authorities. The company’s internal reserves evaluation staff consists of 42 persons with an average of 12 years of relevant technical experience in evaluating reserves, of whom 21 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 21 persons with an average of 11 years of relevant experience in evaluating and managing the evaluation of reserves.
Proved undeveloped reserves
As at December 31, 2019, approximately 11 percent of the company’s proved reserves were proved undeveloped reflecting volumes of 397 million
oil-equivalent
barrels. Proved undeveloped reserves are associated with Cold Lake and the Montney and Duvernay unconventional assets. This compared to 404 million
oil-equivalent
barrels of proved undeveloped reserves reported at the end of 2018. The decrease of 7 million
oil-equivalent
barrels of proved undeveloped reserves includes a decrease of 33 million
oil-equivalent
barrels at the Montney and Duvernay unconventional assets, partially offset by an increase of 26 million oil-equivalent barrels at Cold Lake. Conversion of proved undeveloped reserves into proved developed was 24 million
oil-equivalent
barrels in 2019, associated with Cold Lake and the Montney and Duvernay unconventional assets.
Proved undeveloped reserves that have remained undeveloped for five years or more represent about 83 percent (330 million
oil-equivalent
barrels) of proved undeveloped reserves and are associated with ongoing development programs at the Montney and Duvernay unconventional assets and at Cold Lake. 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 assets. 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 approvals, government policies, consumer preferences, changes in the amount and timing of capital investments, royalty framework and significant changes in long-term oil and gas price levels.
One of the company’s requirements to report resources as proved reserves is that management has made significant funding commitments towards the development of the reserves. The company has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. The company made investments of about $328 million during the year to progress the development of proved undeveloped reserves at the Montney and Duvernay unconventional assets and at Cold Lake. These investments represented about 26 percent of the $1,248 million in total reported Upstream capital and exploration expenditures.
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 40 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, 2019 was as follows. All reported production volumes were from Canada.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands of barrels per day (a)
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- gross
(b)
|
|
|
145
|
|
|
|
146
|
|
|
|
126
|
|
|
|
|
- net
(c)
|
|
|
140
|
|
|
|
135
|
|
|
|
123
|
|
|
|
|
- gross
(b)
|
|
|
140
|
|
|
|
147
|
|
|
|
162
|
|
|
|
|
- net
(c)
|
|
|
114
|
|
|
|
120
|
|
|
|
132
|
|
|
|
|
- gross
(b)
|
|
|
285
|
|
|
|
293
|
|
|
|
288
|
|
|
|
|
- net
(c)
|
|
|
254
|
|
|
|
255
|
|
|
|
255
|
|
|
|
|
- gross
(b)
|
|
|
73
|
|
|
|
62
|
|
|
|
62
|
|
|
|
|
- net
(c)
|
|
|
65
|
|
|
|
60
|
|
|
|
57
|
|
|
|
|
- gross
(b)
|
|
|
16
|
|
|
|
6
|
|
|
|
5
|
|
|
|
|
- net
(c)
|
|
|
14
|
|
|
|
7
|
|
|
|
4
|
|
|
|
|
- gross
(b)
|
|
|
374
|
|
|
|
361
|
|
|
|
355
|
|
|
|
|
- net
(c)
|
|
|
333
|
|
|
|
322
|
|
|
|
316
|
|
|
(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.
|
|
(e)
|
Liquids include crude oil, condensate and NGLs.
|
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, 2019 are set forth below. All reported production volumes were from Canada. All gas volumes in this report are calculated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 40 of this report for a narrative discussion on the material changes.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of cubic feet per day (a)
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
|
|
|
|
145
|
|
|
|
129
|
|
|
|
120
|
|
Net production
(c) (d) (e)
|
|
|
144
|
|
|
|
126
|
|
|
|
114
|
|
Net production available for sale
(f)
|
|
|
108
|
|
|
|
94
|
|
|
|
80
|
|
|
(a)
|
Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.
|
|
(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)
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Total production
oil-equivalent
basis:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
398
|
|
|
|
383
|
|
|
|
375
|
|
|
|
|
|
357
|
|
|
|
343
|
|
|
|
335
|
|
|
(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.
|
The company’s average unit sales price and average unit production costs by product type for the three years ended December 31, 2019 were as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian dollars per barrel
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
50.02
|
|
|
|
37.56
|
|
|
|
39.13
|
|
|
|
|
|
74.47
|
|
|
|
70.66
|
|
|
|
67.58
|
|
|
|
|
|
42.91
|
|
|
|
40.20
|
|
|
|
38.49
|
|
Canadian dollars per thousand cubic feet
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2.05
|
|
|
|
2.43
|
|
|
|
2.58
|
|
|
(a)
|
Liquids include crude oil, condensate and NGLs.
|
In 2019, Imperial’s average Canadian dollar realizations for bitumen increased, supported primarily by an increase in Western Canada Select and lower diluent costs. The company’s average Canadian dollar realizations for synthetic crude increased relative to West Texas Intermediate, primarily due to the narrowing of the western Canadian light crude differential.
In 2018, Imperial’s average Canadian dollar realizations for bitumen declined generally in line with Western Canada Select, adjusted for changes in the exchange rate and transportation costs. The company’s average Canadian dollar realizations for synthetic crude increased, however the widening of the western Canadian light crude differential relative to West Texas Intermediate during the fourth quarter of 2018 negatively impacted synthetic crude realizations.
Average unit production costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian dollars per barrel
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
31.53
|
|
|
|
29.39
|
|
|
|
26.81
|
|
|
|
|
|
54.44
|
|
|
|
60.34
|
|
|
|
58.96
|
|
Total
oil-equivalent
basis
(a)
|
|
|
34.82
|
|
|
|
35.28
|
|
|
|
32.96
|
|
|
(a)
|
Includes liquids, bitumen, synthetic oil and natural gas.
|
In 2019, bitumen unit production costs were higher, primarily driven by Kearl costs associated with improving reliability and mine performance, and increased mine material movement.
In 2019, synthetic oil unit production costs were lower, primarily driven by higher production due to the absence of the site-wide power disruption at Syncrude in 2018 and lower maintenance costs.
In 2018, bitumen unit production costs were higher, primarily driven by Kearl costs associated with improving reliability, partly offset by the impact of higher production.
In 2018, synthetic oil unit production costs were higher, primarily driven by higher maintenance costs, including impacts of the June 20 site-wide power disruption at Syncrude.
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.
The following table sets forth the net exploratory and development wells that were drilled or participated in by the company during the three years ended December 31, 2019.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
wells
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Net productive exploratory
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
-
|
|
Net productive development
|
|
|
28
|
|
|
|
19
|
|
|
|
5
|
|
|
|
|
|
-
|
|
|
|
1
|
|
|
|
-
|
|
|
|
|
|
28
|
|
|
|
20
|
|
|
|
5
|
|
In 2019, wells drilled to add productive capacity include 14 development wells at Cold Lake and 14 wells associated with the Montney and Duvernay unconventional assets.
In 2018, wells drilled to add productive capacity include 10 development wells at Cold Lake and 9 wells associated with the Montney and Duvernay unconventional assets.
In 2017, wells were drilled to add productive capacity, associated primarily with the Montney and Duvernay unconventional assets.
At December 31, 2019, the company was participating in the drilling of the following exploratory and development wells within the Montney and Duvernay unconventional assets. All wells were located in Canada.
|
|
|
|
|
|
|
|
|
|
|
|
|
2019
|
|
|
wells
|
|
Gross
|
|
|
Net
|
|
|
|
|
|
12
|
|
|
|
6
|
|
Exploratory and development activities regarding oil and gas resources
To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically. Additional wells were drilled on existing phases in 2019. In 2020, a development drilling program is planned within the approved development area to add productive capacity.
The company also conducts experimental pilot operations to improve recovery of bitumen from wells by means of new drilling, production or recovery techniques.
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.
In October 2018, regulatory approval for the Aspen
in-situ
project was received from the Alberta Energy Regulator. The first phase of the project was approved by the company’s board and appropriated for $2.6 billion. Construction began late in the fourth quarter of 2018. In March 2019, the company slowed the pace of development given market uncertainty stemming from the Government of Alberta’s temporary mandatory production curtailment regulations and other industry competitiveness challenges. Aspen’s project pace will be continuously evaluated, but it remains an important development project for Imperial.
In March 2016, Imperial filed a regulatory application for an expansion project at Cold Lake to develop the Grand Rapids interval using
SA-SAGD
technology. The project is proposed to produce 50,000 barrels per day, before royalties. In August 2018, regulatory approval for the expansion project at Cold Lake was received from the Alberta Energy Regulator. The company continues to progress the project.
Work progresses on technical evaluations to support potential Clarke Creek, Corner, Clyden and Chard
in-situ
development regulatory applications.
The company also has interests in other oil sands leases in the Athabasca region of northern Alberta. Evaluation wells completed on these leased areas established the presence of bitumen. The company continues to evaluate these leases to determine their potential for future development.
The company is continuing to evaluate, develop and produce resources in its Montney and Duvernay unconventional assets in the western provinces.
In 2007, the company acquired a 50 percent interest in an exploration licence in the Beaufort Sea. As part of the evaluation, a
3-D
seismic survey was conducted in 2008 and the company has since carried out data collection programs to support environmental studies and safe exploration drilling operations.
In 2010, the company executed an agreement to cross-convey interests with another company to acquire a 25 percent interest in an additional Beaufort Sea exploration licence. As a result of that agreement, the company operates both licences and its interest in the original licence was reduced to 25 percent.
In 2013, the company and its joint venture partners filed a project description, initiating the formal regulatory review of the project.
In 2016, the Federal Government of Canada declared Arctic waters off limits to new offshore oil and gas licences for five years subject to review at the end of that period. Existing licences were not impacted.
In June 2019, the Federal Government approved selective changes to the
Canada Petroleum Resources Act
to provide an indefinite prohibition and freeze of the existing licences through the completion of the Beaufort Sea Regional Environmental Assessment
(BR-SEA)
review. The Federal Government continues to consult with stakeholders as part of the
BR-SEA
to address regional social, environmental, economic and spill response impacts of natural resource development in the Arctic. The company continues to hold the licences while actively focusing on community engagement and participation in the
BR-SEA
process.
Exploratory and development activities regarding oil and gas resources extracted by mining methods
The company continues to evaluate other undeveloped, mineable oil sands acreage in the Athabasca region.
Review of principal ongoing activities
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. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation by pipeline and rail.
During 2019, the company’s share of Kearl’s net bitumen production was about 140,000 barrels per day and gross production was about 145,000 barrels per day.
Kearl’s supplemental crushing facilities started operations in late 2019, with
ramp-up
of all units through early 2020. These facilities are expected to further improve reliability, reduce planned downtime, lower unit costs and enable the asset to achieve 240,000 barrels per day of total gross production in 2020 (Imperial’s gross share would be about 170,000 barrels per day).
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.
During 2019, net bitumen production at Cold Lake was about 114,000 barrels per day and gross production was about 140,000 barrels per day.
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 2019, the company’s share of Syncrude’s net production of synthetic crude oil was about 65,000 barrels per day and gross production was about 73,000 barrels per day.
The Province of Alberta, in its capacity as lessor of Kearl, Cold Lake, and Syncrude oil sands leases, is entitled to a royalty on production. Royalties are subject to the oil sands royalty regulations which are based upon a sliding scale determined largely by the price of crude oil.
The company has no material commitments to provide a fixed and determinable quantity of oil or gas under existing contracts and agreements.
Oil and gas properties, wells, operations and acreage
The company’s production of liquids, bitumen and natural gas is derived from wells located exclusively in Canada. The total number of wells capable of production, in which the company had interests at December 31, 2019 and December 31, 2018, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2019
|
|
|
Year ended December 31, 2018
|
|
|
|
|
Crude oil
|
|
|
Natural gas
|
|
|
Crude oil
|
|
|
Natural gas
|
|
|
wells
|
|
Gross
(a)
|
|
|
Net
(b)
|
|
|
Gross
(a)
|
|
|
Net
(b)
|
|
|
Gross
(a)
|
|
|
Net
(b)
|
|
|
Gross
(a)
|
|
|
Net
(b)
|
|
|
|
|
|
4,646
|
|
|
|
4,603
|
|
|
|
2,801
|
|
|
|
911
|
|
|
|
4,760
|
|
|
|
4,655
|
|
|
|
3,459
|
|
|
|
1,164
|
|
|
(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
2019, the company had an interest in 12 gross wells with multiple completions (2018 - 16 gross wells).
|
The total number of wells decreased in 2019 primarily due to the divestment of mature conventional properties.
At December 31, 2019 and December 31, 2018, the company held the following oil and gas rights, and bitumen and synthetic oil leases, all of which are located in Canada, specifically in the western provinces, in the Canada lands and in the Atlantic offshore.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Developed
|
|
|
Undeveloped
|
|
|
Total
|
|
|
thousands of acres
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
|
2018
|
|
|
2019
|
|
|
2018
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- gross
(b)
|
|
|
1,056
|
|
|
|
1,497
|
|
|
|
771
|
|
|
|
807
|
|
|
|
1,827
|
|
|
|
2,304
|
|
|
|
|
- net
(c)
|
|
|
516
|
|
|
|
721
|
|
|
|
432
|
|
|
|
446
|
|
|
|
948
|
|
|
|
1,167
|
|
|
|
|
- gross
(b)
|
|
|
197
|
|
|
|
197
|
|
|
|
601
|
|
|
|
595
|
|
|
|
798
|
|
|
|
792
|
|
|
|
|
- net
(c)
|
|
|
182
|
|
|
|
182
|
|
|
|
269
|
|
|
|
292
|
|
|
|
451
|
|
|
|
474
|
|
|
|
|
- gross
(b)
|
|
|
118
|
|
|
|
118
|
|
|
|
136
|
|
|
|
136
|
|
|
|
254
|
|
|
|
254
|
|
|
|
|
- net
(c)
|
|
|
29
|
|
|
|
29
|
|
|
|
34
|
|
|
|
34
|
|
|
|
63
|
|
|
|
63
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- gross
(b)
|
|
|
4
|
|
|
|
4
|
|
|
|
1,831
|
|
|
|
1,831
|
|
|
|
1,835
|
|
|
|
1,835
|
|
|
|
|
- net
(c)
|
|
|
2
|
|
|
|
2
|
|
|
|
498
|
|
|
|
498
|
|
|
|
500
|
|
|
|
500
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
- gross
(b)
|
|
|
65
|
|
|
|
65
|
|
|
|
267
|
|
|
|
286
|
|
|
|
332
|
|
|
|
351
|
|
|
|
|
- net
(c)
|
|
|
6
|
|
|
|
6
|
|
|
|
36
|
|
|
|
45
|
|
|
|
42
|
|
|
|
51
|
|
|
|
|
- gross
(b)
|
|
|
1,440
|
|
|
|
1,881
|
|
|
|
3,606
|
|
|
|
3,655
|
|
|
|
5,046
|
|
|
|
5,536
|
|
|
|
|
- net
(c)
|
|
|
735
|
|
|
|
940
|
|
|
|
1,269
|
|
|
|
1,315
|
|
|
|
2,004
|
|
|
|
2,255
|
|
|
(a)
|
Western provinces include British Columbia and Alberta.
|
|
(b)
|
Gross acres include the interests of others.
|
|
(c)
|
Net acres exclude the interests of others.
|
|
(d)
|
Canada lands include the Arctic Islands, Beaufort Sea / Mackenzie Delta, and other Northwest Territories and Yukon 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).
|
The company’s bitumen leases include about 171,000 net acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company also has about 69,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company has interests in other bitumen oil sands leases in the Athabasca areas totalling about 177,000 net acres, which include about 62,000 net acres of oil sands leases in the Clyden area, about 34,000 net acres of oil sands leases in the Aspen area, about 30,000 net acres of oil sands leases in the Corner area and about 18,000 net acres in the Chard area. In August 2019, Imperial acquired a 50 percent ownership in the Clarke Creek area, totalling about 29,000 net acres of additional oil sands leases. The 177,000 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 948,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas. In 2019, the company divested mature conventional properties totalling 214,000 net acres.
Crude oil and natural gas leases and licences from the western provinces have exploration periods ranging from two to 15 years and are continued beyond that point by proven production capability.
Land holdings in Canada lands primarily include exploration licence (EL) acreage in the Beaufort Sea of about 252,000 net acres and significant discovery licence (SDL) acreage in the Mackenzie Delta and Beaufort Sea areas of about 183,000 net acres.
Exploration licences on Canada lands have a finite term. If a significant discovery is made, a SDL may be granted that holds the acreage under the SDL indefinitely, subject to certain conditions.
The company’s net acreage in Canada lands is either continued by production or held through ELs and SDLs.
Exploration licences on Atlantic offshore have a finite term. The Atlantic offshore acreage is continued by production or held by SDLs.
The company supplements its own production of crude oil, condensate and petroleum products with substantial purchases from a number of other sources at negotiated market prices. Purchases are made under both spot and term contracts from domestic and foreign sources, including ExxonMobil.
Imperial currently transports the company’s crude oil production and third party crude oil required to supply refineries by contracted pipelines, common carrier pipelines and rail. To mitigate uncertainty associated with the timing of industry pipeline projects and pipeline capacity constraints, the company has developed rail infrastructure. The Edmonton rail terminal has total capacity to ship up to 210,000 barrels per day of crude oil. In 2019, shipments through the Edmonton rail terminal averaged 51,000 barrels per day.
The company owns and operates three refineries, which process predominantly Canadian crude oil. The company purchases finished products to supplement its refinery production.
The approximate average daily volumes of refinery throughput during the three years ended December 31, 2019, and the daily rated capacities of the refineries as at December 31, 2019, were as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Refinery throughput
(a)
|
|
|
Rated capacities
(b)
|
|
|
|
|
Year ended December 31
|
|
|
at December 31
|
|
|
thousands of barrels per day
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
2019
|
|
|
|
|
|
183
|
|
|
|
173
|
|
|
|
185
|
|
|
|
191
|
|
|
|
|
|
86
|
|
|
|
109
|
|
|
|
103
|
|
|
|
119
|
|
|
|
|
|
84
|
|
|
|
110
|
|
|
|
95
|
|
|
|
113
|
|
|
|
|
|
353
|
|
|
|
392
|
|
|
|
383
|
|
|
|
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 353,000 barrels per day in 2019, compared to 392,000 barrels per day in 2018. Capacity utilization was 83 percent, compared to 93 percent in 2018. Reduced throughput was mainly due to higher planned turnaround activities and impacts from the Sarnia fractionation tower incident which occurred in April 2019.
Refinery throughput averaged 392,000 barrels per day in 2018, up from 383,000 barrels per day in 2017. Capacity utilization increased to 93 percent from 91 percent in 2017.
The company maintains a nationwide distribution system, to move petroleum products to market by pipeline, tanker, rail and road transport. The company owns and operates fuel terminals across the country, as well as natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of one crude oil and two products pipeline companies.
The company markets petroleum products throughout Canada under well-known brand names, most notably Esso and Mobil, to all types of customers.
Imperial supplies petroleum products to the motoring public through Esso and Mobil-branded sites and independent marketers. At the end of 2019, there were about 2,300 sites operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate sites in alignment with Esso and Mobil brand standards.
Imperial also sells petroleum products, including fuel, asphalt and lubricants, to large industrial and transportation customers, independent marketers, resellers, as well as other refiners. The company serves agriculture, residential heating and commercial markets through branded fuel and lubricant resellers.
The approximate daily volumes of net petroleum products (excluding purchases / sales contracts with the same counterparty) sold during the three years ended December 31, 2019, are set out in the following table.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands of barrels per day
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
249
|
|
|
|
255
|
|
|
|
257
|
|
Heating, diesel and jet fuels
|
|
|
167
|
|
|
|
183
|
|
|
|
177
|
|
|
|
|
|
21
|
|
|
|
26
|
|
|
|
18
|
|
Lube oils and other products
|
|
|
38
|
|
|
|
40
|
|
|
|
40
|
|
Net petroleum product sales
|
|
|
475
|
|
|
|
504
|
|
|
|
492
|
|
In 2019, lower sales volumes were mainly due to lower refinery throughput.
In 2018, sales growth continued to be driven by optimization across the full downstream value chain, and the expansion of Imperial’s logistic capabilities.
The company’s Chemical operations manufacture and market benzene, aromatic and aliphatic solvents, plasticizer intermediates and polyethylene resin. Its petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the company’s petroleum refinery.
The company’s total petrochemical sales volumes during the three years ended December 31, 2019, were as follows.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands of tonnes
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
Total petrochemical sales
|
|
|
732
|
|
|
|
807
|
|
|
|
774
|
|
In 2019, sales volumes decreased primarily due to lower aromatics and intermediates sales.
In 2018, sales volumes were higher primarily due to higher production in polymers and basic chemicals, driven by stronger reliability.
The company regards protecting the environment in connection with its various operations as a priority. The company works in cooperation with government agencies, industry associations and communities to address existing, and to anticipate potential, environmental protection issues. In the past five years, the company has made capital and operating expenditures of about $3.9 billion on environmental protection and facilities. In 2019, the company’s environmental capital and operating expenditures totalled approximately $0.8 billion, which was spent primarily on activities to protect the air, land and water, including remediation projects. Capital and operating expenditures relating to environmental protection are expected to be about $1.0 billion in 2020.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
career employees (a)
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
6,000
|
|
|
|
5,700
|
|
|
|
5,400
|
|
|
(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 6 percent of the company’s employees are members of unions.
The Canadian energy and petrochemical industries are highly competitive. Competition exists in the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities and the refining, distribution and marketing of petroleum products and chemicals. The energy and petrochemical industries also compete with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers.
Petroleum, natural gas and oil sands rights
Most of the company’s petroleum, natural gas and oil sands rights were acquired from governments, either federal or provincial. These rights, in the form of leases or licences, are generally acquired for cash or work commitments. A lease or licence entitles the holder to explore for petroleum, natural gas and/or oil sands on the leased lands for a specified period.
In western provinces, the lease holder can produce the petroleum or natural gas discovered on the leased lands and retains the rights based on continued production. Oil sands leases are retained by meeting the minimum level of evaluation, payment of rentals, or by production.
The holder of a licence relating to Canada lands and the Atlantic offshore can apply for a SDL if a discovery is made. If granted, the SDL holds the lands indefinitely subject to certain conditions. The holder may then apply for a production licence in order to produce petroleum or natural gas from the licenced land.
Approvals and licences from relevant provincial or federal
governmental or regulatory bodies are required for the company to carry out, or make modifications to, its oil and gas activities. The project approval process for major projects can involve, among other things, environmental assessments (including relevant mitigation measures), stakeholder and Indigenous consultation and input regarding project concerns, and public hearings. Approval may be subject to various conditions and commitments arising through these processes.
In 2019, the Canadian government implemented a new environmental assessment framework in Canada under the
Impact Assessment Act
, which may impact the manner in which large energy projects are approved. Changes from the previous environmental assessment legislation include broader consideration for social, health, and gender-based impacts, the impact on Canada’s climate change commitments, reliance on strategic and regional assessments and adjusted regulatory review timelines.
The maximum allowable gross production of crude oil from wells in Canada is subject to limitations by various regulatory authorities on the basis of engineering and conservation principles.
Additionally, in December 2018, the Government of Alberta introduced temporary mandatory production curtailment regulations, which took effect on January 1, 2019. These regulations impose production limits on large producers in Alberta. Mandatory production curtailments decreased as 2019 progressed, but continue to be imposed on larger producers. The duration of these regulations is uncertain.
Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require the prior approval of the Canada Energy Regulator (CER) and the Government of Canada. Export contracts of less than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require an order from the CER.
The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves and did not have a significant impact on Imperial’s 2019 gas production rates.
The Government of Canada has the authority to regulate the export price for natural gas and has a gas export pricing policy, which accommodates export prices for natural gas negotiated between Canadian exporters and U.S. importers.
Exports of natural gas from Canada require approval by the CER and the Government of Canada. The Government of Canada allows the export of natural gas by CER order without volume limitation for terms not exceeding 24 months.
The Government of Canada and the provinces in which the company produces crude oil and natural gas, impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights.
Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed on crude oil, natural gas and natural gas liquids vary depending on a number of parameters, including well production volumes, selling prices and recovery methods. For information with respect to royalties for Kearl, Cold Lake and Syncrude, see “Upstream” section entitled “Present activities” under Item 1 on page 11.
The
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.
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’s website
www.imperialoil.ca
contains a variety of corporate and investor information which is available free of charge, including the company’s annual report on Form
10-K,
quarterly reports on Form
10-Q
and current reports on Form
8-K
and amendments to these reports. These reports are made available as soon as reasonably practicable after they are filed or furnished to the SEC. The SEC’s website, www.sec.gov, contains reports, proxy and information statements, interactive data files, and other information regarding issuers that are submitted and posted electronically with the SEC.
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:
The oil, gas, fuels and petrochemical businesses are fundamentally commodity businesses. This means the company’s operations and earnings may be significantly affected by changes in oil, natural gas and petrochemical prices, and by changes in margins on refined products and petrochemicals. Crude oil, natural gas, petrochemical and petroleum product prices and margins depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity. Commodity prices have been volatile, and the company expects that volatility to continue. Any material decline in crude oil prices could have a material adverse effect on Imperial’s Upstream operations, financial position, proved reserves and the amount spent to develop reserves. On the other hand, a material increase in crude oil prices could have a material adverse effect on Imperial’s Downstream margins, depending on the market conditions for refined products.
The demand for energy and petrochemicals is generally linked closely with broad-based economic activities and levels of prosperity. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on the company’s results. Other factors that may affect the demand for crude oil, gas, fuels and petrochemicals, and therefore could impact Imperial’s results include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for our products, including lower demand for gasoline, impacting Downstream results in the winter; increased competitiveness of alternative energy sources; new product quality regulations; technological changes or consumer preferences that alter fuel choices, such as technological advances in energy storage that make wind and solar more competitive for power generation or increased consumer demand for alternative fueled or electric transportation; broad-based changes in personal income levels; and security or public health concerns.
Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tend to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity relative to demand tend to reduce margins on affected products. Crude oil, gas and petrochemical supply levels can also be affected by factors that reduce available supplies, such as adherence by member countries or others to Organization of the Petroleum Exporting Countries (OPEC) production quotas and the Government of Alberta curtailment regulations, the occurrence of wars, hostile actions, natural disasters, disruptions in competitors’ operations, or unexpected pipeline or rail constraints that may disrupt supplies. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.
The market price for western Canadian heavy crude oil is typically lower than light and medium grades of oil, principally due to the higher transportation and refining costs. Western Canadian crude oil may also be subject to limits on transportation capacity to markets. Future crude price differentials between western Canadian crude oil relative to prices in the U.S. Gulf Coast are uncertain and changes in the heavy or light crude oil differentials could have a material adverse effect on the company’s business. Increased differentials in 2018 also led the Government of Alberta to impose temporary mandatory production curtailment in 2019. Although mandatory production curtailment decreased throughout 2019, it continues to be imposed on larger producers and the duration of these regulations is uncertain. A significant portion of the company’s production is bitumen, which is blended with diluent for transportation and marketability of heavy crude oil. Increases to diluent prices, relative to heavy crude oil prices, could also have an adverse effect on the company’s business.
Government and political factors
Imperial’s results can be adversely impacted by political, legal or regulatory developments affecting operations and markets. Changes in government policy or regulations, changes in law or interpretation of settled law, third party opposition to company or infrastructure projects, and duration of regulatory reviews could impact Imperial’s existing operations and planned projects. Additionally, changes in environmental regulations, assessment processes or other laws and increasing and expanding stakeholder consultation (including Indigenous stakeholders), may increase the cost of compliance or reduce or delay available business opportunities and adversely impact the company’s results.
Other government and political factors that could adversely affect the company’s financial results include increases in taxes or government royalty rates (including retroactive claims) and changes in trade policies and agreements. Further, the adoption of regulations mandating efficiency standards, and the use of alternative fuels or uncompetitive fuel components could affect the company’s operations. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies. Governments and others are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources, and the success of these initiatives may decrease demand for the company’s products.
Governments may establish regulations with respect to the control of the company’s production, such as when increased price differentials in 2018 led the Government of Alberta to impose temporary mandatory production curtailment regulations effective 2019. Although mandatory production curtailment decreased throughout 2019, it continues to be imposed on larger producers. The duration of these regulations is uncertain, and could have an adverse effect on the company’s business. Government intervention in free markets may introduce unintended consequences such as market volatility and uncertainty, misallocation of resources, and erosion of investor confidence.
All phases of the Upstream, Downstream and Chemical businesses are subject to environmental regulation pursuant to a variety of Canadian federal, provincial, territorial and municipal laws and regulations, as well as international conventions (collectively, “environmental legislation”).
Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Changes to these requirements, such as the International Maritime Organization (IMO) 2020 global Sulphur limits for marine fuel oil, could adversely affect the company’s results by impacting commodity prices, increasing costs and reducing revenues.
Environmental legislation also requires that wells, facility sites and other properties associated with the company’s operations be operated, maintained, monitored, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. This includes the requirement for specific approvals for many areas of interaction with the environment, such as land use, air quality, water use, biodiversity protection and waste, including mine tailings management. The failure to operate as anticipated and adhere to conditions, the delay or denial of approvals and changes to conditions or regulations could impact the company’s ability to operate its projects and facilities and adversely affect the company’s results.
The implementation of, and compliance with, policies and regulations related to air, water and land, such as Alberta’s Lower Athabasca Regional Plan and Wetland Policy, could restrict development in current and future areas of operation. The company also depends on water obtained under licences for withdrawal, storage, reuse and discharge in both its Upstream and Downstream businesses, including future projects and expansions. Water use may be limited by regulatory requirements, seasonal fluctuations, competing demands, environmental sensitivities, increasingly stringent water management standards, and changes to conditions or availability of licences, which may restrict and adversely affect the company’s operations. Additionally, a number of air quality regulations and frameworks are being developed at the federal and provincial levels, and when implemented could impact existing and planned projects through increased capital and operating expenses including retrofits to existing equipment, and could adversely impact the company’s operations and financial results.
Federal and provincial legislation aimed at protecting sensitive, threatened or endangered wildlife, such as woodland caribou and species of migratory birds, may also increase restoration and offset costs and impact the company’s projects. If it is determined that such wildlife and their habitat are not sufficiently protected, governments or other parties may take actions to limit the pace or ability to develop in areas of Imperial’s current and future projects.
The company’s mining operations are subject to tailings management regulations that establish approval, monitoring, reporting and performance criteria for tailings ponds and management plans. Further, the absence or evolving nature of policies and regulations for the timing and closure of tailings ponds, including the approved technologies and methods for closure (such as the use of end pit lakes and water capped tailings), and dam safety directives, regulations, guides and abandonment requirements could have a material impact on conditions for approvals and ultimate mine closure costs. Additionally, successful management and closure requires the release of water to the environment, and although an Alberta water release policy and federal oil sands effluent regulations are being developed, the timing and impact of these regulations is uncertain and the absence of effective regulation could negatively impact the company’s operations and financial results.
In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. In 2019, the Government of Canada implemented a new environmental assessment framework under the
Impact Assessment Act
, which expands assessment considerations beyond the environment to include social, health, economic, and gender-based impacts and the impact on Canada’s climate change commitments. It also includes a reliance on strategic and regional assessments and adjusted regulatory review timelines. The impact of this legislation is not yet known, but it may impact the cost, manner, duration and ability to advance large energy projects.
Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the cessation of operations, imposition of fines and penalties and liability for
clean-up
costs and damages.
The costs of complying with environmental legislation in the future could have a material adverse effect on the company’s financial condition or results of operations. The company anticipates that changes in environmental legislation may require, among other things, reductions in emissions from its operations to the air and water and may result in increased capital expenditures. Changes in environmental legislation (including, but not limited to, application of regulations related to air, water, land, biodiversity and waste, including mine tailings) may increase the cost of compliance or reduce or delay available business opportunities. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on the company’s financial condition or results of operations.
There are operational risks inherent in oil and gas exploration and production activities, as well as the potential to incur substantial financial liabilities, if 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, are considering the adoption of, or have revised, regulatory frameworks to reduce greenhouse gas 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.
The Government of Canada has adopted the Paris Agreement on climate change, and set a goal to reduce greenhouse gas emissions economy-wide by 30 percent below 2005 levels by 2030. To implement these goals, the Government of Canada adopted the
Greenhouse Gas Pollution Pricing Act
(GGPPA), which sets a federal backstop carbon price Canada-wide through a carbon levy applied to fossil fuels ($20 per tonne starting in 2019 and increasing by $10 per tonne annually to $50 per tonne in 2022), and an output-based pricing system for large industrial emitters. Under the GGPPA, provinces are required to either adopt the GGPPA, or obtain equivalency by adopting a price-based system or cap and trade system.
The Government of Alberta has obtained federal equivalency for its Technology Innovation and Emissions Reduction Regulation (TIER) that came into effect in 2020 and applies to facilities with CO2 emissions in excess of 100,000 tonnes per year. TIER is designed to reduce emissions by putting a price on 10 percent of a facility’s emissions in 2020, increasing by 1 percent per year, with pricing for 2020 set at $30 per tonne. Further, the Alberta
Oil Sands Emissions Limit Act
sets a limit of 100 megatonnes of CO2 per year of emissions in the oil sands sector, but oil sands emissions remain below the limit and it is not yet possible to predict the impact of this act on future oil sands operations in Alberta. With respect to other provinces, with Ontario cancelling the cap and trade program in 2018, the company’s operations in Ontario are subject to the federal carbon levy and output based pricing system. British Columbia has carbon pricing in place for all emissions, with pricing currently at $40 per tonne and rising by $5 per tonne in April, 2020 and again in April, 2021. Although current regulations around carbon emissions pricing are not anticipated to have a material impact on the company’s operations in the near term, uncertainty regarding future regulations make it difficult to predict potential future impact on the company.
There are also various low carbon fuel standards being developed or applicable to the company. The Government of Canada is progressing draft regulations for the Clean Fuel Standard, which if implemented would require the reduction in carbon intensity of liquid fuels supplied in Canada starting in 2022 and gaseous and solid fuels starting in 2023. The standard is expected to build upon the existing federal renewable fuels regulations that require fuel producers and importers to have a specified amount of renewable fuel in gasoline and diesel. Similarly, British Columbia introduced a Low Carbon Fuel Standard in 2013, which increased to a 10 percent carbon intensity reduction requirement by 2020. The British Columbia government has announced a draft policy to reduce the carbon intensity of fuels by a further 20 percent by 2030. Compliance can be achieved by either blending renewable fuels with low carbon intensity or by purchasing credits. Changes to these standards could adversely impact the company’s operations and financial results.
The Government of Canada recently enacted the
Impact Assessment Act
, which links environmental assessment approvals to climate change-related goals, and has also discussed a goal of establishing legally-binding policies for being carbon-neutral by 2050.
International accords and underlying regional and national regulations covering climate change and greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. Such laws and policies could make Imperial’s products more expensive and less competitive, reduce or delay available business opportunities, reduce demand for hydrocarbons, and shift hydrocarbon demand toward lower greenhouse gas emission energy sources. Current and pending greenhouse gas regulations or policies may also increase compliance and abatement costs including taxes and levies, increase abandonment and reclamation obligations, lengthen project evaluation and implementation times, impact reserves evaluations and affect operations. Increased costs may not be recoverable in the market place and could reduce the global competitiveness of the company’s crude oil, natural gas and refined products. Concern over the risks of climate change may lead governments to make laws applicable to the energy industry progressively more stringent over time.
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.
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, including those caused by events unrelated to the company’s operations, 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.
The company also enters into contractual relationships with suppliers, partners and other counterparties to procure and sell goods and services, and the company’s operations, market position and financial condition may be adversely impacted if these counterparties do not fulfil their obligations. Imperial may also be adversely affected by the outcome of litigation resulting from its operations or by government enforcement proceedings alleging
non-compliance
with applicable laws or regulations. Litigation is subject to uncertainty and success is not guaranteed, and the company may incur significant expenses and devote significant resources in defending litigation.
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.
The nature of the company’s Upstream, Downstream and Chemical businesses depend on complex, long-term, and capital intensive projects that require a high degree of project management expertise to maximize efficiency. This includes development, engineering, construction, commissioning and ongoing operational activities and expertise. The company’s results are affected by its ability to develop and operate projects and facilities as planned and by events or conditions that affect the advancement, operation, cost or results of such projects or facilities. These risks include the company’s ability to obtain the necessary environmental and other regulatory approvals; changes in regulations; the ability to model and optimize reservoir performance; changes in resources and operating costs including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; and respond effectively to unforeseen technical difficulties that could delay project startup or cause unscheduled downtime.
An important component of Imperial’s competitive performance, especially given the commodity based nature of Imperial’s business, is the ability to operate efficiently, including the company’s ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technological improvements, cost control, productivity enhancements and regular reappraisal of the company’s asset portfolio. The company’s operations and results also depend on key personnel and subject matter expertise, the recruitment, development and retention of high caliber employees, and the availability of skilled labour.
Research and development and technical change
Imperial relies upon the research and development organizations of the company and ExxonMobil, with whom the company conducts shared research. Innovation and technology are important to maintain the company’s competitive position, especially in light of the technological nature of Imperial’s business and the need for continuous efficiency improvement. The company’s research and development organizations must be able to adapt to a changing market and policy environment, including developing technologies to help reduce greenhouse gas emissions intensity. To remain competitive, the company must also continuously adapt and capture the benefits of new technologies including growing the company’s capabilities to utilize digital data technologies to gain new business insights. There are risks associated with projects that rely on new technology, including that the results of implementing the new technology may differ from simulated, piloted or expected results. The failure to develop and adopt new technology may have an adverse impact on the company’s operations, ability to meet regulatory requirements and operational commitments and targets (including environmental sustainability and reduction of greenhouse gas emissions), and financial results.
Safety, business controls and environmental risk management
The scope and nature of the company’s operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, pipeline ruptures and crude oil spills. Imperial’s operations are also subject to the additional hazards of pollution, releases of toxic gas and environmental hazards and risks, such as severe weather, and geological events. The company’s results depend on management’s ability to minimize these inherent risks, to effectively control business activities and to minimize the potential for human error. Imperial applies rigorous management systems, including a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. The company also maintains a disciplined framework of internal controls and applies a controls management system for monitoring compliance with this framework. The company’s upstream and downstream operations may experience loss of production, slowdowns or shutdowns and increased costs due to the failure of interdependent systems, and substantial liabilities and other adverse impacts could result if the company’s management systems and controls do not function as intended.
Imperial is regularly subject to attempted cybersecurity disruptions from a variety of threat actors, including state-sponsored actors. Imperial’s defensive preparedness includes multi-layered technological capabilities for prevention and detection of cybersecurity disruptions;
non-technological
measures such as threat information sharing with governmental and industry groups; internal training and awareness campaigns including routine testing of employee awareness via mock threats; and an emphasis on resiliency including business response and recovery.
If the measures the company is taking to protect against cybersecurity disruptions prove to be insufficient, the company, as well as its customers, employees or third parties could be adversely affected. Cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost or stolen; result in employee, customer or third party information being compromised; or otherwise disrupt the company’s business operations. Imperial could incur significant costs to remedy the effects of a major cybersecurity disruption, in addition to costs in connection with resulting regulatory actions, litigation or reputational harm.
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.
Imperial’s reputation is an important corporate asset. An operating incident, significant cybersecurity disruption, change in consumer views concerning the company’s products, or other adverse events, such as those described in Item 1A, may have a negative impact on Imperial’s reputation, which in turn could make it more difficult for the company to compete successfully for new opportunities, obtain necessary regulatory approvals, or could reduce consumer demand for the company’s branded products. Imperial’s reputation may also be harmed by events which negatively affect the image of the industry as a whole, including public and investor perception of Alberta oil sands in relation to greenhouse gas emissions and environmental impact.
The company’s future production and cash flows from bitumen, synthetic oil, liquids and natural gas reserves are highly dependent upon the company’s success in exploiting its current reserves. To maintain production and cash flows, the company must continue to replace produced reserves as they are depleted, which can be accomplished through exploration discovery of new resources, appraisal and investments in developing discovered resources, or acquisition of reserves. To the extent cash flows from operations are insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the company’s ability to make the necessary capital investments to maintain and grow oil and natural gas reserves will be adversely impacted. In addition, the company may be unable to find and develop or acquire additional reserves to replace oil and natural gas production at acceptable costs.
Estimates of economically recoverable oil and natural gas reserves and future net cash flows involve many uncertainties, including factors beyond the company’s control. Key factors with uncertainty include: geological and engineering estimates, including that additional information obtained through seismic and drilling programs, reservoir analysis and production and operational history may result in revisions to reserves; the assumed effects of regulation or changes to regulation by government agencies, including royalty frameworks and environmental regulations (such as the regulation of greenhouse gas emissions, which could impose significant compliance costs on the company, require new technology, or impact the economic viability of certain projects); future commodity prices, where low commodity prices may affect reserves development; abandonment and reclamation costs, including reclamation and tailings requirements for mining operations; and operating costs. Actual production, revenues, taxes and royalties, development costs, abandonment and reclamation costs, and operating expenditures with respect to reserves will likely vary from such estimates, and such variances could be material.
|
|
Unresolved staff comments
|
None.
Reference is made to Item 1 above.
None.
Not applicable.
25
|
|
Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities
|
The company’s common shares are listed and trade on the Toronto Stock Exchange in Canada, and have unlisted trading privileges and trade on the NYSE American LLC in the United States. The symbol for the company’s common shares on these exchanges is IMO.
As of February 12, 2020 there were 10,221 holders of record of common shares of the company.
Information for security holders outside Canada
Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to a Canadian
non-resident
withholding tax of 15 percent, but may vary from one tax convention to another.
The withholding tax is reduced to 5 percent on dividends paid to a corporation resident in the U.S. that owns at least 10 percent of the voting shares of the company.
The company is a qualified foreign corporation for purposes of the reduced U.S. capital gains tax rates, which are applicable to dividends paid by U.S. domestic corporations and qualified foreign corporations.
There is no Canadian tax on gains from selling shares or debt instruments owned by
non-residents
not carrying on business in Canada, as long as the shareholder does not, in any given 60 month period, own 25 percent or more of the shares of the company.
Between October 1, 2019 and December 31, 2019, pursuant to the company’s restricted stock unit plan, 650 shares were issued to employees or former employees outside the U.S. in reliance on Regulation S under the Securities Act.
Securities authorized for issuance under equity compensation plans
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the section under the “Company executives and executive compensation”:
|
|
·
|
|
Entitled “Performance graph” within the “Compensation discussion and analysis” section on page 157 of this report; and
|
|
|
·
|
|
Entitled “Equity compensation plan information”, within the “Compensation discussion and analysis”, on page 163 of this report.
|
Issuer purchases of equity securities
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total number of
shares purchased
|
|
|
Average price paid
per share
(Canadian dollars)
|
|
|
Total number of
shares purchased
as part of publicly
announced plans
or programs
|
|
|
Maximum number
of shares that may
yet be purchased
under the plans or
programs
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(October 1 - October 31)
|
|
|
3,431,196
|
|
|
|
32.81
|
|
|
|
3,431,196
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(November 1 - November 30)
|
|
|
3,275,232
|
|
|
|
33.89
|
|
|
|
3,275,232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
(December 1 - December 31)
|
|
|
2,340,102
|
|
|
|
33.25
|
|
|
|
2,340,102
|
|
|
19,338,861
(b)
|
|
|
|
(a)
|
On June 21, 2019, the company announced by news release that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid and will continue its existing share purchase program. The program enables the company to purchase up to a maximum of 38,211,086 common shares during the period June 27, 2019 to June 26, 2020. This maximum includes 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 has advised the company that it intends to participate to maintain its ownership percentage at approximately 69.6 percent. The program will end should the company purchase the maximum allowable number of shares, or on June 26, 2020.
|
|
(b)
|
In its most recent quarterly earnings release, the company stated that it currently anticipates exercising its share purchases uniformly over the duration of the program. Purchase plans may be modified at any time without prior notice.
|
The company will continue to evaluate its share purchase program in the context of its overall capital activities.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
2016
|
|
|
2015
|
|
|
Revenues
|
|
|
34,002
|
|
|
|
34,964
|
|
|
|
29,125
|
|
|
|
25,049
|
|
|
|
26,756
|
|
|
Net income (loss)
|
|
|
2,200
|
|
|
|
2,314
|
|
|
|
490
|
|
|
|
2,165
|
|
|
|
1,122
|
|
|
|
|
|
42,187
|
|
|
|
41,456
|
|
|
|
41,601
|
|
|
|
41,654
|
|
|
|
43,170
|
|
Long-term debt at
year-end
|
|
|
4,961
|
|
|
|
4,978
|
|
|
|
5,005
|
|
|
|
5,032
|
|
|
|
6,564
|
|
|
|
|
|
5,190
|
|
|
|
5,180
|
|
|
|
5,207
|
|
|
|
5,234
|
|
|
|
8,516
|
|
Other long-term obligations at
year-end
|
|
|
3,637
|
|
|
|
2,943
|
|
|
|
3,780
|
|
|
|
3,656
|
|
|
|
3,597
|
|
|
Canadian dollars
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share - basic
|
|
|
2.88
|
|
|
|
2.87
|
|
|
|
0.58
|
|
|
|
2.55
|
|
|
|
1.32
|
|
|
Net income (loss) per common share - diluted
|
|
|
2.88
|
|
|
|
2.86
|
|
|
|
0.58
|
|
|
|
2.55
|
|
|
|
1.32
|
|
|
Dividends per common share - declared
|
|
|
0.85
|
|
|
|
0.73
|
|
|
|
0.63
|
|
|
|
0.59
|
|
|
|
0.54
|
|
Reference is made to the table setting forth exchange rates for the Canadian dollar, expressed in U.S. dollars, on page 2 of this report.
|
|
Management’s discussion and analysis of financial condition and results of operations
|
Reference is made to the section entitled “Management’s discussion and analysis of financial condition and results of operations” in the “Financial section”, starting on page 40 of this report.
|
|
Quantitative and qualitative disclosures about market risk
|
Reference is made to the section entitled “Market risks and other uncertainties” in the “Financial section”, starting on page 54 of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.
27
|
|
Financial statements and supplementary data
|
Reference is made to the table of contents in the “Financial section” on page 36 of this report:
|
●
|
|
Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP (PwC) dated February 26, 2020 beginning with the section entitled “Report of independent registered public accounting firm” on page 62 and continuing through note 18, “Other comprehensive income (loss) information” on page 95;
|
|
●
|
|
“Supplemental information on oil and gas exploration and production activities” (unaudited) starting on page 96; and
|
|
●
|
|
“Quarterly financial data” on page 100.
|
|
|
Changes in and disagreements with accountants on accounting and financial disclosure
|
None.
As indicated in the certifications in Exhibit 31 of this report, the company’s principal executive officer and principal financial officer have evaluated the company’s disclosure controls and procedures as of December 31, 2019. Based on that evaluation, these officers have concluded that the company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Reference is made to page 61 of this report for “Management’s report on internal control over financial reporting” and page 62 for the “Report of independent registered public accounting firm” on the company’s internal control over financial reporting as of December 31, 2019.
There has not been any change in the company’s internal control over financial reporting during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting.
None.
28
|
|
Directors, executive officers and corporate governance
|
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
The company currently has seven directors. The articles of the company require that the board have between five and fifteen directors. Each director is elected to hold office until the close of the next annual meeting. Each of the seven individuals listed in the section entitled “Nominees for director” on pages 102 to 105 of this report have been nominated for election at the annual meeting of shareholders to be held May 1, 2020. All of the nominees are directors and have been since the dates indicated.
S.D. Whittaker retired from the board on April 26, 2019 as she reached the company’s mandatory retirement age for directors in 2019. In September 2019, R.M. Kruger, then chairman, president and chief executive officer, announced his intention to retire from the company at the end of 2019. B.W. Corson was appointed to the board and as president of the company on September 17, 2019. Mr. Corson assumed the additional roles of chairman and chief executive officer on January 1, 2020, following Mr. Kruger’s retirement from the company and resignation from the board on December 31, 2019.
Reference is made to the section under “Nominees for director”:
|
|
|
“Director nominee tables”, on pages 102 to 105 of this report;
|
Reference is made to the sections under “Corporate governance disclosure”:
|
·
|
|
“Skills and experience of our board members”, on page 109 of this report.
|
|
·
|
|
“Other public company directorships of our board members”, on page 113 of this report.
|
|
·
|
|
The table entitled “Audit committee” under “Board and committee structure”, on page 119 of this report;
|
|
·
|
|
“Ethical business conduct”, starting on page 131 of this report; and
|
|
·
|
|
“Largest shareholder”, on page 134 of this report.
|
Reference is made to the sections under “Company executives and executive compensation”:
|
·
|
|
“Named executive officers of the company” and “Other executive officers of the company”, on pages 136 to 139 of this report.
|
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the sections under “Corporate governance disclosure”:
|
|
·
|
|
“Director compensation”, on pages 123 to 129 of this report; and
|
|
|
·
|
|
“Share ownership guidelines of independent directors and chairman, president and chief executive officer”, on page 130 of this report.
|
Reference is made to the following sections under “Company executives and executive compensation”:
|
|
·
|
|
“Letter to shareholders from the executive resources committee on executive compensation”, starting on page 140 of this report; and
|
|
|
·
|
|
“Compensation discussion and analysis”, on pages 142 to 165 of this report.
|
|
|
Security ownership of certain beneficial owners and management and related stockholder matters
|
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the section under “Company executives and executive compensation” entitled “Equity compensation plan information”, within the “Compensation discussion and analysis” section, on page 163 of this report.
Reference is made to the section under “Corporate governance disclosure” entitled “Largest shareholder”, on page 134 of this report.
Reference is also made to the security ownership information for directors and executive officers of the company under the preceding Items 10 and 11. The compensation of the directors and executive officers of the company for the year-ended December 31, 2019 is described in the sections under “Nominees for director” starting on page 102, “Director compensation” starting on page 123 and “Company executives and executive compensation” starting on page 136. The following table shows the number of Imperial Oil Limited and Exxon Mobil Corporation common shares owned and restricted stock units held by each named executive officer, and the incumbent directors and executive officers as a group, as of February 12, 2020.
|
|
|
Imperial Oil Limited
|
|
|
Exxon Mobil Corporation
|
|
|
Named executive officer
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
-
|
|
|
|
599,100
|
|
|
|
2,007
|
|
|
|
118,500
|
|
|
|
|
|
-
|
|
|
|
38,400
|
|
|
|
8,770
|
|
|
|
29,850
|
|
|
|
|
|
-
|
|
|
|
78,200
|
|
|
|
96,903
|
|
|
|
144,200
|
|
|
|
|
|
-
|
|
|
|
66,000
|
|
|
|
28,607
|
|
|
|
15,850
|
|
|
|
|
|
3,407
|
|
|
|
98,050
|
|
|
|
-
|
|
|
|
-
|
|
Incumbent directors and executive
officers as a group (17 people)
|
|
|
140,042
|
|
|
|
581,325
|
|
|
|
146,549
|
|
|
|
263,000
|
|
|
(a)
|
No common shares are beneficially owned by reason of exercisable options. None of these individuals owns more than 0.01 percent of the outstanding shares of Imperial Oil Limited or Exxon Mobil Corporation. The directors and officers as a group own approximately 0.02 percent of the outstanding shares of Imperial Oil Limited, and less than 0.01 percent of the outstanding shares of Exxon Mobil Corporation. Information not being within the knowledge of the company has been provided by the directors and the executive officers individually.
|
|
(b)
|
Restricted stock units do not carry voting rights prior to the issuance of shares on settlement of the awards.
|
|
(c)
|
R.M. Kruger was the company’s chairman, president and chief executive officer until September 16, 2019, and continued as chairman and chief executive officer until his retirement on December 31, 2019.
|
|
|
Certain relationships and related transactions, and director independence
|
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 101. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the section under “Corporate governance disclosure” entitled “Independence of our board members”, on page 110 of this report.
Reference is made to the section under “Corporate governance disclosure” entitled “Transactions with Exxon Mobil Corporation”, on page 134 of this report.
D.C. Brownell is deemed a
non-independent
member of the board of directors and the executive resources committee, public policy and corporate responsibility committee, nominations and corporate governance committee and community collaboration and engagement committee under the relevant standards. As an employee of Exxon Mobil Corporation, D.C. Brownell is independent of the company’s management and is able to assist these committees by reflecting the perspective of the company’s shareholders.
|
|
Principal accountant fees and services
|
The audit committee of the board of directors recommends that PwC be reappointed as the auditor of the company until the close of the next annual meeting. PwC has been the auditor of the company for more than five years and are located in Calgary, Alberta. PwC is a participating audit firm with the Canadian Public Accountability Board.
The aggregate fees of PwC for professional services rendered for the audit of the company’s financial statements and other services for the fiscal years ended December 31, 2019 and December 31, 2018 were as follows:
|
|
|
|
|
|
|
|
|
|
thousands of Canadian dollars
|
|
|
2019
|
|
|
|
2018
|
|
|
|
|
|
1,782
|
|
|
|
1,808
|
|
|
|
|
|
94
|
|
|
|
94
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
-
|
|
|
|
-
|
|
|
|
|
|
1,876
|
|
|
|
1,902
|
|
Audit fees included the audit of the company’s annual financial statements, internal control over financial reporting, and a review of the first three quarterly financial statements in 2019. Audit-related fees consisted of other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities. The company did not engage the auditor for any other services.
The audit committee formally and annually evaluates the performance of the external auditor, recommends the external auditor to be appointed by the shareholders, recommends their remuneration and oversees their work. The audit committee also approves the proposed current year audit program of the external auditor, assesses the results of the program after the end of the program period and approves in advance any
non-audit
services to be performed by the external auditor after considering the effect of such services on their independence.
All of the services rendered by the auditor to the company were approved by the audit committee.
The audit committee continually discusses with PwC their independence from the company and from management. PwC have confirmed that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta, the Public Company Accounting Oversight Board (United States) (PCAOB) and the rules of the U.S. Securities and Exchange Commission. The company has concluded that the auditor’s independence has been maintained.
|
Item 15.
|
Exhibits, financial statement schedules
|
Reference is made to the table of contents in the “Financial section” on page 36 of this report.
The following exhibits, numbered in accordance with Item 601 of Regulation
S-K,
are filed as part of this report:
|
|
|
|
|
(3) (i)
|
|
Restated certificate and articles of incorporation of the company (Incorporated herein by reference to Exhibit (3.1) to the company’s Form
8-K
filed on May 3, 2006 (File
No. 0-12014)).
|
|
|
|
By-laws
of the company (Incorporated herein by reference to Exhibit (3)(ii) to the company’s Quarterly Report on Form
10-Q
for the quarter ended March 31, 2003 (File
No. 0-12014)).
|
|
|
|
|
(4) (vi)
|
|
Description of capital stock.
|
|
|
|
|
(10) (ii)
|
|
(1) Syncrude Ownership and Management Agreement, dated February 4, 1975 (Incorporated herein by reference to Exhibit 13(b) of the company’s Registration Statement on Form
S-1,
as filed with the Securities and Exchange Commission on August 21, 1979 (File
No. 2-65290)).
|
|
|
|
(2) Letter Agreement, dated February 8, 1982, between the Government of Canada and Esso Resources Canada Limited, amending Schedule “C” to the Syncrude Ownership and Management Agreement filed as Exhibit (10)(ii)(2) (Incorporated herein by reference to Exhibit (20) of the company’s Annual Report on Form
10-K
for the year ended December 31, 1981 (File
No. 2-9259)).
|
|
|
|
(3) Amendment to Syncrude Ownership and Management Agreement, dated March 10, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(14) of the company’s Annual Report on Form
10-K
for the year ended December 31, 1989 (File
No. 0-12014)).
|
|
|
|
(4) Alberta Cold Lake Transition Agreement, effective January 1, 2000, relating to the royalties payable in respect of the Cold Lake production project and terminating the Alberta Cold Lake Crown Agreement dated June 25, 1984. (Incorporated herein by reference to Exhibit (10)(ii)(20) of the company’s Annual Report on Form
10-K
for the year ended December 31, 2001 (File
No. 0-12014)).
|
|
|
|
(5) Amendment to Syncrude Ownership and Management Agreement effective January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(22) of the company’s Quarterly Report on Form
10-Q
for the quarter ended June 30, 2002 (File
No. 0-12014)).
|
|
|
|
(6) Amendment to Syncrude Ownership and Management Agreement effective September 16, 1994 (Incorporated herein by reference to Exhibit (10)(ii)(23) of the company’s Quarterly Report on Form
10-Q
for the quarter ended June 30, 2002 (File
No. 0-12014)).
|
|
|
|
(7) Syncrude Bitumen Royalty Option Agreement, dated November 18, 2008, setting out the terms of the exercise by the Syncrude Joint Venture owners of the option contained in the existing Crown Agreement to convert to a royalty payable on the value of bitumen, effective January 1, 2009 (Incorporated herein by reference to Exhibit 1.01(10)(ii)(2) of the company’s Form
8-K
filed on November 19, 2008 (File
No. 0-12014)).
|
|
|
|
|
(iii)(A)
|
|
(1) Form of Letter relating to Supplemental Retirement Income (Incorporated herein by reference to Exhibit (10)(c)(3) of the company’s Annual Report on Form
10-K
for the year ended December 31, 1980 (File
No. 2-9259)).
|
|
|
|
(2) Deferred Share Unit Plan for Nonemployee Directors. (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company’s Annual Report on Form
10-K
for the year ended December 31, 1998 (File
No. 0-12014)).
|
|
|
|
(3) Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2008 and subsequent years, as amended effective November 20, 2008 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(5)] of the company’s Form
8-K
filed on November 25, 2008 (File
No. 0-12014)).
|
|
|
|
(4) Short Term Incentive Program for selected executives effective February 2, 2012 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form
8-K
filed on February 7, 2012 (File No. 0-12014)).
|
|
|
|
(5) Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2011 and subsequent years, as amended effective November 14, 2011 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form
8-K
filed on February 23, 2012 (File
No. 0-12014)).
|
|
|
|
|
|
|
|
(6) Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2016 and subsequent years, as amended effective October 26, 2016 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form
8-K
filed on October 31, 2016 (File
No. 0-12014)).
|
|
|
|
(7) Amended Short Term Incentive Program with respect to awards granted in 2016 and subsequent years, as amended effective October 26, 2016 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form
8-K
filed on October 31, 2016 (File
No. 0-12014)).
|
|
|
|
|
(21)
|
|
Imperial Oil Resources Limited is incorporated in Canada, and is a wholly-owned subsidiary of the company. The names of all other subsidiaries of the company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2019.
|
|
|
|
|
(31.1)
|
|
Certification by principal executive officer of Periodic Financial Report pursuant to Rule
13a-14(a).
|
|
|
|
|
(31.2)
|
|
Certification by principal financial officer of Periodic Financial Report pursuant to Rule
13a-14(a).
|
|
|
|
|
(32.1)
|
|
Certification by chief executive officer of Periodic Financial Report pursuant to Rule
13a-14(b)
and 18 U.S.C. Section 1350.
|
|
|
|
|
(32.2)
|
|
Certification by chief financial officer of Periodic Financial Report pursuant to Rule
13a-14(b)
and 18 U.S.C. Section 1350.
|
|
|
|
|
(101)
|
|
Interactive Data Files (formatted as Inline XBRL).
|
|
|
|
|
(104)
|
|
Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
|
Copies of Exhibits may be acquired upon written request of any shareholder to the vice president, investor relations, Imperial Oil Limited, 505 Quarry Park Boulevard S.E., Calgary, Alberta T2C 5N1, and payment of processing and mailing costs.
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf on February 26, 2020 by the undersigned, thereunto duly authorized.
|
Imperial Oil Limited
|
|
|
|
|
|
(Bradley W. Corson)
|
|
Chairman, president and chief executive officer
|
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 26, 2020 by the following persons on behalf of the registrant and in the capacities indicated.
|
|
|
|
|
|
|
Signature
|
|
|
|
Title
|
|
|
|
|
|
|
|
|
|
chief executive officer and director
(Principal executive officer)
|
|
|
|
|
|
|
|
|
|
finance and administration, and controller
(Principal financial officer and principal accounting officer)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
|
|
|
|
|
|
|
|
Director
|
|
(David W. Cornhill)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
(Miranda C. Hubbs)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
(Jack M. Mintz)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Director
|
|
(David S. Sutherland)
|
|
|
|
|
|
|
|
|
|
|
|
Table of contents
|
|
|
Page
|
|
|
|
|
|
|
|
|
37
|
|
|
|
|
|
38
|
|
|
|
|
|
40
|
|
|
|
|
|
40
|
|
|
|
|
|
40
|
|
|
|
|
|
45
|
|
|
|
|
|
50
|
|
|
|
|
|
53
|
|
|
|
|
|
54
|
|
|
|
|
|
56
|
|
|
|
|
|
60
|
|
|
|
|
|
61
|
|
|
|
|
|
62
|
|
|
|
|
|
65
|
|
|
|
|
|
66
|
|
|
|
|
|
67
|
|
|
|
|
|
68
|
|
|
|
|
|
69
|
|
|
|
|
|
70
|
|
|
|
|
|
70
|
|
|
|
|
|
75
|
|
|
|
|
|
76
|
|
|
|
|
|
78
|
|
|
|
|
|
79
|
|
|
|
|
|
84
|
|
|
|
|
|
85
|
|
|
|
|
|
86
|
|
|
|
|
|
87
|
|
|
|
|
|
87
|
|
|
|
|
|
88
|
|
|
|
|
|
89
|
|
|
|
|
|
89
|
|
|
|
|
|
90
|
|
|
|
|
|
92
|
|
|
|
|
|
93
|
|
|
|
|
|
94
|
|
|
|
|
|
95
|
|
|
|
|
|
96
|
|
|
|
|
|
100
|
|
Financial information (U.S. GAAP)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
|
|
2016
|
|
|
|
2015
|
|
|
|
|
|
34,002
|
|
|
|
34,964
|
|
|
|
29,125
|
|
|
|
25,049
|
|
|
|
26,756
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
1,348
|
|
|
|
(138
|
)
|
|
|
(706
|
)
|
|
|
(661
|
)
|
|
|
(704
|
)
|
|
|
|
|
961
|
|
|
|
2,366
|
|
|
|
1,040
|
|
|
|
2,754
|
|
|
|
1,586
|
|
|
|
|
|
108
|
|
|
|
275
|
|
|
|
235
|
|
|
|
187
|
|
|
|
287
|
|
|
|
|
|
(217
|
)
|
|
|
(189
|
)
|
|
|
(79
|
)
|
|
|
(115
|
)
|
|
|
(47
|
)
|
|
|
|
|
2,200
|
|
|
|
2,314
|
|
|
|
490
|
|
|
|
2,165
|
|
|
|
1,122
|
|
|
|
|
|
|
|
|
Cash and cash equivalents at
year-end
|
|
|
1,718
|
|
|
|
988
|
|
|
|
1,195
|
|
|
|
391
|
|
|
|
203
|
|
|
|
|
|
42,187
|
|
|
|
41,456
|
|
|
|
41,601
|
|
|
|
41,654
|
|
|
|
43,170
|
|
|
|
|
|
|
|
|
Long-term debt at
year-end
|
|
|
4,961
|
|
|
|
4,978
|
|
|
|
5,005
|
|
|
|
5,032
|
|
|
|
6,564
|
|
|
|
|
|
5,190
|
|
|
|
5,180
|
|
|
|
5,207
|
|
|
|
5,234
|
|
|
|
8,516
|
|
Other long-term obligations at
year-end
|
|
|
3,637
|
|
|
|
2,943
|
|
|
|
3,780
|
|
|
|
3,656
|
|
|
|
3,597
|
|
|
|
|
|
|
|
|
Shareholders’ equity at
year-end
|
|
|
24,276
|
|
|
|
24,489
|
|
|
|
24,435
|
|
|
|
25,021
|
|
|
|
23,425
|
|
Cash flow from operating activities
|
|
|
4,429
|
|
|
|
3,922
|
|
|
|
2,763
|
|
|
|
2,015
|
|
|
|
2,167
|
|
|
|
|
|
|
|
|
Per share information (Canadian dollars)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Net income (loss) per common share - basic
|
|
|
2.88
|
|
|
|
2.87
|
|
|
|
0.58
|
|
|
|
2.55
|
|
|
|
1.32
|
|
Net income (loss) per common share - diluted
|
|
|
2.88
|
|
|
|
2.86
|
|
|
|
0.58
|
|
|
|
2.55
|
|
|
|
1.32
|
|
Dividends per common share - declared
|
|
|
0.85
|
|
|
|
0.73
|
|
|
|
0.63
|
|
|
|
0.59
|
|
|
|
0.54
|
|
Listed below are definitions of several of Imperial’s key business and financial performance measures. The definitions are provided to facilitate understanding of the terms and how they are calculated.
Capital employed is a measure of net investment. When viewed from the perspective of how capital is used by the business, it includes the company’s property, plant and equipment, and other assets, less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the company, it includes total debt and equity. Both of these views include the company’s share of amounts applicable to equity companies, which the company believes should be included to provide a more comprehensive measurement of capital employed.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
Business uses: asset and liability perspective
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
42,187
|
|
|
|
41,456
|
|
|
|
41,601
|
|
Less: Total current liabilities excluding notes and loans payable
|
|
|
(4,366)
|
|
|
|
(3,753
|
)
|
|
|
(3,934
|
)
|
Total long-term liabilities excluding long-term debt
|
|
|
(8,355)
|
|
|
|
(8,034
|
)
|
|
|
(8,025
|
)
|
Add: Imperial’s share of equity company debt
|
|
|
24
|
|
|
|
23
|
|
|
|
19
|
|
|
|
|
|
29,490
|
|
|
|
29,692
|
|
|
|
29,661
|
|
|
|
|
|
|
Total company sources: Debt and equity perspective
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
229
|
|
|
|
202
|
|
|
|
202
|
|
|
|
|
|
4,961
|
|
|
|
4,978
|
|
|
|
5,005
|
|
|
|
|
|
24,276
|
|
|
|
24,489
|
|
|
|
24,435
|
|
Add: Imperial’s share of equity company debt
|
|
|
24
|
|
|
|
23
|
|
|
|
19
|
|
|
|
|
|
29,490
|
|
|
|
29,692
|
|
|
|
29,661
|
|
Return on average capital employed (ROCE)
ROCE is a financial performance 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
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. 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 the best measure of historical capital productivity in a capital-intensive, long-term industry to demonstrate to shareholders that capital has been used wisely over the long term. Additional measures, which are more cash flow based, are used to make investment decisions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
|
|
|
|
2,200
|
|
|
|
2,314
|
|
|
|
490
|
|
Financing
(after-tax),
including Imperial’s share of equity companies
|
|
|
66
|
|
|
|
77
|
|
|
|
48
|
|
Net income excluding financing
|
|
|
2,266
|
|
|
|
2,391
|
|
|
|
538
|
|
|
|
|
|
|
|
|
|
|
29,591
|
|
|
|
29,677
|
|
|
|
29,967
|
|
Return on average capital employed (percent) – corporate total
|
|
|
7.7
|
|
|
|
8.1
|
|
|
|
1.8
|
|
Cash flows from operating activities and asset sales
Cash flows from operating activities and asset sales is the sum of the net cash provided by operating activities and proceeds from asset sales reported in the Consolidated statement of cash flows. This cash flow reflects the total sources of cash both from operating the company’s assets and from the divesting of assets. The company employs a long-standing and regular disciplined review process to ensure that all assets are contributing to the company’s strategic objectives. Assets are divested when they no longer meet these objectives or are worth considerably more to others. Because of the regular nature of this activity, the company believes it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
Cash flows from operating activities
|
|
|
4,429
|
|
|
|
3,922
|
|
|
|
2,763
|
|
Proceeds from asset sales
|
|
|
82
|
|
|
|
59
|
|
|
|
232
|
|
Total cash flows from operating activities and asset sales
|
|
|
4,511
|
|
|
|
3,981
|
|
|
|
2,995
|
|
Operating costs are the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy costs, staffing and maintenance costs. They exclude the cost of raw materials, taxes and interest expense and are on a
before-tax
basis. While the company is responsible for all revenue and expense elements of net income, operating costs represent the expenses most directly under the company’s control and therefore, are useful in evaluating the company’s performance.
Reconciliation of operating costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
From Imperial’s Consolidated statement of income
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
32,055
|
|
|
|
32,026
|
|
|
|
28,842
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Purchases of crude oil and products
|
|
|
20,946
|
|
|
|
21,541
|
|
|
|
18,145
|
|
Federal excise tax and fuel charge
|
|
|
1,808
|
|
|
|
1,667
|
|
|
|
1,673
|
|
|
|
|
|
93
|
|
|
|
108
|
|
|
|
78
|
|
|
|
|
|
22,847
|
|
|
|
23,316
|
|
|
|
19,896
|
|
Imperial’s share of equity company expenses
|
|
|
76
|
|
|
|
74
|
|
|
|
62
|
|
|
|
|
|
9,284
|
|
|
|
8,784
|
|
|
|
9,008
|
|
Components of operating costs
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars
|
|
|
2019
|
|
|
|
2018
|
|
|
|
2017
|
|
From Imperial’s Consolidated statement of income
|
|
|
|
|
|
|
|
|
|
|
|
|
Production and manufacturing
|
|
|
6,520
|
|
|
|
6,121
|
|
|
|
5,586
|
|
|
|
|
|
900
|
|
|
|
908
|
|
|
|
883
|
|
Depreciation and depletion
|
|
|
1,598
|
|
|
|
1,555
|
|
|
|
2,172
|
|
Non-service
pension and postretirement benefit
|
|
|
143
|
|
|
|
107
|
|
|
|
122
|
|
|
|
|
|
47
|
|
|
|
19
|
|
|
|
183
|
|
|
|
|
|
9,208
|
|
|
|
8,710
|
|
|
|
8,946
|
|
Imperial’s share of equity company expenses
|
|
|
76
|
|
|
|
74
|
|
|
|
62
|
|
|
|
|
|
9,284
|
|
|
|
8,784
|
|
|
|
9,008
|
|
Management’s discussion and analysis of financial condition and results of operations
The following discussion and analysis of Imperial’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Imperial Oil Limited.
The company’s accounting and financial reporting fairly reflect its business model involving exploration for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products.
Imperial, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new Canadian energy supplies. The company’s integrated business model, with significant investments in Upstream, Downstream and Chemical segments, reduces the company’s risk from changes in commodity prices. While commodity prices depend on supply and demand and may be volatile on a short-term basis, Imperial’s investment decisions are grounded on fundamentals reflected in its long-term business outlook, and use a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives, in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Volumes are based on individual field production profiles, which are also updated annually. Price ranges for crude oil, natural gas, refined products and chemical products are based on corporate plan assumptions developed annually and are utilized for investment evaluation purposes. Major investment opportunities are evaluated over a range of potential market conditions. Once major investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.
The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.
Business environment and risk assessment
Long-term business outlook
The “Long-term business outlook” is based on Exxon Mobil Corporation’s 2019
Outlook for Energy
, which is used to help inform the company’s long-term business strategies and investment plans. By 2040, the world’s population is projected at around 9.2 billion people, or about 1.6 billion more than in 2017. Coincident with this population increase, the company expects worldwide economic growth to average close to 3 percent per year, with economic output nearly doubling by 2040. As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by about 20 percent from 2017 to 2040. This increase in energy demand is expected to be driven by developing countries (i.e., those that are not member nations of the Organization for Economic
Co-operation
and Development (OECD)). Canada is expected to see flat to modest local energy demand growth through to 2040 and will continue to be a large supplier of energy exports to help meet rising global energy needs.
As expanding prosperity helps drive global energy demand higher, increasing use of energy efficient technologies and practices, as well as lower-emission products will continue to help significantly reduce energy consumption and emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspects of the world’s economy through 2040, affecting energy requirements for power generation, transportation, industrial applications, and residential and commercial needs.
Global electricity demand is expected to increase approximately 60 percent from 2017 to 2040, with developing countries likely to account for about 85 percent of the increase. Consistent with this projection, power generation is expected to remain the largest and fastest growing major segment of global primary energy demand, supported by a wide variety of energy sources. The share of coal fired generation is likely to decline substantially and approach 25 percent of the world’s electricity in 2040, versus nearly 40 percent in 2017, in part as a result of policies to improve air quality as well as reduce greenhouse gas emissions to address the risks related to climate change. From 2017 to 2040, the amount of electricity supplied using natural gas, nuclear power, and renewables is likely to grow by
two-thirds,
accounting for the entire growth in electricity supplies and offsetting the reduction of coal. Electricity from wind and solar is likely to increase about 400 percent, helping total renewables (including other sources, i.e., hydropower) to account for about 75 percent of the increase in electricity supplies worldwide through 2040. Total renewables will likely reach nearly 40 percent of global electricity supplies by 2040. Natural gas and nuclear are also expected to increase shares over the period to 2040, reaching almost 30 percent and about 15 percent of global electricity supplies respectively by 2040. Supplies of electricity by energy type will reflect significant differences across regions reflecting a wide range of factors including the cost and availability of various energy supplies and policy developments.
Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by more than 25 percent from 2017 to 2040. Transportation energy demand is likely to account for approximately 60 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to peak prior to 2025 and then decline to levels seen in the early-2010s by 2040 as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United States, work to offset growth in the worldwide car fleet of about 70 percent. By 2040, light-duty vehicles are expected to account for about 20 percent of global liquid fuels demand. During the same time period, nearly all the world’s transportation fleets are likely to continue to run on liquid fuels, which are widely available and offer practical advantages in providing a large quantity of energy in small volumes.
Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of transportation, and fitness as a practical solution to meet a wide variety of needs. By 2040, global demand for liquid fuels is projected to grow to approximately 114 million
oil-equivalent
barrels per day, an increase of about 16 percent from 2017. The
non-OECD
share of global liquid fuels demand is expected to increase to about 65 percent by 2040, as liquid fuels demand in the OECD is likely to decline by close to 10 percent. Much of the global liquid fuels demand today is met by crude production from traditional conventional sources; these supplies will remain important, and significant development activity is expected to offset much of the natural declines from these fields. At the same time, a variety of emerging supply sources – including tight oil, deepwater, oil sands, natural gas liquids and biofuels – are expected to grow to help meet rising demand. The world’s resource base is sufficient to meet projected demand through 2040 as technology advances continue to expand the availability of economic and lower carbon supply options. However, timely investments will remain critical to meeting global needs with reliable and affordable supplies.
Natural gas is a
low-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 2017 to 2040, meeting more than 40 percent of global energy demand growth. Global natural gas demand is expected to rise about 35 percent from 2017 to 2040, with about half of that increase coming from the Asia Pacific region. Significant growth in supplies of unconventional gas – the natural gas found in shale and other tight rock formations – will help meet these needs. In total, about 60 percent of the growth in natural gas supplies is expected to be from unconventional sources. At the same time, conventionally-produced natural gas is likely to remain the cornerstone of global supply, meeting more than
two-thirds
of worldwide demand in 2040. Liquefied natural gas (LNG) trade will expand significantly, meeting about 40 percent of the increase in global demand growth, with much of this supply expected to help meet rising demand in Asia Pacific.
The world’s energy mix is highly diverse and will remain so through 2040. Oil is expected to remain the largest source of energy with its share remaining close to 30 percent in 2040. Coal is currently the second largest source of energy, but it is likely to lose that position to natural gas in the 2020 to 2025 timeframe. The share of natural gas is expected to reach about 25 percent by 2040, while the share of coal falls to about 20 percent. Nuclear power is projected to grow significantly, as many nations are likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is likely to exceed 15 percent of global energy by 2040, with biomass, hydro and geothermal contributing a combined share of more than 10 percent. Total energy supplied from wind, solar and biofuels is expected to increase rapidly, growing nearly 250 percent from 2017 to 2040, when they will likely be just over 5 percent of the world energy mix.
The company anticipates that the world’s available oil and gas resource base will grow not only from new discoveries, but also from increases in previously discovered fields. Technology will underpin these increases. The investments to develop and supply resources to meet global demand through 2040 will be significant – even if demand remains flat. This reflects a fundamental aspect of the oil and natural gas business as the International Energy Agency (IEA) describes in its
World Energy Outlook 2019
. According to the IEA’s Stated Energy Policies Scenario, the investment required to meet oil and natural gas supply requirements worldwide over the period 2019 to 2040 will be about US$20 trillion (measured in 2018 dollars). In the IEA’s Sustainable Development Scenario, which is in line with the objectives of the Paris Agreement on climate change, the investment need would still accumulate to US$13 trillion.
International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. Imperial’s estimates of potential costs related to greenhouse gas emissions align with applicable provincial and federal regulations. Additionally, Imperial uses ExxonMobil’s
Outlook for Energy
as a foundation for estimating energy supply and demand requirements from various energy sources and uses, and the
Outlook for Energy
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 for Energy
reflects an environment with increasingly stringent climate policies and is consistent with the aggregation of Nationally Determined Contributions, which were submitted by signatories to the United Nations Framework Convention on Climate Change (UNFCCC) 2015 Paris Agreement. The
Outlook for Energy
seeks to identify potential impacts of climate related policies, which often target specific sectors. It estimates potential impacts of these policies on consumer energy demand by using various assumptions and tools – including, depending on the sector, application of a proxy cost of carbon or assessment of targeted policies (i.e., automotive fuel economy standards). As people and nations look for ways to reduce risks of global climate change, they will continue to need practical solutions that do not jeopardize the affordability or reliability of the energy they need.
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, affordable energy, and economic progress for all people. All practical and economically viable energy sources, both conventional and unconventional, will need to be pursued to continue meeting global energy demand, recognizing the scale and variety of worldwide energy needs, as well as the importance of expanding access to modern energy to promote better standards of living for billions of people.
The information provided in the
“Long-term
business outlook” includes internal estimates and forecasts based upon ExxonMobil’s internal data and analyses, as well as publicly available information from external sources including the International Energy Agency.
Imperial produces crude oil and natural gas for sale predominantly into North American markets. Imperial’s Upstream business strategies guide the company’s exploration, development, production, research and gas marketing activities. These strategies include maximizing asset reliability, accelerating development and application of high impact technologies, maximizing value by capturing new business opportunities and managing the existing portfolio, as well as pursuing sustainable improvements in organizational efficiency and effectiveness. These strategies are underpinned by a relentless focus on operations integrity, commitment to innovative technologies, disciplined approach to investing and cost management, development of employees and investment in the communities within which the company operates.
Imperial has a significant oil and gas resource base and a large inventory of potential projects. The company continues to evaluate opportunities to support long-term growth. As future development projects bring new production online, Imperial expects growth from oil sands
in-situ
and mining, as well as unconventional resources, with the largest growth potential related to
in-situ.
Actual volumes will vary from year to year due to the factors described in Item 1A. “Risk factors”.
Kearl’s supplemental crushing facilities started operations in late 2019, with
ramp-up
of all units through early 2020. These facilities are expected to further improve reliability, reduce planned downtime, lower unit costs and enable the asset to achieve 240,000 barrels per day of total gross production in 2020. Gross bitumen production at Cold Lake was impacted by reservoir performance at Nabiye in 2019. The company anticipates this will continue to impact the asset’s near-term performance and, similar to 2019, expects gross bitumen production at Cold Lake to average 140,000 barrels per day in 2020. In 2019, the company slowed the pace of development of its $2.6 billion Aspen
in-situ
oil sands project given market uncertainty stemming from the Government of Alberta’s temporary mandatory production curtailment regulations and other industry competitiveness challenges. The decision to return to planned project activity levels will depend on several factors such as any subsequent government actions related to production curtailment and general market conditions.
The upstream industry environment continued to recover in 2019 as crude price differentials in the western Canadian market narrowed since the end of 2018. Prices for most of the company’s crude oil sold are referenced to Western Canada Select (WCS) and West Texas Intermediate (WTI) oil markets. On January 1, 2019, the Government of Alberta’s temporary mandatory production curtailment regulations came into effect. Consequently, the WTI / WCS differential narrowed from an average of approximately US$40 per barrel in the fourth quarter of 2018, to an average of about US$12 per barrel in the first quarter of 2019. Throughout 2019, the Government of Alberta continually eased the mandatory production limit, increased the base limit for production curtailment, and introduced several exemptions including a special production allowance providing temporary curtailment relief equivalent to incremental increases in shipments by rail. The duration of these regulations is uncertain. Imperial continually monitors the effects of these regulations and evaluates opportunities, including crude shipments by rail and the pace of the development of its Aspen
in-situ
oil sands project, as economically justified.
As described in more detail in Item 1A. “Risk factors”, environmental risks and climate related regulations could have negative impacts on the upstream business. On January 1, 2020, the International Maritime Organization’s mandate of a global 0.5 percent cap on the maximum level of sulphur in marine fuel came into effect. This new cap represents a significant reduction from the previous limit, and may adversely impact heavy crude price differentials in western Canada.
Imperial believes prices over the long-term will be driven by market supply and demand, with the demand side largely being a function of general economic activities, levels of prosperity, technology advances, consumer preference and government policies. On the supply side, prices may be significantly impacted by political events, logistics constraints, the actions of OPEC, governments and other factors. To manage the risks associated with price, Imperial evaluates annual plans and all major investments across a range of price scenarios.
Imperial’s Downstream serves predominantly Canadian markets with refining, logistics and marketing assets. Imperial’s Downstream business strategies competitively position the company across a range of market conditions. These strategies include targeting industry leading performance in reliability, safety and operations integrity, as well as maximizing value from advanced technologies, capitalizing on integration across Imperial’s businesses, selectively investing for resilient and advantaged returns, operating efficiently and effectively, and providing quality, valued and differentiated products and services to customers.
Imperial owns and operates three refineries in Canada, with aggregate distillation capacity of 423,000 barrels per day. Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, diesel oil, jet fuel, fuel oil and asphalt). Crude oil and many products are widely traded with published prices, including those quoted on the New York Mercantile Exchange. Prices for these commodities are determined by the global and regional marketplaces and are influenced by many factors, including global and regional supply / demand balances, inventory levels, industry refinery operations, import / export balances, currency fluctuations, seasonal demand, weather and political climate. Imperial’s integration across the value chain, from refining to marketing, enhances overall value across the fuels business.
In 2019, Imperial’s margins were negatively impacted by narrowing crude price differentials that resulted, in part, from the Government of Alberta’s temporary mandatory curtailment regulations on crude oil production.
As described in more detail in Item 1A. “Risk factors”, proposed carbon policy and other climate related regulations, as well as continued biofuels mandates, could have negative impacts on the downstream business.
Imperial supplies petroleum products to the motoring public through Esso and Mobil-branded sites and independent marketers. At the end of 2019, there were about 2,300 sites operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate sites in alignment with Esso and Mobil brand standards.
North America continued to benefit from abundant supplies of natural gas and gas liquids, providing both low cost energy and feedstock for steam crackers. In 2019, margins were adversely impacted by continued industry capacity additions outpacing demand growth. Imperial maintains a competitive advantage through continued operational excellence, 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.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
2,200
|
|
|
|
2,314
|
|
|
|
490
|
|
Net income in 2019 was $2,200 million, or $2.88 per share on a diluted basis, compared to net income of $2,314 million or $2.86 per share in 2018. 2019 results include a favourable impact, largely
non-cash,
of $662 million associated with the Alberta corporate income tax rate decrease. On June 28, 2019, the Alberta government enacted a 4 percent decrease in the provincial tax rate, from 12 percent to 8 percent by 2022.
Net income in 2018 was $2,314 million, or $2.86 per share on a diluted basis, an increase of $1,824 million compared to net income of $490 million or $0.58 per share in 2017. The prior year results included upstream
non-cash
impairment charges of $566 million.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of Canadian dollars
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
1,348
|
|
|
|
(138
|
)
|
|
|
(706
|
)
|
Upstream net income was $1,348 million for the year, reflecting the favourable impact associated with the decreased Alberta corporate income tax rate of $689 million. Excluding this impact, 2019 net income was $659 million, up $797 million compared to a net loss of $138 million in 2018. Improved results reflect higher crude oil realizations of about $1,000 million, as well as higher volumes of about $350 million primarily at Syncrude and Norman Wells. Results were negatively impacted by higher royalties of about $230 million, higher operating expenses of about $190 million and lower Cold Lake volumes of about $120 million.
Upstream recorded a net loss of $138 million in 2018, compared to a net loss of $706 million in 2017. Improved results reflect the absence of impairment charges of $566 million, higher Kearl volumes of about $210 million, lower royalties of about $80 million and favourable foreign exchange effects of about $50 million. These items were partially offset by higher operating costs of about $200 million, lower Cold Lake volumes of about $170 million and lower Canadian crude oil realizations of about $60 million.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canadian dollars
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
|
50.02
|
|
|
|
37.56
|
|
|
|
39.13
|
|
Synthetic oil
(per barrel)
|
|
|
74.47
|
|
|
|
70.66
|
|
|
|
67.58
|
|
Conventional crude oil
(per barrel)
|
|
|
51.81
|
|
|
|
41.84
|
|
|
|
53.51
|
|
Natural gas liquids
(per barrel)
|
|
|
22.83
|
|
|
|
38.66
|
|
|
|
31.46
|
|
Natural gas
(per thousand cubic feet)
|
|
|
2.05
|
|
|
|
2.43
|
|
|
|
2.58
|
|
WTI averaged US$57.03 per barrel in 2019, down from US$65.03 per barrel in 2018. WCS averaged US$44.29 per barrel and US$38.71 per barrel for the same periods. The WTI / WCS differential narrowed to average approximately US$13 per barrel in 2019, from around US$26 per barrel in 2018. The Canadian dollar averaged US$0.75 in 2019, a decrease of US$0.02 from 2018.
Imperial’s average Canadian dollar realizations for bitumen increased in 2019, supported primarily by an increase in WCS and lower diluent costs. Bitumen realizations averaged $50.02 per barrel, up from $37.56 per barrel in 2018. The company’s average Canadian dollar realizations for synthetic crude increased relative to WTI, primarily due to the narrowing of the western Canadian light crude differential. Synthetic crude realizations averaged $74.47 per barrel, up from $70.66 per barrel in 2018.
WTI averaged US$65.03 per barrel in 2018, up from US$50.85 per barrel in 2017. WCS averaged US$38.71 per barrel and US$38.95 per barrel for the same periods. The WTI / WCS differential widened to average approximately US$26 per barrel in 2018, from around US$12 per barrel in 2017. The Canadian dollar averaged US$0.77 in 2018, unchanged from 2017.
Imperial’s average Canadian dollar realizations for bitumen declined generally in line with WCS, adjusted for changes in the exchange rate and transportation costs. Bitumen realizations averaged $37.56 per barrel in 2018, a decrease of $1.57 per barrel from 2017. The company’s average Canadian dollar realizations for synthetic crude increased by $3.08 per barrel to average $70.66 per barrel in 2018, however the widening of the western Canadian light crude differential relative to WTI during the fourth quarter of 2018 negatively impacted synthetic crude realizations.
Crude oil and natural gas liquids (NGL) - production and sales
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
thousands of barrels per day
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
|
|
|
gross
|
|
|
net
|
|
|
gross
|
|
|
net
|
|
|
gross
|
|
|
net
|
|
|
|
|
|
285
|
|
|
|
254
|
|
|
|
293
|
|
|
|
255
|
|
|
|
288
|
|
|
|
255
|
|
|
|
|
|
73
|
|
|
|
65
|
|
|
|
62
|
|
|
|
60
|
|
|
|
62
|
|
|
|
57
|
|
|
|
|
|
14
|
|
|
|
13
|
|
|
|
5
|
|
|
|
5
|
|
|
|
4
|
|
|
|
3
|
|
Total crude oil production
|
|
|
372
|
|
|
|
332
|
|
|
|
360
|
|
|
|
320
|
|
|
|
354
|
|
|
|
315
|
|
|
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
|
|
2
|
|
|
|
1
|
|
|
|
1
|
|
Total crude oil and NGL production
|
|
|
374
|
|
|
|
333
|
|
|
|
361
|
|
|
|
322
|
|
|
|
355
|
|
|
|
316
|
|
Bitumen sales, including diluent
(c)
|
|
|
387
|
|
|
|
|
|
|
|
406
|
|
|
|
|
|
|
|
381
|
|
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
|
|
6
|
|
|
|
|
|
Natural gas - production and production available for sale
(a)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
millions of cubic feet per day
|
|
2019
|
|
|
2018
|
|
|
2017
|
|
<