NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
INDEX
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Page
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1.
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Business Overview
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2.
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Significant Accounting Policies
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3.
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Changes in Accounting Policies
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4.
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Revenue
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5.
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Segmented Information
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6.
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Earnings per Common Share
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7.
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Regulatory Matters
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8.
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Acquisitions and Dispositions
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9.
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Accounts Receivable and Other
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10.
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Inventory
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11.
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Property, Plant and Equipment
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12.
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Variable Interest Entities
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13.
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Long-Term Investments
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14.
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Restricted Long-Term Investments
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15.
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Intangible Assets
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16.
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Goodwill
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17.
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Accounts Payable and Other
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18.
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Debt
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19.
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Asset Retirement Obligations
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20.
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Noncontrolling Interests
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21.
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Share Capital
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22.
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Stock Option and Stock Unit Plans
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23.
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Components of Accumulated Other Comprehensive Income/(Loss)
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24.
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Risk Management and Financial Instruments
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25.
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Income Taxes
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26.
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Pension and Other Postretirement Benefits
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27.
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Leases
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28.
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Changes in Operating Assets and Liabilities
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29.
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Related Party Transactions
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30.
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Commitments and Contingencies
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31.
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Guarantees
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32.
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Quarterly Financial Data (Unaudited)
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1. BUSINESS OVERVIEW
The terms "we," "our," "us" and "Enbridge" as used in this report refer collectively to Enbridge Inc. and its subsidiaries unless the context suggests otherwise. These terms are used for convenience only and are not intended as a precise description of any separate legal entity within Enbridge.
Enbridge is a publicly traded energy transportation and distribution company. We conduct our business through five business segments: Liquids Pipelines, Gas Transmission and Midstream, Gas Distribution and Storage, Renewable Power Generation, and Energy Services. These reporting segments are strategic business units established by senior management to facilitate the achievement of our long-term objectives, to aid in resource allocation decisions and to assess operational performance.
LIQUIDS PIPELINES
Liquids Pipelines consists of pipelines and terminals in Canada and the United States (US) that transport various grades of crude oil and other liquid hydrocarbons, including the Mainline System, Regional Oil Sands System, Gulf Coast and Mid-Continent, Southern Lights Pipeline, Express-Platte System, Bakken System, and Feeder Pipelines and Other. This segment also includes Moda Midstream Operating, LLC (Moda) which was acquired on October 12, 2021 (Note 8) and is a component of Gulf Coast and Mid-Continent.
GAS TRANSMISSION AND MIDSTREAM
Gas Transmission and Midstream consists of our investments in natural gas pipelines and gathering and processing facilities in Canada and the US, including US Gas Transmission, Canadian Gas Transmission, US Midstream and Other.
GAS DISTRIBUTION AND STORAGE
Gas Distribution and Storage consists of our natural gas utility operations, the core of which is Enbridge Gas Inc. (Enbridge Gas), which serves residential, commercial and industrial customers located throughout Ontario. This business segment also includes natural gas distribution activities in Québec and an investment in Noverco Inc. (Noverco). We sold our investment in Noverco to Trencap L.P. on December 30, 2021 (Note 13).
RENEWABLE POWER GENERATION
Renewable Power Generation consists primarily of investments in wind and solar assets, as well as geothermal, waste heat recovery and transmission assets. In North America, assets are primarily located in the provinces of Alberta, Saskatchewan, Ontario and Québec, and in the states of Colorado, Texas, Indiana and West Virginia. We also have offshore wind assets in operation and under development in the United Kingdom, Germany and France.
ENERGY SERVICES
Our Energy Services businesses in Canada and the US undertake physical commodity marketing activity and logistical services to manage our volume commitments on various pipeline systems. Energy Services also provides energy marketing services to North American refiners, producers and other customers.
ELIMINATIONS AND OTHER
In addition to the business segments noted above, Eliminations and Other includes operating and administrative costs that are not allocated to business segments as well as a foreign exchange hedging program. Eliminations and Other also includes new business development activities and corporate investments.
2. SIGNIFICANT ACCOUNTING POLICIES
These consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (US GAAP). Amounts are stated in Canadian dollars unless otherwise noted. As a Securities and Exchange Commission (SEC) registrant, we are permitted to use US GAAP for the purposes of meeting both our Canadian and US continuous disclosure requirements.
BASIS OF PRESENTATION AND USE OF ESTIMATES
The preparation of financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities in the consolidated financial statements. Significant estimates and assumptions used in the preparation of the consolidated financial statements include, but are not limited to: variable consideration included in revenue (Note 4); carrying values of regulatory assets and liabilities (Note 7); purchase price allocations (Note 8); unbilled revenues; expected credit losses; depreciation rates and carrying value of property, plant and equipment (Note 11); amortization rates and carrying value of intangible assets (Note 15); measurement of goodwill (Note 16); fair value of asset retirement obligations (ARO) (Note 19); valuation of stock-based compensation (Note 22); fair value of financial instruments (Note 24); provisions for income taxes (Note 25); assumptions used to measure retirement benefits and OPEB (Note 26); commitments and contingencies (Note 30); and estimates of losses related to environmental remediation obligations (Note 30). Actual results could differ from these estimates.
Certain comparative figures in our consolidated financial statements have been reclassified to conform to the current year's presentation.
PRINCIPLES OF CONSOLIDATION
The consolidated financial statements include our accounts and accounts of our subsidiaries and VIEs for which we are the primary beneficiary. A VIE is a legal entity that does not have sufficient equity at risk to finance its activities without additional subordinated financial support or is structured such that equity investors lack the ability to make significant decisions relating to the entity’s operations through voting rights or do not substantively participate in the gains and losses of the entity. Upon inception of a contractual agreement, we perform an assessment to determine whether the arrangement contains a variable interest in a legal entity and whether that legal entity is a VIE. The primary beneficiary has both the power to direct the activities of the VIE that most significantly impact the entity’s economic performance and the obligation to absorb losses or the right to receive benefits from the VIE entity that could potentially be significant to the VIE. Where we conclude that we are the primary beneficiary of a VIE, we consolidate the accounts of that VIE. We assess all variable interests in the entity and use our judgment when determining if we are the primary beneficiary. Other qualitative factors that are considered include decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties. We assess the primary beneficiary determination for a VIE on an ongoing basis if there are changes in the facts and circumstances related to a VIE. If an entity is determined to not be a VIE, the voting interest entity model is applied, where an investor holding the majority voting rights consolidates the entity. The consolidated financial statements also include the accounts of any limited partnerships where we represent the general partner and, based on all facts and circumstances, control such limited partnerships, unless the limited partner has substantive participating rights or substantive kick-out rights. For certain investments where we retain an undivided interest in assets and liabilities, we record our proportionate share of assets, liabilities, revenues and expenses.
All significant intercompany accounts and transactions are eliminated upon consolidation. Ownership interests in subsidiaries represented by other parties that do not control the entity are presented in the consolidated financial statements as activities and balances attributable to noncontrolling interests. Investments and entities over which we exercise significant influence are accounted for using the equity method.
REGULATION
Certain parts of our businesses are subject to regulation by various authorities including, but not limited to, the Canada Energy Regulator (CER), the Federal Energy Regulatory Commission (FERC), the Alberta Energy Regulator, the Ontario Energy Board (OEB) and La Régie de l’energie du Québec. Regulatory bodies exercise statutory authority over matters such as construction, rates and ratemaking and agreements with customers. To recognize the economic effects of the actions of the regulator, the timing of recognition of certain revenues and expenses in these operations may differ from that otherwise expected under US GAAP for non-rate-regulated entities.
Regulatory assets represent amounts that are expected to be recovered from customers in future periods through rates. Regulatory liabilities represent amounts that are expected to be refunded to customers in future periods through rates or expected to be paid to cover future abandonment costs in relation to the CER’s Land Matters Consultation Initiative (LMCI). Regulatory assets are assessed for impairment if we identify an event indicative of possible impairment. The recognition of regulatory assets and liabilities is based on the actions, or expected future actions, of the regulator. To the extent that the regulator’s actions differ from our expectations, the timing and amount of recovery or settlement of regulatory balances could differ significantly from those recorded. In the absence of rate regulation, we would generally not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. A regulatory asset or liability is recognized in respect of deferred income taxes when it is expected the amounts will be recovered or settled through future regulator-approved rates. We believe that the recovery of our regulatory assets as at December 31, 2021 is probable over the periods described in Note 7 - Regulatory Matters.
Allowance for funds used during construction (AFUDC) is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component, which are both capitalized based on rates set out in a regulatory agreement. The corresponding impact on earnings is included in Interest expense for the interest component and Other income/(expense) for the equity component. In the absence of rate regulation, we would capitalize interest using a capitalization rate based on our cost of borrowing, whereas the capitalized equity component, the corresponding earnings during the construction phase and the subsequent depreciation relating to the equity component would not be recognized.
Under the pool method prescribed by certain regulators, it is not possible to identify the carrying value of the equity component of AFUDC or its effect on depreciation. Similarly, gains and losses on the retirement of certain specific fixed assets in any given year cannot be identified or quantified.
With the approval of regulators, certain operations capitalize a percentage of specified operating costs. These operations are authorized to charge depreciation and earn a return on the net book value of such capitalized costs in future years. In the absence of rate regulation, a portion of such operating costs would be charged to earnings in the year incurred.
For certain regulated operations to which US GAAP guidance for phase-in plans applies, negotiated depreciation rates recovered in transportation tolls may be less than the depreciation expense calculated in accordance with US GAAP in early years of long-term contracts but recovered in future periods when tolls exceed depreciation. Depreciation expense on such assets is recorded in accordance with US GAAP and no regulatory asset is recorded.
REVENUE RECOGNITION
For businesses that are not rate-regulated, revenues are recorded when products have been delivered or services have been performed, the amount of revenue can be reliably measured and collectability is reasonably assured. Customer creditworthiness is assessed prior to agreement signing, as well as throughout the contract duration. Certain revenues from liquids and gas pipeline businesses are recognized under the terms of committed delivery contracts rather than the cash tolls received.
Long-term take-or-pay contracts, under which shippers are obligated to pay fixed amounts ratably over the contract period regardless of volumes shipped, may contain make-up rights. Make-up rights are earned by shippers when minimum volume commitments are not utilized during the period but under certain circumstances can be used to offset overages in future periods, subject to expiry. We recognize revenues associated with make-up rights at the earlier of when the make-up volume is shipped, the make-up right expires or when it is determined that the likelihood that the shipper will utilize the make-up right is remote.
Certain offshore pipeline transportation contracts require us to provide transportation services for the life of the underlying producing fields. Under these arrangements, shippers pay us a fixed monthly toll for a defined period of time which may be shorter than the estimated reserve life of the underlying producing fields, resulting in a contract period which extends past the period of cash collection. Fixed monthly toll revenues are recognized ratably over the committed volume made available to shippers throughout the contract period, regardless of when cash is received.
For the years ended December 31, 2021, 2020 and 2019, cash received net of revenue recognized for contracts under make-up rights and similar deferred revenue arrangements was $127 million, $292 million and $169 million, respectively.
For rate-regulated businesses, revenues are recognized in a manner that is consistent with the underlying agreements as approved by the regulators. Natural gas utility revenues are recorded based on regular meter readings and estimates of customer usage from the last meter reading to the end of the reporting period. Estimates are based on historical consumption patterns and heating degree days experienced. Heating degree days is a measure of coldness that is indicative of volumetric requirements for natural gas utilized for heating purposes in our distribution franchise areas.
Our Energy Services segment enters into commodity purchase and sale arrangements that are recorded on a gross basis as the related contracts are not held for trading purposes and we are acting as the principal in the transactions.
Our largest non-affiliated customer accounted for approximately 13.5% of our third-party revenues for the year ended December 31, 2021 and 13.6% for the year ended December 31, 2020. No non-affiliated customer exceeded 10% of our third-party revenues for the year ended December 31, 2019.
DERIVATIVE INSTRUMENTS AND HEDGING
Non-qualifying Derivatives
Non-qualifying derivative instruments are used primarily to economically hedge foreign exchange, interest rate and commodity price earnings exposure. Non-qualifying derivatives are measured at fair value with changes in fair value recognized in earnings in Commodity sales, Transportation and other services revenue, Commodity costs, Operating and administrative expense, Net foreign currency gain/(loss) and Interest expense.
Derivatives in Qualifying Hedging Relationships
We use derivative financial instruments to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. Hedge accounting is optional and requires us to document the hedging relationship and test the hedging item’s effectiveness in offsetting changes in fair values or cash flows of the underlying hedged item on an ongoing basis. We present the earnings effects of hedging items with the hedged transaction. Derivatives in qualifying hedging relationships are categorized as cash flow hedges, fair value hedges or net investment hedges.
Cash Flow Hedges
We use cash flow hedges to manage our exposure to changes in commodity prices, foreign exchange rates, interest rates and certain compensation tied to our share price. The change in the fair value of a cash flow hedging instrument is recorded in Other comprehensive income/(loss) (OCI) and is reclassified to earnings when the hedged item impacts earnings.
If a derivative instrument designated as a cash flow hedge ceases to be effective or is terminated, hedge accounting is discontinued and the gain or loss at that date is deferred in OCI and recognized in earnings concurrently with the related transaction. If an anticipated hedged transaction is no longer probable, the gain or loss is recognized immediately in earnings. Subsequent gains and losses from derivative instruments for which hedge accounting has been discontinued are recognized in earnings in the period in which they occur.
Fair Value Hedges
We may use fair value hedges to hedge the fair value of debt instruments. The change in the fair value of the hedging instrument is recorded in earnings with changes in the fair value of the hedged risk of the asset or liability that is designated as part of the hedging relationship. If a fair value hedge is discontinued or ceases to be effective, the hedged risk of the asset or liability ceases to be remeasured at fair value and the cumulative fair value adjustment to the carrying value of the hedged item is recognized in earnings over the remaining life of the hedged item.
Net Investment Hedges
Gains and losses arising from the translation of our net investment in foreign operations from their functional currencies to Enbridge’s Canadian dollar presentation currency are included in cumulative translation adjustments (CTA), a component of OCI. We currently have designated a portion of our US dollar denominated debt, as well as a portfolio of foreign exchange forward contracts in prior periods, as a hedge of our net investment in US dollar denominated investments and subsidiaries. As a result, the change in fair value of the foreign currency derivatives as well as the translation of US dollar denominated debt are reflected in OCI. Amounts recognized previously in Accumulated other comprehensive income/(loss) (AOCI) are reclassified to earnings when there is a reduction of the hedged net investment resulting from the disposal of a foreign operation.
Classification of Derivatives
We recognize the fair value of derivative instruments in the Consolidated Statements of Financial Position as current and non-current assets or liabilities depending on the timing of settlements and the resulting cash flows associated with the instruments. Fair value amounts related to cash flows occurring beyond one year are classified as non-current.
Cash inflows and outflows related to derivative instruments are classified as Operating activities in the Consolidated Statements of Cash Flows.
Balance Sheet Offset
Assets and liabilities arising from derivative instruments may be offset in the Consolidated Statements of Financial Position when we have the legal right and intention to settle them on a net basis.
Transaction Costs
Transaction costs are incremental costs directly related to the acquisition of a financial asset or the issuance of a financial liability. We incur transaction costs primarily from the issuance of debt and account for these costs as a reduction to Long-term debt in the Consolidated Statements of Financial Position. These costs are amortized using the effective interest rate method over the term of the related debt instrument and are recorded in Interest expense.
EQUITY INVESTMENTS
Equity investments over which we exercise significant influence, but do not have controlling financial interests, are accounted for using the equity method. Equity investments are initially measured at cost and are adjusted for our proportionate share of undistributed equity earnings or loss. Equity investments are increased for contributions made to, and decreased for distributions received from, the investee. To the extent an equity investee undertakes activities necessary to commence its planned principal operations, we capitalize interest costs associated with the investment during such period.
RESTRICTED LONG-TERM INVESTMENTS
Long-term investments that are restricted as to withdrawal or usage, for the purposes of the CER’s LMCI, are presented as Restricted long-term investments in the Consolidated Statements of Financial Position.
OTHER INVESTMENTS
Generally, we classify equity investments in entities over which we do not exercise significant influence and that do not have readily determinable fair values as other investments measured using the fair value measurement alternative (FVMA). These investments are recorded at cost minus impairment, if any, plus or minus the impact of observable price changes occurring in orderly transactions for an identical or similar investment of the same issuer. Investments in equity securities measured using the FVMA are reviewed for impairment each reporting period and written down to their fair value if objective evidence of impairment is identified. Equity investments with readily determinable fair values are measured at fair value through earnings. Dividends received from investments in equity securities are recognized in earnings when the right to receive payment is established.
Investments in debt securities are classified as available-for-sale and measured at fair value through OCI.
NONCONTROLLING INTERESTS
Noncontrolling interests represent ownership interests attributable to third parties in certain consolidated subsidiaries. The portion of equity not owned by us in such entities is reflected as Noncontrolling interests within the equity section of the Consolidated Statements of Financial Position.
INCOME TAXES
Income taxes are accounted for using the liability method. Deferred income tax assets and liabilities are recorded based on temporary differences between the tax bases of assets and liabilities and their carrying values for accounting purposes. Deferred income tax assets and liabilities are measured using the tax rate that is expected to apply when the temporary differences reverse. For our regulated operations, a deferred income tax liability or asset is recognized with a corresponding regulatory asset or liability, respectively, to the extent that taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income tax expense.
FOREIGN CURRENCY TRANSACTIONS AND TRANSLATION
Foreign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated to the functional currency using the exchange rate prevailing at the date of the transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the functional currency using the exchange rate in effect as at the balance sheet date. Exchange gains and losses resulting from the translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise.
Gains and losses arising from the translation of foreign operations' functional currencies to our Canadian dollar presentation currency are included in the CTA component of AOCI and are recognized in earnings upon sale of the foreign operation. Asset and liability accounts are translated at the exchange rates in effect as at the balance sheet date, while revenues and expenses are translated using monthly average exchange rates.
CASH AND CASH EQUIVALENTS
Cash and cash equivalents include short-term investments with a term to maturity of three months or less when purchased.
RESTRICTED CASH
Cash and cash equivalents that are restricted as to withdrawal or usage, in accordance with specific commercial arrangements, are presented as Restricted cash in the Consolidated Statements of Financial Position.
LOANS AND RECEIVABLES
Affiliate long-term notes receivable are measured at amortized cost using the effective interest rate method, net of any impairment losses recognized. Accounts receivable and other are measured at cost. Interest income is recognized in earnings as it is earned with the passage of time.
CURRENT EXPECTED CREDIT LOSSES
For accounts receivable, a loss allowance matrix is utilized to measure lifetime expected credit losses. The matrix contemplates historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations. Other loan receivables and applicable off-balance sheet commitments utilize a discounted cash flow methodology which calculates the current expected credit losses based on historical default probability rates associated with the credit rating of the counterparty and the related term of the loan or commitment, adjusted for forward-looking information and management expectations.
NATURAL GAS IMBALANCES
The Consolidated Statements of Financial Position include balances as a result of differences in gas volumes received from, and delivered for, customers. As settlement of certain imbalances is in-kind, changes in the balances do not have an effect on our Consolidated Statements of Earnings or Consolidated Statements of Cash Flows. Most natural gas volumes owed to or by us are valued at natural gas market index prices as at the balance sheet dates.
INVENTORY
Inventory is comprised of natural gas held in storage by Enbridge Gas, crude oil and natural gas held primarily by businesses in the Energy Services segment and materials and supplies. Natural gas held in storage by Enbridge Gas is recorded at the quarterly prices approved by the OEB in the determination of distribution rates. The actual price of gas purchased may differ from the OEB approved price. The difference between the approved price and the actual cost of gas purchased is deferred as a liability for future refund, or as an asset for collection as approved by the OEB. Other inventory is recorded at the lower of cost, as determined on a weighted average basis, or market value. Upon disposition, other commodities inventory is recorded to Commodity costs in the Consolidated Statements of Earnings at the weighted average cost of inventory, including any adjustments recorded to reduce inventory to market value. Materials and supplies inventory is recorded at the lower of average cost or net realizable value.
PROPERTY, PLANT AND EQUIPMENT
Property, plant and equipment is recorded at historical cost. Expenditures for construction, expansion, major renewals and betterments are capitalized. Maintenance and repair costs are expensed as incurred. Expenditures for project development are capitalized if they are expected to have future benefit. We capitalize interest incurred during construction for non-rate-regulated assets. For rate-regulated assets, AFUDC is included in the cost of property, plant and equipment and is depreciated over future periods as part of the total cost of the related asset. AFUDC includes both an interest component and, if approved by the regulator, a cost of equity component.
Two primary methods of depreciation are utilized. For distinct assets, depreciation is generally provided on a straight-line basis over the estimated useful lives of the assets commencing when the asset is placed in-service. For largely homogeneous groups of assets with comparable useful lives, the pool method of accounting for property, plant and equipment is followed whereby similar assets are grouped and depreciated as a pool. When group assets are retired or otherwise disposed of, gains and losses are generally not reflected in earnings but are booked as an adjustment to accumulated depreciation.
LEASES
We recognize an arrangement as a lease when a customer has the right to obtain substantially all of the economic benefits from the use of an asset, as well as the right to direct the use of the asset. We recognize right-of-use (ROU) assets and the related lease liabilities in the Consolidated Statements of Financial Position for operating lease arrangements with a term of 12 months or longer. We do not separate non-lease components from the associated lease components of our lessee contracts and account for both components as a single lease component. We combine lease and non-lease components within a contract for operating lessor leases when certain conditions are met. ROU assets are assessed for impairment using the same approach applied for other long-lived assets.
Lease liabilities and ROU assets require the use of judgment and estimates which are applied in determining the term of a lease, appropriate discount rates, whether an arrangement contains a lease, whether there are any indicators of impairment for ROU assets and whether any ROU assets should be grouped with other long-lived assets for impairment testing.
DEFERRED AMOUNTS AND OTHER ASSETS
Deferred amounts and other assets primarily consists of costs that regulatory authorities have permitted, or are expected to permit, to be recovered through future rates, including: deferred income taxes; the fair value adjustment to long-term debt; actual cost of removal of previously retired or decommissioned plant assets; and actuarial gains and losses arising from defined benefit pension plans.
INTANGIBLE ASSETS
Intangible assets consist primarily of certain software costs, customer relationships and emission allowances. We capitalize costs incurred during the application development stage of internal use software projects. Customer relationships represent the underlying relationship from long-term agreements with customers that are capitalized upon acquisition. Intangible assets are generally amortized on a straight-line basis over their expected lives, commencing when the asset is available for use, with the exception of emission allowances, which are not amortized as they will be used to satisfy compliance obligations as they come due.
GOODWILL
Goodwill represents the excess of the purchase price over the fair value of net identifiable assets upon acquisition of a business. The carrying value of goodwill, which is not amortized, is assessed for impairment annually or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwill may be impaired. We perform our annual review of the goodwill balance on April 1.
We perform our annual review for impairment at the reporting unit level, which is identified by assessing whether the components of our operating segments constitute businesses for which discrete information is available, whether segment management regularly reviews the operating results of those components and whether the economic and regulatory characteristics are similar.
We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwill impairment assessment. When performing a qualitative assessment, we determine the drivers of fair value for each reporting unit and evaluate whether those drivers have been positively or negatively affected by relevant events and circumstances since the last fair value assessment. Our evaluation includes, but is not limited to, the assessment of macroeconomic trends, regulatory environments, capital accessibility, operating income trends and industry conditions. Based on our assessment of qualitative factors, if we determine it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment assessment is performed.
The quantitative goodwill impairment assessment involves determining the fair value of our reporting units and comparing those values to the carrying value of each reporting unit. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value, goodwill impairment is measured at the amount by which the reporting unit’s carrying value exceeds its fair value. This amount should not exceed the carrying amount of goodwill. The fair value of our reporting units is estimated using a combination of discounted cash flow and earnings multiples techniques. The determination of fair value using the discounted cash flow technique requires the use of estimates and assumptions related to discount rates, projected operating income, terminal value growth rates, capital expenditures and working capital levels. Cash flow projections include significant judgments and assumptions relating to discount rates and expected future capital expenditures. The determination of fair value using the earnings multiples technique requires assumptions to be made in relation to maintainable earnings and earnings multipliers for reporting units.
The allocation of goodwill to held-for-sale and disposed businesses is based on the relative fair value of businesses included in the relevant reporting unit.
On April 1, 2021, we performed a quantitative goodwill impairment assessment for the Gas Transmission and Midstream reporting unit and qualitative assessments for the Liquids Pipelines and Gas Distribution and Storage reporting units. Our goodwill impairment assessments did not result in an impairment charge. Also, we did not identify any indicators of goodwill impairment during the remainder of 2021.
IMPAIRMENT
We review the carrying values of our long-lived assets as events or changes in circumstances warrant. If it is determined that the carrying value of an asset exceeds its expected undiscounted cash flows, we will calculate fair value based on the discounted cash flows and write the asset down to the extent that the carrying value exceeds the fair value.
With respect to investments in debt securities and equity investments, we assess at each balance sheet date whether there is objective evidence that a financial asset is impaired by completing a quantitative or qualitative analysis of factors impacting the investment. If there is objective evidence of impairment, we value the expected discounted cash flows using observable market inputs. We determine whether the decline below carrying value is other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities. If the decline is determined to be other-than-temporary for equity method investments or is due to a credit loss for investments in debt securities, an impairment charge is recorded in earnings with an offsetting reduction to the carrying value of the asset.
ASSET RETIREMENT OBLIGATIONS
ARO associated with the retirement of long-lived assets are measured at fair value and recognized as Accounts payable and other or Other long-term liabilities in the period in which they can be reasonably determined. Fair value approximates the cost a third party would charge to perform the tasks necessary to retire such assets and is recognized at the present value of expected future cash flows. ARO are added to the carrying value of the associated asset and depreciated over the asset’s useful life. The corresponding liability is accreted over time through charges to earnings and is reduced by actual costs of decommissioning and reclamation. Our estimates of retirement costs could change as a result of changes in cost estimates and regulatory requirements. Currently, for the majority of our assets, it is not possible to make a reasonable estimate of ARO due to the indeterminate timing and scope of the asset retirements.
PENSION AND OTHER POSTRETIREMENT BENEFITS
We sponsor defined benefit and defined contribution pension plans, and defined benefit OPEB plans, which provide group health care, life insurance benefits and other postretirement benefits.
Defined benefit pension obligation and net periodic benefit cost are estimated using the projected unit credit method, which incorporates management’s best estimates of future salary levels, other cost escalations, retirement ages of employees and other actuarial factors, including discount rates and mortality. The OPEB benefit obligation and net periodic benefit cost are estimated using the projected unit credit method, where benefits are attributed to years of service, taking into consideration projection of benefit costs.
We use mortality tables issued by the Society of Actuaries in the US (revised in 2021) and the Canadian Institute of Actuaries (revised in 2014) to measure the benefit obligations of our US pension plans (the US Plans) and our Canadian pension plans (the Canadian Plans), respectively.
We determine discount rates by reference to rates of high-quality long-term corporate bonds with maturities that approximate the timing of future payments we anticipate making under each of the respective plans.
Funded pension and OPEB plan assets are measured at fair value. The expected return on funded pension and OPEB plan assets is determined using market-related values and assumptions on the invested asset mix consistent with the investment policies relating to the plan assets. The market-related values reflect estimated return on investments consistent with long-term historical averages for similar assets.
Actuarial gains and losses arise from the difference between the actual and expected rate of return on plan assets for that period (for funded pension and OPEB plans) or from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate, changes in headcount and salary inflation experience.
The excess of the fair value of a plan’s assets over the fair value of a plan’s benefit obligation is recognized as Deferred amounts and other assets in the Consolidated Statements of Financial Position. The excess of the fair value of a plan’s benefit obligation over the fair value of a plan’s assets is recognized as Accounts payable and other and Other long-term liabilities in the Consolidated Statements of Financial Position.
Net periodic benefit cost is charged to earnings and includes:
•cost of benefits provided in exchange for employee services rendered during the year (current service cost);
•interest cost of plan obligations;
•expected return on plan assets (for funded pension and OPEB plans);
•amortization of prior service costs on a straight-line basis over the expected average remaining service period of the active employee group covered by the plans; and
•amortization of cumulative unrecognized net actuarial gains and losses in excess of 10% of the greater of the accrued benefit obligation or the fair value of plan assets, over the expected average remaining service life of the active employee group covered by the plans.
Cumulative unrecognized net actuarial gains and losses and prior service costs arising from defined benefit pension plans for our non-utility operations and from defined benefit OPEB plans are presented as a component of AOCI in the Consolidated Statements of Changes in Equity. Any unrecognized actuarial gains and losses and prior service costs and credits related to those plans that arise during the period are recognized as a component of OCI, net of tax. Cumulative unrecognized net actuarial gains and losses and prior service costs arising from defined benefit pension plans for our utility operations, which have been permitted or are expected to be permitted by the regulators, to be recovered through future rates, are presented as a component of Deferred amounts and other assets in the Consolidated Statements of
Financial Position.
Our utility operations also record regulatory adjustments to reflect the difference between certain net periodic benefit costs for accounting purposes and net periodic benefit costs for ratemaking purposes. Offsetting regulatory assets or liabilities are recorded to the extent net periodic benefit costs are expected to be collected from or refunded to customers, respectively, in future rates. In the absence of rate regulation, regulatory assets or liabilities would not be recorded and net periodic benefit costs would be charged to earnings and OCI on an accrual basis.
For defined contribution plans, contributions made by us are expensed in the period in which the contribution occurs.
STOCK-BASED COMPENSATION
Incentive Stock Options (ISO) granted are recorded using the fair value method. Under this method, compensation expense is measured at the grant date based on the fair value of the ISO granted as calculated by the Black-Scholes-Merton model and is recognized on a straight-line basis over the shorter of the vesting period or the period to early retirement eligibility, with a corresponding credit to Additional paid-in capital. Balances in Additional paid-in capital are transferred to Share capital when the options are exercised.
Performance Stock Units (PSU) and Restricted Stock Units (RSU) are cash settled awards for which the related liability is remeasured each reporting period. PSUs vest at the completion of a three-year term and RSUs vest one-third annually from the grant date. During the vesting term, compensation expense is recorded based on the number of units outstanding and the current market price of Enbridge’s shares with an offset to Accounts payable and other or to Other long-term liabilities. The value of the PSUs is also dependent on our performance relative to performance targets set out under the plan.
COMMITMENTS, CONTINGENCIES AND ENVIRONMENTAL LIABILITIES
We expense or capitalize, as appropriate, expenditures for ongoing compliance with environmental regulations that relate to past or current operations. We expense costs incurred for remediation of existing environmental contamination caused by past operations that do not benefit future periods by preventing or eliminating future contamination. We record liabilities for environmental matters when assessments indicate that remediation efforts are probable and the costs can be reasonably estimated. Estimates of environmental liabilities are based on currently available facts, existing technology and presently enacted laws and regulations, taking into consideration the likely effects of inflation and other factors. These amounts also consider prior experience in remediating contaminated sites, other companies’ clean-up experience and data released by government organizations. Our estimates are subject to revision in future periods based on actual costs or new information and are included in Accounts payable and other and Other long-term liabilities in the Consolidated Statements of Financial Position at their undiscounted amounts. There is always a potential of incurring additional costs in connection with environmental liabilities due to variations in any or all of the categories described above, including modified or revised requirements from regulatory agencies, in addition to fines and penalties, as well as expenditures associated with litigation and settlement of claims. We evaluate recoveries from insurance coverage separately from the liability and, when recovery is probable, we record and report an asset separately from the associated liability in the Consolidated Statements of Financial Position.
Liabilities for other commitments and contingencies are recognized when, after fully analyzing available information, we determine it is either probable that an asset has been impaired, or that a liability has been incurred, and the amount of impairment or loss can be reasonably estimated. When a range of probable loss can be estimated, we recognize the most likely amount, or if no amount is more likely than another, the minimum of the range of probable loss is accrued. We expense legal costs associated with loss contingencies as such costs are incurred.
3. CHANGES IN ACCOUNTING POLICIES
CHANGES IN ACCOUNTING POLICIES
There were no changes in accounting policies during the year ended December 31, 2021.
ADOPTION OF NEW ACCOUNTING STANDARDS
Accounting for Contract Assets and Liabilities from Contracts with Customers in a Business Combination
Effective November 1, 2021, we adopted Accounting Standards Update (ASU) 2021-08 on a retrospective basis beginning January 1, 2021. The new standard was issued in October 2021 to amend business combination accounting specific to contract assets and contract liabilities resulting from contracts with customers, requiring measurement in accordance with Accounting Standards Codification (ASC) 606. The ASU is also applicable to contract assets and contract liabilities from other contracts to which ASC 606 applies, such as contract liabilities from the sale of nonfinancial assets within the scope of ASC 610-20. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Reference Rate Reform
For eligible hedging relationships existing as at January 1, 2021 and prospectively, we have applied the optional expedient in ASU 2020-04 whereby the modification of the hedging instrument does not result in an automatic hedging relationship de-designation. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Clarifying Interaction Between Equity Securities, Equity Method Investments and Derivatives
Effective January 1, 2021, we adopted ASU 2020-01 on a prospective basis. The new standard was issued in January 2020 and clarifies that observable transactions should be considered for the purpose of applying the measurement alternative in accordance with ASC 321 Investments - Equity Securities immediately before the application or upon discontinuance of the equity method of accounting. Furthermore, the ASU clarifies that forward contracts or purchased options on equity securities are not out of scope of ASC 815 Derivatives and Hedging guidance only because, upon the contracts' exercise, the equity securities could be accounted for under the equity method of accounting or fair value option. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Accounting for Income Taxes
Effective January 1, 2021, we adopted ASU 2019-12 on a prospective basis. The new standard was issued in December 2019 with the intent of simplifying the accounting for income taxes. The accounting update removes certain exceptions to the general principles in ASC 740 Income Taxes as well as provides simplification by clarifying and amending existing guidance. The adoption of this ASU did not have a material impact on our consolidated financial statements.
FUTURE ACCOUNTING POLICY CHANGES
Disclosures About Government Assistance
ASU 2021-10 was issued in November 2021 to increase the transparency of government assistance to business entities. The ASU adds new disclosure requirements for transactions with government that are accounted for using a grant or contribution accounting model by analogy. The required disclosures include information about the nature of transactions, accounting policy applied, impacted financial statement line items and significant terms and conditions. ASU 2021-10 is effective January 1, 2022 and can be applied either prospectively or retrospectively with early adoption permitted. The adoption of ASU 2021-10 is not expected to have a material impact on our consolidated financial statements.
Accounting for Certain Lessor Leases with Variable Lease Payments
ASU 2021-05 was issued in July 2021 to amend lessor accounting for certain leases with variable lease payments that do not depend on a reference index or a rate and would have resulted in the recognition of a loss at lease commencement if classified as a sales-type or a direct financing lease. The ASU amends the classification requirements of such leases for lessors to result in an operating lease classification. ASU 2021-05 is effective January 1, 2022 and can be applied either retrospectively or prospectively with early adoption permitted. The adoption of ASU 2021-05 is not expected to have a material impact on our consolidated financial statements.
Accounting for Modifications or Exchanges of Certain Equity-Classified Contracts
ASU 2021-04 was issued in May 2021 to clarify issuer accounting for modifications or exchanges of freestanding equity-classified written call options that remain equity classified after modification or exchange. The ASU requires an issuer to determine the accounting for the modification or exchange based on the economic substance of the modification or exchange. ASU 2021-04 is effective January 1, 2022 and should be applied prospectively. The adoption of ASU 2021-04 is not expected to have a material impact on our consolidated financial statements.
Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity
ASU 2020-06 was issued in August 2020 to simplify accounting for certain financial instruments. The ASU eliminates the current models that require separation of beneficial conversion and cash conversion features from convertible instruments and simplifies the derivative scope exception guidance pertaining to equity classification of contracts in an entity’s own equity. The ASU also introduces additional disclosures for convertible debt and freestanding instruments that are indexed to and settled in an entity’s own equity. The ASU amends the diluted earnings per share guidance, including the requirement to use if-converted method for all convertible instruments and an update for instruments that can be settled in either cash or shares. ASU 2020-06 is effective January 1, 2022 and should be applied on a full or modified retrospective basis. The adoption of ASU 2020-06 is not expected to have a material impact on our consolidated financial statements.
4. REVENUE
REVENUE FROM CONTRACTS WITH CUSTOMERS
Major Products and Services
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids Pipelines
|
Gas Transmission and Midstream
|
Gas Distribution and Storage
|
Renewable Power Generation
|
Energy Services
|
Eliminations and Other
|
Consolidated
|
|
Year ended December 31, 2021
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Transportation revenue
|
9,492
|
|
4,364
|
|
676
|
|
—
|
|
—
|
|
—
|
|
14,532
|
|
|
Storage and other revenue
|
147
|
|
255
|
|
246
|
|
—
|
|
—
|
|
—
|
|
648
|
|
|
Gas gathering and processing revenue
|
—
|
|
49
|
|
—
|
|
—
|
|
—
|
|
—
|
|
49
|
|
|
Gas distribution revenue
|
—
|
|
—
|
|
4,026
|
|
—
|
|
—
|
|
—
|
|
4,026
|
|
|
Electricity and transmission revenue
|
—
|
|
—
|
|
—
|
|
177
|
|
—
|
|
—
|
|
177
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from contracts with customers
|
9,639
|
|
4,668
|
|
4,948
|
|
177
|
|
—
|
|
—
|
|
19,432
|
|
|
Commodity sales
|
—
|
|
—
|
|
—
|
|
—
|
|
26,873
|
|
—
|
|
26,873
|
|
|
Other revenue1,2
|
375
|
|
42
|
|
13
|
|
336
|
|
—
|
|
—
|
|
766
|
|
|
Intersegment revenue
|
567
|
|
1
|
|
19
|
|
(1)
|
|
44
|
|
(630)
|
|
—
|
|
|
Total revenue
|
10,581
|
|
4,711
|
|
4,980
|
|
512
|
|
26,917
|
|
(630)
|
|
47,071
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids Pipelines
|
Gas Transmission and Midstream
|
Gas Distribution and Storage
|
Renewable Power Generation
|
Energy Services
|
Eliminations and Other
|
Consolidated
|
|
Year ended December 31, 2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Transportation revenue
|
9,161
|
|
4,523
|
|
674
|
|
—
|
|
—
|
|
—
|
|
14,358
|
|
|
Storage and other revenue
|
94
|
|
274
|
|
203
|
|
—
|
|
—
|
|
—
|
|
571
|
|
|
Gas gathering and processing revenue
|
—
|
|
27
|
|
—
|
|
—
|
|
—
|
|
—
|
|
27
|
|
|
Gas distribution revenue
|
—
|
|
—
|
|
3,663
|
|
—
|
|
—
|
|
—
|
|
3,663
|
|
|
Electricity and transmission revenue
|
—
|
|
—
|
|
—
|
|
198
|
|
—
|
|
—
|
|
198
|
|
|
|
|
|
|
|
|
|
|
|
Total revenue from contracts with customers
|
9,255
|
|
4,824
|
|
4,540
|
|
198
|
|
—
|
|
—
|
|
18,817
|
|
|
Commodity sales
|
—
|
|
—
|
|
—
|
|
—
|
|
19,259
|
|
—
|
|
19,259
|
|
|
Other revenue1,2
|
584
|
|
44
|
|
17
|
|
389
|
|
—
|
|
(23)
|
|
1,011
|
|
|
Intersegment revenue
|
584
|
|
2
|
|
12
|
|
—
|
|
24
|
|
(622)
|
|
—
|
|
|
Total revenue
|
10,423
|
|
4,870
|
|
4,569
|
|
587
|
|
19,283
|
|
(645)
|
|
39,087
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids Pipelines
|
Gas Transmission and Midstream
|
Gas Distribution and Storage
|
Renewable Power Generation
|
Energy Services
|
Eliminations and Other
|
Consolidated
|
|
Year ended December 31, 2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Transportation revenue
|
9,082
|
|
4,477
|
|
743
|
|
—
|
|
—
|
|
—
|
|
14,302
|
|
|
Storage and other revenue
|
109
|
|
268
|
|
201
|
|
—
|
|
—
|
|
—
|
|
578
|
|
|
Gas gathering and processing revenue
|
—
|
|
423
|
|
—
|
|
—
|
|
—
|
|
—
|
|
423
|
|
|
Gas distribution revenue
|
—
|
|
—
|
|
4,210
|
|
—
|
|
—
|
|
—
|
|
4,210
|
|
|
Electricity and transmission revenue
|
—
|
|
—
|
|
—
|
|
180
|
|
—
|
|
—
|
|
180
|
|
|
Commodity sales
|
—
|
|
4
|
|
—
|
|
—
|
|
—
|
|
—
|
|
4
|
|
|
Total revenue from contracts with customers
|
9,191
|
|
5,172
|
|
5,154
|
|
180
|
|
—
|
|
—
|
|
19,697
|
|
|
Commodity sales
|
—
|
|
—
|
|
—
|
|
—
|
|
29,305
|
|
—
|
|
29,305
|
|
|
Other revenue1,2
|
659
|
|
30
|
|
9
|
|
387
|
|
(2)
|
|
(16)
|
|
1,067
|
|
|
Intersegment revenue
|
369
|
|
5
|
|
16
|
|
—
|
|
71
|
|
(461)
|
|
—
|
|
|
Total revenue
|
10,219
|
|
5,207
|
|
5,179
|
|
567
|
|
29,374
|
|
(477)
|
|
50,069
|
|
1 Includes mark-to-market gains from our hedging program for the year ended December 31, 2021 of $59 million, (2020 - $265 million, 2019 - $346 million).
2 Includes revenues from lease contracts. Refer to Note 27 - Leases.
We disaggregate revenue into categories which represent our principal performance obligations within each business segment. These revenue categories represent the most significant revenue streams in each segment and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.
Contract Balances
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Contract Receivables
|
Contract Assets
|
Contract Liabilities
|
|
(millions of Canadian dollars)
|
|
|
|
|
Balance as at December 31, 2021
|
2,369
|
|
213
|
|
1,898
|
|
|
Balance as at December 31, 2020
|
2,042
|
|
226
|
|
1,815
|
|
Contract receivables represent the amount of receivables derived from contracts with customers.
Contract assets represent the amount of revenue which has been recognized in advance of payments received for performance obligations we have fulfilled (or partially fulfilled) and prior to the point in time at which our right to the payment is unconditional. Amounts included in contract assets are transferred to accounts receivable when our right to the consideration becomes unconditional.
Contract liabilities represent payments received for performance obligations which have not been fulfilled. Contract liabilities primarily relate to make-up rights and deferred revenue. Revenue recognized during the year ended December 31, 2021 included in contract liabilities at the beginning of the period is $305 million. Increases in contract liabilities from cash received, net of amounts recognized as revenue during the year ended December 31, 2021 were $397 million.
Performance Obligations
|
|
|
|
|
|
|
|
Segment
|
Nature of Performance Obligation
|
|
Liquids Pipelines
|
•Transportation and storage of crude oil and natural gas liquids (NGLs)
|
|
Gas Transmission and Midstream
|
•Transportation, storage, gathering, compression and treating of natural gas
|
|
•Transportation of NGLs
|
|
•Sale of crude oil, natural gas and NGLs
|
|
Gas Distribution and Storage
|
•Supply and delivery of natural gas
|
|
•Transportation of natural gas
|
|
•Storage of natural gas
|
|
Renewable Power Generation
|
•Generation and transmission of electricity
|
|
•Delivery of electricity from renewable energy generation facilities
|
There was no material revenue recognized in the year ended December 31, 2021 from performance obligations satisfied in previous periods.
Payment Terms
Payments are received monthly from customers under long-term transportation, commodity sales, and gas gathering and processing contracts. Payments from Gas Distribution and Storage customers are received on a continuous basis based on established billing cycles.
Certain contracts in the US offshore business provide for us to receive a series of fixed monthly payments (FMPs) for a specified period which is less than the period during which the performance obligations are satisfied. As a result, a portion of the FMPs are recorded as contract liabilities. The FMPs are not considered to be a financing arrangement because the payments are scheduled to match the production profiles of offshore oil and gas fields, which generate greater revenue in the initial years of their productive lives.
Revenue to be Recognized from Unfulfilled Performance Obligations
Total revenue from performance obligations expected to be fulfilled in future periods is $59.8 billion, of which $7.4 billion is expected to be recognized during the year ended December 31, 2022.
The revenues excluded from the amounts above based on optional exemptions available under ASC 606, as explained below, represent a significant portion of our overall revenues and revenues from contracts with customers. Certain revenues such as flow-through operating costs charged to shippers are recognized at the amount for which we have the right to invoice our customers and are excluded from the amounts of revenue to be recognized in the future from unfulfilled performance obligations above. Variable consideration is excluded from the amounts above due to the uncertainty of the associated consideration, which is generally resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be estimated. Additionally, the effect of escalation on certain tolls which are contractually escalated for inflation has not been reflected in the amounts above as it is not possible to reliably estimate future inflation rates. Revenues for periods extending beyond the current rate settlement term for regulated contracts where the tolls are periodically reset by the regulator are excluded from the amounts above since future tolls remain unknown. Finally, revenues from contracts with customers which have an original expected duration of one year or less are excluded from the amounts above.
SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUE
Long-Term Transportation Agreements
For long-term transportation agreements, significant judgments pertain to the period over which revenue is recognized and whether the agreement provides for make-up rights for the shippers. Transportation revenue earned from firm contracted capacity arrangements is recognized ratably over the contract period. Transportation revenue from interruptible or volumetric-based arrangements is recognized when services are performed.
Variable Consideration
Revenue from arrangements subject to variable consideration is recognized only to the extent that it is probable that a significant reversal in the amount of cumulative revenue recognized will not occur when the uncertainty associated with the variable consideration is subsequently resolved. Uncertainties associated with variable consideration relate principally to differences between estimated and actual volumes and prices. These uncertainties are resolved each month when actual volumes are sold or transported and actual tolls and prices are determined.
During the year ended December 31, 2021, revenue for the Canadian Mainline has been recognized in accordance with the terms of the Competitive Tolling Settlement (CTS), which expired on June 30, 2021. The tolls in place on June 30, 2021 continue on an interim basis until a new commercial arrangement is implemented and are subject to finalization and adjustment applicable to the interim period, if any. Due to the uncertainty of adjustment to tolling pursuant to a CER decision and potential customer negotiations, interim toll revenue recognized during the year ended December 31, 2021 is considered variable consideration.
Recognition and Measurement of Revenue
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids Pipelines
|
Gas Transmission and Midstream
|
Gas Distribution and Storage
|
Renewable Power Generation
|
|
Consolidated
|
|
Year ended December 31, 2021
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
Revenue from products transferred at a point in time
|
—
|
|
—
|
|
70
|
|
—
|
|
|
70
|
|
|
Revenue from products and services transferred over time1
|
9,639
|
|
4,668
|
|
4,878
|
|
177
|
|
|
19,362
|
|
|
Total revenue from contracts with customers
|
9,639
|
|
4,668
|
|
4,948
|
|
177
|
|
|
19,432
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids Pipelines
|
Gas Transmission and Midstream
|
Gas Distribution and Storage
|
Renewable Power Generation
|
|
Consolidated
|
|
Year ended December 31, 2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
Revenue from products transferred at a point in time
|
—
|
|
—
|
|
60
|
|
—
|
|
|
60
|
|
|
Revenue from products and services transferred over time1
|
9,255
|
|
4,824
|
|
4,480
|
|
198
|
|
|
18,757
|
|
|
Total revenue from contracts with customers
|
9,255
|
|
4,824
|
|
4,540
|
|
198
|
|
|
18,817
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids Pipelines
|
Gas Transmission and Midstream
|
Gas Distribution and Storage
|
Renewable Power Generation
|
|
Consolidated
|
|
Year ended December 31, 2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
Revenue from products transferred at a point in time
|
—
|
|
4
|
|
65
|
|
—
|
|
|
69
|
|
|
Revenue from products and services transferred over time1
|
9,191
|
|
5,168
|
|
5,089
|
|
180
|
|
|
19,628
|
|
|
Total revenue from contracts with customers
|
9,191
|
|
5,172
|
|
5,154
|
|
180
|
|
|
19,697
|
|
1 Revenue from crude oil and natural gas pipeline transportation, storage, natural gas gathering, compression and treating, natural gas distribution, natural gas storage services and electricity sales.
Performance Obligations Satisfied Over Time
For arrangements involving the transportation and sale of petroleum products and natural gas where the transportation services or commodities are simultaneously received and consumed by the shipper or customer, we recognize revenue over time using an output method based on volumes of commodities delivered or transported. The measurement of the volumes transported or delivered corresponds directly to the benefits received by the shippers or customers during that period.
Determination of Transaction Prices
Prices for transportation and gas processing services are determined based on the capital cost of the facilities, pipelines and associated infrastructure required to provide such services plus a rate of return on capital invested that is determined either through negotiations with customers or through regulatory processes for those operations that are subject to rate regulation.
Prices for commodities sold are determined by reference to market price indices plus or minus a negotiated differential and in certain cases a marketing fee.
Prices for natural gas sold and distribution services provided by regulated natural gas distribution operations are prescribed by regulation.
5. SEGMENTED INFORMATION
Segmented information for the years ended December 31, 2021, 2020 and 2019 is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2021
|
Liquids Pipelines
|
Gas Transmission and Midstream
|
Gas Distribution and Storage
|
Renewable Power Generation
|
Energy Services
|
Eliminations and Other
|
Consolidated
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Revenues
|
10,581
|
|
4,711
|
|
4,980
|
|
512
|
|
26,917
|
|
(630)
|
|
47,071
|
|
|
Commodity and gas distribution costs
|
(25)
|
|
—
|
|
(2,147)
|
|
—
|
|
(27,174)
|
|
644
|
|
(28,702)
|
|
|
Operating and administrative
|
(3,431)
|
|
(1,877)
|
|
(1,143)
|
|
(180)
|
|
(48)
|
|
(33)
|
|
(6,712)
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from equity investments
|
759
|
|
813
|
|
42
|
|
101
|
|
—
|
|
(4)
|
|
1,711
|
|
|
Impairment of equity investments
|
—
|
|
(111)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(111)
|
|
|
Other income/(expense)
|
13
|
|
135
|
|
385
|
|
75
|
|
(8)
|
|
379
|
|
979
|
|
|
Earnings/(loss) before interest, income tax expense and depreciation and amortization
|
7,897
|
|
3,671
|
|
2,117
|
|
508
|
|
(313)
|
|
356
|
|
14,236
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
(3,852)
|
|
|
Interest expense
|
|
|
|
|
|
|
(2,655)
|
|
|
Income tax expense
|
|
|
|
|
|
|
(1,415)
|
|
|
Earnings
|
|
|
|
|
|
|
6,314
|
|
|
Capital expenditures1
|
4,051
|
|
2,420
|
|
1,343
|
|
16
|
|
1
|
|
54
|
|
7,885
|
|
|
Total property, plant and equipment, net
|
52,530
|
|
27,028
|
|
16,904
|
|
3,315
|
|
23
|
|
267
|
|
100,067
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2020
|
Liquids Pipelines
|
Gas Transmission and Midstream
|
Gas Distribution and Storage
|
Renewable Power Generation
|
Energy Services
|
Eliminations and Other
|
Consolidated
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Revenues
|
10,423
|
|
4,870
|
|
4,569
|
|
587
|
|
19,283
|
|
(645)
|
|
39,087
|
|
|
Commodity and gas distribution costs
|
(20)
|
|
—
|
|
(1,810)
|
|
(2)
|
|
(19,450)
|
|
613
|
|
(20,669)
|
|
|
Operating and administrative
|
(3,331)
|
|
(1,859)
|
|
(1,091)
|
|
(191)
|
|
(67)
|
|
(210)
|
|
(6,749)
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from equity investments
|
558
|
|
479
|
|
9
|
|
94
|
|
(3)
|
|
(1)
|
|
1,136
|
|
|
Impairment of equity investments
|
—
|
|
(2,351)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(2,351)
|
|
|
Other income/(expense)
|
53
|
|
(52)
|
|
71
|
|
35
|
|
1
|
|
130
|
|
238
|
|
|
Earnings/(loss) before interest, income tax expense and depreciation and amortization
|
7,683
|
|
1,087
|
|
1,748
|
|
523
|
|
(236)
|
|
(113)
|
|
10,692
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
(3,712)
|
|
|
Interest expense
|
|
|
|
|
|
|
(2,790)
|
|
|
Income tax expense
|
|
|
|
|
|
|
(774)
|
|
|
Earnings
|
|
|
|
|
|
|
3,416
|
|
|
Capital expenditures1
|
2,033
|
|
2,130
|
|
1,134
|
|
81
|
|
2
|
|
90
|
|
5,470
|
|
|
Total property, plant and equipment, net
|
48,799
|
|
25,745
|
|
16,079
|
|
3,495
|
|
24
|
|
429
|
|
94,571
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31, 2019
|
Liquids Pipelines
|
Gas Transmission and Midstream
|
Gas Distribution and Storage
|
Renewable Power Generation
|
Energy Services
|
Eliminations and Other
|
Consolidated
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Revenues
|
10,219
|
|
5,207
|
|
5,179
|
|
567
|
|
29,374
|
|
(477)
|
|
50,069
|
|
|
Commodity and gas distribution costs
|
(29)
|
|
—
|
|
(2,354)
|
|
(2)
|
|
(29,091)
|
|
472
|
|
(31,004)
|
|
|
Operating and administrative
|
(3,298)
|
|
(2,232)
|
|
(1,149)
|
|
(189)
|
|
(44)
|
|
(79)
|
|
(6,991)
|
|
|
Impairment of long-lived assets
|
(21)
|
|
(105)
|
|
—
|
|
(297)
|
|
—
|
|
—
|
|
(423)
|
|
|
|
|
|
|
|
|
|
|
|
Income/(loss) from equity investments
|
780
|
|
682
|
|
4
|
|
31
|
|
8
|
|
(2)
|
|
1,503
|
|
|
Other income/(expense)
|
30
|
|
(181)
|
|
67
|
|
1
|
|
3
|
|
515
|
|
435
|
|
|
Earnings before interest, income tax expense and depreciation and amortization
|
7,681
|
|
3,371
|
|
1,747
|
|
111
|
|
250
|
|
429
|
|
13,589
|
|
|
Depreciation and amortization
|
|
|
|
|
|
|
(3,391)
|
|
|
Interest expense
|
|
|
|
|
|
|
(2,663)
|
|
|
Income tax expense
|
|
|
|
|
|
|
(1,708)
|
|
|
Earnings
|
|
|
|
|
|
|
5,827
|
|
|
Capital expenditures1
|
2,548
|
|
1,753
|
|
1,100
|
|
23
|
|
2
|
|
124
|
|
5,550
|
|
|
Total property, plant and equipment, net
|
48,783
|
|
25,268
|
|
15,622
|
|
3,658
|
|
24
|
|
368
|
|
93,723
|
|
1Includes allowance for equity funds used during construction.
The measurement basis for preparation of segmented information is consistent with the significant accounting policies (Note 2).
GEOGRAPHIC INFORMATION
Revenues1
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
Canada
|
20,474
|
|
16,453
|
|
19,954
|
|
|
US
|
26,597
|
|
22,634
|
|
30,115
|
|
|
|
47,071
|
|
39,087
|
|
50,069
|
|
1 Revenues are based on the country of origin of the product or service sold.
Property, Plant and Equipment1
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Canada
|
47,102
|
|
46,499
|
|
|
US
|
52,965
|
|
48,072
|
|
|
|
100,067
|
|
94,571
|
|
1 Amounts are based on the location where the assets are held.
6. EARNINGS PER COMMON SHARE
BASIC
Earnings per common share is calculated by dividing earnings attributable to common shareholders by the weighted average number of common shares outstanding. The weighted average number of common shares outstanding has been reduced by our pro-rata weighted average interest in our own common shares of approximately 2 million as at December 31, 2021, 5 million as at December 31, 2020, and 6 million as at December 31, 2019, resulting from our reciprocal investment in Noverco. On December 30, 2021, we closed the sale of our non-operating minority ownership of Noverco. Refer to Note 13 - Long-term Investments for more information.
DILUTED
The treasury stock method is used to determine the dilutive impact of stock options. This method assumes any proceeds from the exercise of stock options would be used to purchase common shares at the average market price during the period.
Weighted average shares outstanding used to calculate basic and diluted earnings per share are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
2019
|
|
(number of shares in millions)
|
|
|
|
|
Weighted average shares outstanding
|
2,023
|
|
2,020
|
|
2,017
|
|
|
Effect of dilutive options
|
2
|
|
1
|
|
3
|
|
|
Diluted weighted average shares outstanding
|
2,025
|
|
2,021
|
|
2,020
|
|
For the years ended December 31, 2021, 2020 and 2019, 18.6 million, 29.8 million and 17.8 million, respectively, of anti-dilutive stock options with a weighted average exercise price of $52.89, $51.42 and $53.56, respectively, were excluded from the diluted earnings per common share calculation.
7. REGULATORY MATTERS
We record assets and liabilities that result from regulated ratemaking processes that would not be recorded under US GAAP for non-regulated entities. See Note 2 - Significant Accounting Policies for further discussion. Our significant regulated businesses and the related accounting impacts are described below.
Under the current authorized rate structure for certain operations, income tax costs are recovered in rates based on the current income tax payable and do not include accruals for deferred income tax. However, as income taxes become payable as a result of the reversal of temporary differences that created the deferred income taxes, it is expected that rates will be adjusted to recover these taxes. Since most of these temporary differences are related to property, plant and equipment costs, this recovery is expected to occur over the life of the related assets.
LIQUIDS PIPELINES
Canadian Mainline
Canadian Mainline includes the Canadian portion of our mainline system and is subject to regulation by the CER. Tolls, excluding Lines 8 and 9, are governed by the 10-year CTS which expired on June 30, 2021 (Note 4). The CTS established a Canadian Local Toll for all volumes shipped on the Canadian Mainline and an International Joint Tariff for all volumes shipped from western Canadian receipt points to delivery points on our Lakehead System. Under the CTS, we have recognized a regulatory asset of $2.1 billion as at December 31, 2021 (2020 - $1.9 billion) to offset deferred income taxes, as a CER rate order governing flow-through income tax treatment permits future recovery. No other material regulatory assets or liabilities are recognized under the terms of the CTS.
Southern Lights Pipeline
The US and Canadian portions of the Southern Lights Pipeline are regulated by the FERC and CER, respectively. Shippers on the Southern Lights Pipeline are subject to long-term transportation contracts under a cost-of-service toll methodology. Toll adjustments are filed annually with the regulators and provide for the recovery of allowable operating and debt financing costs, plus a pre-determined after-tax return on equity (ROE) of 10%.
GAS TRANSMISSION AND MIDSTREAM
British Columbia Pipeline and Maritimes & Northeast Canada
British Columbia (BC) Pipeline and Maritimes & Northeast (M&N) Canada are regulated by the CER. Rates are approved by the CER through negotiated toll settlement agreements based on cost-of-service. Both our BC Pipeline and M&N Canada systems operate under the terms of their respective negotiated toll settlements, which stipulate an allowable ROE and the continuation and establishment of certain deferral and variance accounts. As both settlement agreements expired in December 2021, we are currently operating under CER-approved interim tolls and negotiating the terms of new toll settlements for periods beginning in 2022.
US Gas Transmission
Most of our US gas transmission and storage services are regulated by the FERC and may also be subject to the jurisdiction of various other federal, state and local agencies. The FERC regulates natural gas transmission in US interstate commerce including the establishment of rates for services, while rates for intrastate commerce and/or gathering services are regulated by the state gas commissions. Cost-of-service is the basis for the calculation of regulated tariff rates, although the FERC also allows the use of negotiated and discounted rates within contracts with shippers that may result in a rate that is above or below the FERC-regulated recourse rate for that service.
GAS DISTRIBUTION AND STORAGE
Enbridge Gas
Enbridge Gas' distribution rates, commencing in 2019, are set under a five-year Incentive Regulation (IR) framework using a price cap mechanism. The price cap mechanism establishes new rates each year through an annual base rate escalation at inflation less a 0.3% stretch factor, annual updates for certain costs to be passed through to customers, and where applicable, the recovery of material discrete incremental capital investments beyond those that can be funded through base rates. The IR framework includes the continuation and establishment of certain deferral and variance accounts, as well as an earnings sharing mechanism that requires Enbridge Gas to share equally with customers any earnings in excess of 150 basis points over the annual OEB approved ROE.
FINANCIAL STATEMENT EFFECTS
Accounting for rate-regulated activities has resulted in the recognition of the following regulatory assets and liabilities in the Consolidated Statements of Financial Position:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
Recovery/Refund
Period Ends
|
|
(millions of Canadian dollars)
|
|
|
|
|
Current regulatory assets
|
|
|
|
|
|
|
|
|
|
Under-recovery of fuel costs
|
114
|
|
86
|
|
2022
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current regulatory assets
|
145
|
|
146
|
|
2022
|
|
Total current regulatory assets1 (Note 9)
|
259
|
|
232
|
|
|
|
Long-term regulatory assets
|
|
|
|
|
Deferred income taxes2
|
4,176
|
|
3,890
|
|
Various
|
|
Long-term debt3
|
398
|
|
429
|
|
2023-2046
|
|
Negative salvage4
|
243
|
|
246
|
|
Various
|
|
Purchase gas variance
|
215
|
|
—
|
|
2023
|
|
Accounting policy changes5
|
157
|
|
169
|
|
Various
|
|
Pension plan receivable6
|
78
|
|
402
|
|
Various
|
|
Other long-term regulatory assets
|
339
|
|
261
|
|
Various
|
|
Total long-term regulatory assets1
|
5,606
|
|
5,397
|
|
|
|
Total regulatory assets
|
5,865
|
|
5,629
|
|
|
|
Current regulatory liabilities
|
|
|
|
|
|
|
|
|
|
Purchase gas variance
|
—
|
|
153
|
|
2021
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other current regulatory liabilities
|
106
|
|
117
|
|
2022
|
|
Total current regulatory liabilities7
|
106
|
|
270
|
|
|
|
Long-term regulatory liabilities
|
|
|
|
|
Future removal and site restoration reserves8
|
1,543
|
|
1,455
|
|
Various
|
|
Regulatory liability related to US income taxes9
|
895
|
|
941
|
|
2050-2072
|
|
Pipeline future abandonment costs (Note 14)
|
649
|
|
578
|
|
Various
|
|
Other long-term regulatory liabilities
|
234
|
|
150
|
|
Various
|
|
Total long-term regulatory liabilities7
|
3,321
|
|
3,124
|
|
|
|
Total regulatory liabilities
|
3,427
|
|
3,394
|
|
|
1 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in Deferred amounts and other assets.
2 Represents the regulatory offset to deferred income tax liabilities to the extent that it is expected to be included in future regulator-approved rates and recovered from customers. The recovery period depends on the timing of the reversal of temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded.
3 Represents our regulatory offset to the fair value adjustment to debt acquired in our merger with Spectra Energy Corp. (Spectra Energy). The offset is viewed as a proxy for the regulatory asset that would be recorded in the event such debt was extinguished at an amount higher than the carrying value.
4 The negative salvage balance represents the recovery in future rates of the actual cost of removal of previously retired or decommissioned plant assets, as approved by the FERC.
5 This deferral reflects unamortized accumulated actuarial gains/losses and past service costs incurred by Union Gas Limited, relating to the period up to our merger with Spectra Energy, which were previously recorded in AOCI. The amortization of this balance is recognized as a component of accrual-based pension expenses, which are included in Other income/(expense) and recovered in rates, as previously approved by the OEB.
6 Represents the regulatory offset to our pension liability to the extent that it is expected to be included in regulator-approved future rates and recovered from customers. The settlement period for this balance is not determinable. In the absence of rate-regulated accounting, this regulatory balance and the related pension expense would be recorded in earnings and OCI.
7 Current regulatory liabilities are included in Accounts payable and other, while long-term regulatory liabilities are included in Other long-term liabilities.
8 Future removal and site restoration reserves consists of amounts collected from customers, with the approval of the OEB, to fund future costs of removal and site restoration relating to property, plant and equipment. These costs are collected as part of the depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance will occur over the long-term as costs are incurred. In the absence of rate-regulated accounting, depreciation rates would not include a charge for removal and site restoration and costs would be charged to earnings as incurred with recognition of revenue for amounts previously collected.
9 The regulatory liability related to US income taxes resulted from the US tax reform legislation dated December 22, 2017. These balances will be refunded to customers in accordance with the respective rate settlements approved by the FERC.
8. ACQUISITIONS AND DISPOSITIONS
ACQUISITION
Moda Midstream Operating, LLC
On October 12, 2021, through a wholly-owned US subsidiary, we acquired all of the outstanding membership interests in Moda for $3.7 billion (US$3.0 billion) of cash plus potential contingent payments of up to US$150 million dependent on performance of the assets (the Acquisition). The Acquisition is also subject to customary closing and working capital adjustments. Moda owns and operates a light crude export platform with very large crude carrier capability. The Acquisition aligns with and advances our US Gulf Coast export strategy and enables connectivity to low-cost and long-lived reserves in the Permian and Eagle Ford basins.
We accounted for the Acquisition using the acquisition method as prescribed by ASC 805 Business Combinations. In accordance with valuation methodologies described in ASC 820 Fair Value Measurements, the acquired assets and assumed liabilities were recorded at their estimated fair values as at the date of acquisition.
The following table summarizes the estimated preliminary fair values that were assigned to the net assets of Moda:
|
|
|
|
|
|
|
|
|
October 12, 2021
|
|
(millions of Canadian dollars)
|
|
|
Fair value of net assets acquired:
|
|
|
Current assets
|
62
|
|
|
Property, plant and equipment (a)
|
1,480
|
|
|
Long-term investments (b)
|
427
|
|
|
Intangible assets (c)
|
1,781
|
|
|
Current liabilities
|
59
|
|
|
Long-term liabilities
|
17
|
|
|
Goodwill (d)
|
268
|
|
|
Purchase price:
|
|
|
Cash
|
3,755
|
|
|
Contingent consideration (e)
|
187
|
|
|
|
3,942
|
|
a) Due to the specialized nature of Moda's property, plant and equipment, which includes groups of assets configured for use as storage facilities, pipelines and export terminals, the depreciated replacement cost approach was adopted as the primary valuation methodology. In determining replacement cost, both indirect costing using relevant inflation indices and direct costing using relevant market quotes were utilized. Adjustments were then applied for physical deterioration as well as functional and economic obsolescence. The fair value of land was determined using a market approach, which is based on rents and offerings for comparable properties.
b) Long-term investments represent Moda's 20% equity interest in Cactus II Pipeline, LLC (Cactus II). The fair value of Cactus II was determined using the discounted cash flow method. The discounted cash flow method is an income-based approach to valuation which estimates the present value of future projected benefits from the investment.
c) Intangible assets consist primarily of customer relationships associated with long-term take-or-pay contracts. Fair value was determined using an income-based approach by estimating the present value of the after-tax earnings attributable to the contracts, including earnings associated with expected renewal terms, and will be amortized on a straight-line basis over an expected useful life of 10 years.
d) Goodwill is primarily attributable to uncontracted future revenues, existing assembled assets that cannot be duplicated at the same cost by a new entrant, and enhanced scale and geographic diversity which provide greater optionality and platforms for future growth. The goodwill balance recognized has been assigned to our Liquids Pipelines segment and is tax deductible over 15 years.
e) We agreed to pay additional contingent consideration of up to US$150 million to Moda's former membership interest holders if Moda's monthly volumes of crude oil loaded onto a vessel equal or exceed specified throughput levels. These performance requirements terminate the earlier of December 31, 2023 or the date the final contingent payment is made. The US$150 million of contingent consideration recognized in the purchase price represents the fair value of contingent consideration at the date of acquisition. As at December 31, 2021, there were no changes to the amount of contingent consideration recognized.
Acquisition-related expenses incurred were approximately $21 million for the year ended December 31, 2021 and are included in Operating and administrative expense in the Consolidated Statements of Earnings.
Upon completion of the Acquisition, we began consolidating Moda. For the period beginning October 12, 2021 through to December 31, 2021, Moda generated approximately $80 million in operating revenues and $9 million in earnings attributable to common shareholders.
Our supplemental pro forma consolidated financial information for the years ended December 31, 2021 and 2020, including the results of operations for Moda as if the Acquisition had been completed on January 1, 2020, are as follows:
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|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
|
(unaudited; millions of Canadian dollars)
|
|
|
|
Operating revenues
|
47,339
|
|
39,435
|
|
|
Earnings attributable to common shareholders1,2
|
5,771
|
|
2,938
|
|
1 Acquisition-related expenses of $21 million (after-tax $16 million) were excluded from earnings attributable to common shareholders for the year ended December 31 2021 and deducted for the year ended December 31, 2020.
2 Includes the amortization of fair value adjustments recorded for acquired property, plant and equipment, long-term investments and intangible assets of $193 million and $207 million (after-tax of $145 million and $155 million) for the years ended December 31, 2021 and 2020, respectively.
DISPOSITIONS
Line 10 Crude Oil Pipeline
In the first quarter of 2018, we satisfied the condition as set out in our agreements for the sale of our Line 10 crude oil pipeline (Line 10), which originates near Hamilton, Ontario and terminates at West Seneca, New York. Our subsidiaries, Enbridge Pipelines Inc. and Enbridge Energy Partners, L.P. (EEP), owned the Canadian and US portions of Line 10, respectively, and the related assets were included in our Liquids Pipelines segment. The transaction closed on June 1, 2020. No gain or loss on disposition was recorded.
Montana-Alberta Tie Line
In the fourth quarter of 2019, we committed to a plan to sell the Montana-Alberta Tie Line (MATL) transmission asset, a 345 kilometer transmission line from Great Falls, Montana to Lethbridge, Alberta. MATL was included in our Renewable Power Generation segment. The purchase and sale agreement was signed in January 2020.
Upon the reclassification and subsequent remeasurement of MATL assets as held for sale, a loss of $297 million was included within Impairment of long-lived assets in the Consolidated Statements of Earnings for the year ended December 31, 2019.
On May 1, 2020, we closed the sale of MATL for cash proceeds of approximately $189 million. After closing adjustments, a gain on disposal of $4 million was included in Other income/(expense) in the Consolidated Statements of Earnings.
Ozark Gas Transmission
In the first quarter of 2020, we agreed to sell our Ozark Gas Transmission and Ozark Gas Gathering assets (Ozark assets). The Ozark assets are composed of a transmission system that extends from southeastern Oklahoma through Arkansas to southeastern Missouri, and a fee-based gathering system that accesses Fayetteville Shale and Arkoma production. These assets were included in our Gas Transmission and Midstream segment.
On April 1, 2020, we closed the sale of the Ozark assets for cash proceeds of approximately $63 million. After closing adjustments, a gain on disposal of $1 million was included in Other income/(expense) in the Consolidated Statements of Earnings.
Canadian Natural Gas Gathering and Processing Businesses
On July 4, 2018, we entered into agreements to sell our Canadian natural gas gathering and processing businesses to Brookfield Infrastructure Partners L.P. and its institutional partners for a cash purchase price of approximately $4.3 billion, subject to customary closing adjustments. Separate agreements were entered into for those facilities currently governed by provincial regulations and those governed by federal regulations (collectively, Canadian Natural Gas Gathering and Processing Businesses assets); these assets were part of our Gas Transmission and Midstream segment.
On October 1, 2018, we closed the sale of the provincially regulated facilities. On December 31, 2019, we closed the sale of the federally regulated facilities for proceeds of approximately $1.7 billion. After closing adjustments, a loss on disposal of $268 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019. As these assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach.
St. Lawrence Gas Company, Inc.
In August 2017, we entered into an agreement to sell the issued and outstanding shares of St. Lawrence Gas Company, Inc. (St. Lawrence Gas). St. Lawrence Gas assets were included in the Gas Distribution and Storage segment. On November 1, 2019, we closed the sale of St. Lawrence Gas for cash proceeds of approximately $72 million. After closing adjustments, a loss on disposal of $10 million was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019.
Enbridge Gas New Brunswick
In December 2018, we entered into an agreement for the sale of Enbridge Gas New Brunswick Limited Partnership and Enbridge Gas New Brunswick Inc. (collectively, EGNB). EGNB assets were a part of our Gas Distribution and Storage segment. On October 1, 2019, we closed the sale of EGNB to Liberty Utilities (Canada) LP, a wholly-owned subsidiary of Algonquin Power and Utilities Corp., for cash proceeds of approximately $331 million. After closing adjustments, a loss on disposal of $3 million was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2019.
As EGNB assets represented a portion of a reporting unit, we allocated a portion of the goodwill of the reporting unit to these assets using a relative fair value approach. As such, allocated goodwill of $133 million was included in assets subsequently disposed.
9. ACCOUNTS RECEIVABLE AND OTHER
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Trade receivables and unbilled revenues1
|
4,957
|
|
3,923
|
|
|
Short-term portion of derivative assets (Note 24)
|
529
|
|
323
|
|
|
Regulatory assets (Note 7)
|
259
|
|
232
|
|
|
Taxes receivable
|
407
|
|
374
|
|
|
Other
|
710
|
|
406
|
|
|
|
6,862
|
|
5,258
|
|
1 Net of allowance for expected credit losses of $87 million as at December 31, 2021 and $70 million as at December 31, 2020.
10. INVENTORY
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Natural gas
|
953
|
|
710
|
|
|
Crude oil
|
624
|
|
744
|
|
|
Other
|
93
|
|
82
|
|
|
|
1,670
|
|
1,536
|
|
11. PROPERTY, PLANT AND EQUIPMENT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
|
|
December 31,
|
Depreciation Rate
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
Pipelines
|
2.8
|
%
|
62,997
|
|
57,459
|
|
|
Facilities and equipment
|
3.1
|
%
|
34,331
|
|
30,149
|
|
|
Land and right-of-way1
|
2.3
|
%
|
3,320
|
|
2,896
|
|
|
Gas mains, services and other
|
2.7
|
%
|
13,606
|
|
12,813
|
|
|
Storage
|
2.4
|
%
|
3,099
|
|
2,936
|
|
|
Wind turbines, solar panels and other
|
4.0
|
%
|
4,912
|
|
4,877
|
|
|
Other
|
8.2
|
%
|
1,507
|
|
1,558
|
|
|
Under construction
|
—
|
%
|
2,268
|
|
5,762
|
|
|
Total property, plant and equipment
|
|
126,040
|
|
118,450
|
|
|
Total accumulated depreciation
|
|
(25,973)
|
|
(23,879)
|
|
|
Property, plant and equipment, net
|
|
100,067
|
|
94,571
|
|
1 The measurement of weighted average depreciation rate excludes non-depreciable assets.
Depreciation expense for the years ended December 31, 2021, 2020 and 2019 was $3.5 billion, $3.4 billion and $3.0 billion, respectively.
IMPAIRMENT
Access Northeast Project
In 2019, we announced that we terminated the agreements with Eversource Energy and National Grid USA Service Company, Inc. related to the Access Northeast project. As a result, we recognized an impairment loss of $105 million for the year ended December 31, 2019, which is included in Impairment of long-lived assets in the Consolidated Statements of Earnings. Access Northeast is part of our Gas Transmission and Midstream segment.
Impairment charges were based on the amount by which the carrying values of the assets exceeded fair value, determined using expected discounted future cash flows.
12. VARIABLE INTEREST ENTITIES
CONSOLIDATED VARIABLE INTEREST ENTITIES
Our consolidated VIEs consist of legal entities where we are the primary beneficiary. We are the primary beneficiary when our variable interest(s) provide us with (i) the power to direct the activities of the VIE that most significantly impact the VIE’s economic performance and (ii) the obligation to absorb losses of the VIE or the right to receive benefits from the VIE that could potentially be significant to the VIE. We determine whether we are the primary beneficiary of a VIE by considering qualitative and quantitative factors, including, but not limited to: decision-making responsibilities, the VIE capital structure, risk and rewards sharing, contractual agreements with the VIE, voting rights and level of involvement of other parties.
The following table includes assets to be used to settle liabilities of our consolidated VIEs and liabilities of our consolidated VIEs for which creditors do not have recourse to our general credit as the primary beneficiary. These assets and liabilities are included in the Consolidated Statements of Financial Position.
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
20211
|
20201
|
|
(millions of Canadian dollars)
|
|
|
|
Assets
|
|
|
|
Cash and cash equivalents
|
247
|
|
215
|
|
|
Restricted cash
|
4
|
|
1
|
|
|
Accounts receivable and other
|
99
|
|
65
|
|
|
|
|
|
|
Inventory
|
9
|
|
7
|
|
|
|
359
|
|
288
|
|
|
Property, plant and equipment, net
|
3,052
|
|
3,201
|
|
|
Long-term investments
|
16
|
|
14
|
|
|
Restricted long-term investments
|
101
|
|
84
|
|
|
Deferred amounts and other assets
|
2
|
|
3
|
|
|
Intangible assets, net
|
108
|
|
115
|
|
|
|
|
|
|
|
|
|
|
|
3,638
|
|
3,705
|
|
|
Liabilities
|
|
|
|
|
|
|
|
Accounts payable and other
|
84
|
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Other long-term liabilities
|
182
|
|
175
|
|
|
Deferred income taxes
|
5
|
|
5
|
|
|
|
271
|
|
232
|
|
|
|
3,367
|
|
3,473
|
|
1 Excludes assets and liabilities of EEP and Spectra Energy Partners, L.P. (SEP) following the subsidiary guarantees agreement entered on January 22, 2019. See Part II. Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations - Summarized Financial Information.
We do not have obligations to provide additional financial support to any of our consolidated VIEs.
UNCONSOLIDATED VARIABLE INTEREST ENTITIES
We currently hold interests in several non-consolidated VIEs where we are not the primary beneficiary as we do not have the power to direct the activities of the VIEs that most significantly impact the VIEs' economic performance. These interests include investments in limited partnerships that are assessed to be VIEs due to the limited partners not having substantive kick-out rights or participating rights. The power to direct the activities of a majority of these non-consolidated limited partnership VIEs is shared amongst the partners. Each partner has representatives that make up an executive committee that makes significant decisions for the VIE and none of the partners may make significant decisions unilaterally.
The carrying amount of these VIEs and our estimated maximum exposure to loss as at December 31, 2021 and 2020 are presented below:
|
|
|
|
|
|
|
|
|
|
|
|
Carrying
Amount of
|
Maximum
Exposure to
|
|
December 31, 2021
|
the VIE
|
Loss
|
|
(millions of Canadian dollars)
|
|
|
|
Aux Sable Liquid Products L.P.1
|
113
|
|
195
|
|
|
EIH S.á r.l.2, 8
|
38
|
|
664
|
|
|
Enbridge Renewable Infrastructure Investments S.á r.l.3
|
54
|
|
2,121
|
|
|
|
|
|
|
|
|
|
|
Rampion Offshore Wind Limited5
|
450
|
|
508
|
|
|
Vector Pipeline L.P.6
|
189
|
|
374
|
|
|
Other4,7
|
210
|
|
426
|
|
|
|
1,054
|
|
4,288
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Carrying
Amount of
|
Maximum
Exposure to
|
|
December 31, 2020
|
the VIE
|
Loss
|
|
(millions of Canadian dollars)
|
|
|
|
Aux Sable Liquid Products L.P.1
|
106
|
|
187
|
|
|
Éolien Maritime France SAS2, 8
|
96
|
|
949
|
|
|
Enbridge Renewable Infrastructure Investments S.á r.l.3
|
100
|
|
2,516
|
|
|
|
|
|
|
PennEast Pipeline Company, LLC4
|
116
|
|
371
|
|
|
Rampion Offshore Wind Limited5
|
599
|
|
650
|
|
|
Vector Pipeline L.P.6
|
201
|
|
390
|
|
|
Other7
|
133
|
|
361
|
|
|
|
1,351
|
|
5,424
|
|
1At December 31, 2021 and 2020, the maximum exposure to loss includes guarantees by us for our respective share of the VIE’s borrowing on a bank credit facility.
2At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the three French offshore wind projects for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $73 million held by us as at December 31, 2021. On March 18, 2021, Enbridge Renewable Infrastructure Holdings S.á r.l. (ERIH) closed the sale of 49% of its interest in EIH S.á r.l. to the Canada Pension Plan Investment Board (CPP Investments).
3At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE and an outstanding affiliate loan receivable for $807 million and $904 million held by us as at December 31, 2021 and 2020, respectively.
4At December 31, 2021, the maximum exposure to loss is limited to our equity investment and at December 31, 2020, the maximum exposure to loss includes the remaining expected contributions to the joint venture.
5At December 31, 2021 and 2020, the maximum exposure to loss includes our parental guarantees that have been committed in project contracts in which we would be liable for in the event of default by the VIE.
6At December 31, 2021 and 2020, the maximum exposure to loss includes the carrying value of outstanding affiliate loans receivable for $80 million and $84 million held by us as at December 31, 2021 and 2020, respectively, and an outstanding credit facility for $105 million as at December 31, 2021 and 2020.
7At December 31, 2021, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable in the event of default by the VIE.
8At December 31, 2020, the maximum exposure to loss includes our parental guarantees that have been committed in connection with the project for which we would be liable for in the event of default by the VIE and an outstanding affiliate loan receivable for $132 million held by us as at December 31, 2020. In relation to the sale of 49% of EIH S.á r.l.'s interest to CPP Investments, Eolien Maritime France SAS is now reported under EIH S.á r.l. in 2021.
We do not have an obligation to and did not provide any additional financial support to the VIEs during the years ended December 31, 2021 and 2020.
13. LONG-TERM INVESTMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Ownership
|
|
|
|
December 31,
|
Interest
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
EQUITY INVESTMENTS
|
|
|
|
|
Liquids Pipelines
|
|
|
|
|
MarEn Bakken Company LLC1
|
75.0
|
%
|
1,728
|
|
1,795
|
|
|
Gray Oak Holdings LLC2
|
35.0
|
%
|
469
|
|
502
|
|
|
Seaway Crude Holdings LLC
|
50.0
|
%
|
2,634
|
|
2,668
|
|
|
Illinois Extension Pipeline Company, L.L.C.3
|
65.0
|
%
|
593
|
|
623
|
|
|
Cactus II Pipeline, LLC4
|
20.0
|
%
|
434
|
|
—
|
|
|
Other
|
30.0% - 43.8%
|
71
|
|
73
|
|
|
Gas Transmission and Midstream
|
|
|
|
|
Alliance Pipeline5
|
50.0
|
%
|
504
|
|
269
|
|
|
Aux Sable6
|
42.7% - 50.0%
|
238
|
|
251
|
|
|
DCP Midstream, LLC7
|
50.0
|
%
|
397
|
|
331
|
|
|
Gulfstream Natural Gas System, L.L.C.
|
50.0
|
%
|
1,180
|
|
1,175
|
|
|
Nexus Gas Transmission, LLC
|
50.0
|
%
|
1,724
|
|
1,745
|
|
|
PennEast Pipeline Company, LLC
|
20.0
|
%
|
12
|
|
116
|
|
|
Sabal Trail Transmission, LLC
|
50.0
|
%
|
1,464
|
|
1,510
|
|
|
Southeast Supply Header, LLC
|
50.0
|
%
|
82
|
|
84
|
|
|
Steckman Ridge, LP
|
50.0
|
%
|
88
|
|
90
|
|
|
Vector Pipeline8
|
60.0
|
%
|
189
|
|
201
|
|
|
Offshore - various joint ventures
|
22.0% - 74.3%
|
309
|
|
338
|
|
|
Other
|
33.3%
|
2
|
|
4
|
|
|
Gas Distribution and Storage
|
|
|
|
|
Noverco Common Shares9
|
38.9
|
%
|
—
|
|
156
|
|
|
Other
|
47.6% - 50%
|
20
|
|
13
|
|
|
Renewable Power Generation
|
|
|
|
|
EIH S.a.r.l.10
|
51.0
|
%
|
38
|
|
96
|
|
|
Enbridge Renewable Infrastructure Investments S.a.r.l.
|
51.0
|
%
|
54
|
|
100
|
|
|
Rampion Offshore Wind Limited
|
24.9
|
%
|
450
|
|
599
|
|
|
NextBridge Infrastructure LP
|
25.0
|
%
|
186
|
|
122
|
|
|
Other
|
12.0% - 50.0%
|
93
|
|
74
|
|
|
Eliminations and Other
|
|
|
|
|
Other
|
42.7% - 50.0%
|
23
|
|
32
|
|
|
OTHER LONG-TERM INVESTMENTS
|
|
|
|
|
Gas Distribution and Storage
|
|
|
|
|
Noverco Preferred Shares9
|
|
—
|
|
567
|
|
|
Renewable Power Generation
|
|
|
|
|
Emerging Technologies and Other
|
|
32
|
|
32
|
|
|
Eliminations and Other
|
|
|
|
|
Other11
|
|
310
|
|
252
|
|
|
|
|
13,324
|
|
13,818
|
|
1Owns 49% interest in Bakken Pipeline Investments L.L.C., which owns 75% of the Bakken Pipeline System resulting in a 27.6% effective interest in the Bakken Pipeline System.
2Owns 65% interest in Gray Oak Pipeline, LLC resulting in a 22.8% effective interest in Gray Oak Pipeline, LLC.
3Owns the Southern Access Extension Project.
4In October 2021 we acquired an effective 20.0% interest in Cactus II Pipeline, LLC through the acquisition of Moda Midstream Operating, LLC. See Note 8 - Acquisitions and Dispositions for further discussion.
5Includes Alliance Pipeline Limited Partnership in Canada and Alliance Pipeline L.P. in the US.
6Includes Aux Sable Canada LP in Canada and Aux Sable Liquid Products LP and Aux Sable Midstream LLC in the US.
7Our ownership in DCP Midstream, LLC (DCP Midstream) holds an interest of 56.5% in DCP Midstream, LP.
8Includes Vector Pipeline Limited Partnership in Canada and Vector Pipeline L.P. in the US.
9On December 30, 2021, we sold our 38.9% common share and preferred share interest of Noverco Inc.
10 On March 18, 2021, we sold 49% of EIH S.a.r.l., an entity that holds our 50% interest in Éolien Maritime France SAS (EMF), to the CPP Investments. This resulted in a 25.5% effective interest in EMF. Through our investment in EMF, we own equity interests in three French offshore wind projects, including Saint-Nazaire (25.5%), Fécamp (17.9%) and Calvados (21.7%).
11 Includes investments held and valued at fair value through net income.
Equity investments include the unamortized excess of the purchase price over the underlying net book value of the investees' assets at the purchase date. As at December 31, 2021, this basis difference was $2.5 billion (2020 - $2.4 billion), of which $730 million (2020 - $657 million) was amortizable.
For the years ended December 31, 2021, 2020 and 2019, distributions received from equity investments were $2.2 billion, $2.1 billion and $2.2 billion, respectively.
Summarized combined financial information of our interest in unconsolidated equity investments (presented at 100%) is as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
|
|
2021
|
|
|
2020
|
|
|
2019
|
|
|
|
|
|
|
|
|
|
|
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
|
|
Operating revenues
|
|
|
19,891
|
|
|
|
13,987
|
|
|
|
15,687
|
|
|
Operating expenses
|
|
|
16,514
|
|
|
|
12,223
|
|
|
|
13,153
|
|
|
Earnings
|
|
|
2,952
|
|
|
|
2,306
|
|
|
|
3,016
|
|
|
Earnings attributable to Enbridge
|
|
|
1,711
|
|
|
|
1,136
|
|
|
|
1,503
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
2021
|
|
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
Current assets
|
|
|
3,581
|
|
|
|
3,136
|
|
|
Non-current assets
|
|
|
44,497
|
|
|
|
45,955
|
|
|
Current liabilities
|
|
|
3,678
|
|
|
|
3,539
|
|
|
Non-current liabilities
|
|
|
16,950
|
|
|
|
19,639
|
|
|
Noncontrolling interests
|
|
|
3,786
|
|
|
|
3,810
|
|
Noverco Inc.
On June 7, 2021, IPL System Inc., a wholly owned subsidiary of Enbridge, entered into a purchase and sale agreement to sell its 38.9% common share and preferred share interest in Noverco to Trencap L.P. for $1.1 billion in cash.
On December 30, 2021, we closed the sale of Noverco for cash proceeds of $1.1 billion. After closing adjustments, a gain on disposal of $303 million before tax was included in Other income/(expense) in the Consolidated Statements of Earnings for the year ended December 31, 2021. Noverco was previously included in our Gas Distribution and Storage segment.
IMPAIRMENT OF EQUITY INVESTMENTS
PennEast Pipeline Company, LLC
PennEast Pipeline Company, LLC (PennEast) is a joint venture formed to develop a natural gas transmission pipeline to serve local distribution companies and power generators in Southeastern Pennsylvania and New Jersey, is owned 20% by Enbridge, and is recorded as an equity method investment. In the third quarter of 2021, PennEast determined further development of the project was no longer viable and development of the project was ceased. As a result, we recorded an other-than-temporary impairment loss of $111 million on our investment for the year ended December 31, 2021 based on the estimated fair value of our share of the net assets. The carrying value of this investment as at December 31, 2021 and 2020 was $12 million and $116 million, respectively.
Steckman Ridge, LP
Steckman Ridge, LP (Steckman Ridge) is engaged in the storage of natural gas, is owned 50% by Enbridge and is recorded as an equity method investment. During the year ended December 31, 2020, Steckman Ridge’s forecasted performance was adjusted for the expectation that future available capacity will be re-contracted at lower than expected rates and an other than temporary impairment loss on our investment of $221 million for the year ended December 31, 2020 was recorded based on a discounted cash flow analysis. The carrying value of this investment as at December 31, 2021 and 2020 was $88 million and $90 million, respectively.
Southeast Supply Header, L.L.C.
Southeast Supply Header, L.L.C. (SESH) provides natural gas transmission services from east Texas and northern Louisiana to the southeast markets of the Gulf Coast. SESH is owned 50% by Enbridge and is recorded as an equity method investment. The forecasted performance of SESH was revised during the year ended December 31, 2020 to reflect downward revisions to future negotiated rates as well as higher than expected available capacity levels, caused primarily by a significant contract expiry. An other than temporary impairment loss on our investment of $394 million for the year ended December 31, 2020 was recorded based on a discounted cash flow analysis. The carrying value of this investment as at December 31, 2021 and 2020 was $82 million and $84 million, respectively.
DCP Midstream, LLC
DCP Midstream, a 50% owned equity method investment of Enbridge, holds an equity interest in DCP Midstream, LP. A decline in the market price of DCP Midstream, LP’s publicly traded units during the first quarter of 2020 resulted in an other than temporary impairment loss on our investment in DCP Midstream of $1.7 billion for the year ended December 31, 2020. In addition, we incurred losses of $324 million through our equity earnings pick up in relation to asset and goodwill impairment losses recorded by DCP Midstream, LP. The carrying value of our investment in DCP Midstream as at December 31, 2021 and 2020 was $397 million and $331 million, respectively.
Our investments in PennEast, Steckman, SESH and DCP Midstream form part of our Gas Transmission and Midstream segment. The impairment losses were recorded within Impairment of Equity Investments in the Consolidated Statements of Earnings.
14. RESTRICTED LONG-TERM INVESTMENTS
Effective January 1, 2015, we began collecting and setting aside funds to cover future pipeline abandonment costs for all CER regulated pipelines as a result of the CER’s regulatory requirements under LMCI. The funds collected are held in trusts in accordance with the CER decision. The funds collected from shippers are reported within Transportation and other services revenues on the Consolidated Statements of Earnings and Restricted long-term investments on the Consolidated Statements of Financial Position. Concurrently, we reflect the future abandonment cost as an increase to Operating and administrative expense on the Consolidated Statements of Earnings and Other long-term liabilities on the Consolidated Statements of Financial Position.
We routinely invest excess cash and various restricted balances in securities such as commercial paper, bankers acceptances, corporate debt securities, Canadian equity securities, treasury bills and money market securities in the US and Canada.
As at December 31, 2021 and 2020, we had restricted long-term investments held in trust and classified as available-for-sale of $630 million and $553 million, respectively. The cost basis of our debt securities classified as available-for-sale and recorded as part of our restricted long-term investment balance was $383 million and $322 million as at December 31, 2021 and 2020, respectively. Within Other long-term liabilities we had estimated future abandonment costs related to LMCI of $649 million and $578 million as at December 31, 2021 and 2020, respectively (Note 7).
15. INTANGIBLE ASSETS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
Accumulated
|
|
|
December 31, 2021
|
Amortization Rate
|
Cost
|
Amortization
|
Net
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
Software
|
12.0
|
%
|
2,067
|
|
(1,148)
|
|
919
|
|
|
Power purchase agreements
|
4.5
|
%
|
63
|
|
(21)
|
|
42
|
|
|
Project agreement1
|
4.0
|
%
|
152
|
|
(27)
|
|
125
|
|
|
Customer relationships
|
8.5
|
%
|
2,532
|
|
(215)
|
|
2,317
|
|
|
Other intangible assets
|
3.9
|
%
|
475
|
|
(116)
|
|
359
|
|
|
Under development
|
—
|
%
|
246
|
|
—
|
|
246
|
|
|
|
|
5,535
|
|
(1,527)
|
|
4,008
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Weighted Average
|
|
Accumulated
|
|
|
December 31, 2020
|
Amortization Rate
|
Cost
|
Amortization
|
Net
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
Software
|
10.5
|
%
|
2,043
|
|
(1,299)
|
|
744
|
|
|
Power purchase agreements
|
4.5
|
%
|
63
|
|
(18)
|
|
45
|
|
|
Project agreement1
|
4.0
|
%
|
153
|
|
(21)
|
|
132
|
|
|
Customer relationships
|
5.0
|
%
|
724
|
|
(139)
|
|
585
|
|
|
Other intangible assets
|
2.7
|
%
|
456
|
|
(96)
|
|
360
|
|
|
Under development
|
—
|
%
|
214
|
|
—
|
|
214
|
|
|
|
|
3,653
|
|
(1,573)
|
|
2,080
|
|
1Represents a project agreement acquired from the merger of Enbridge and Spectra Energy.
For the years ended December 31, 2021, 2020 and 2019, our amortization expense related to intangible assets totaled $348 million, $294 million and $296 million, respectively. Our expected amortization expense associated with existing intangible assets for each of the years 2022 to 2026 is $492 million.
16. GOODWILL
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liquids
Pipelines
|
Gas
Transmission and Midstream
|
Gas
Distribution and Storage
|
|
Energy
Services
|
|
Consolidated
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Balance at January 1, 2020
|
7,951
|
|
19,844
|
|
5,356
|
|
|
2
|
|
|
33,153
|
|
|
Foreign exchange and other
|
(123)
|
|
(364)
|
|
—
|
|
|
—
|
|
|
(487)
|
|
|
Acquisition
|
—
|
|
—
|
|
22
|
|
|
—
|
|
|
22
|
|
|
Balance at December 31, 20201,2
|
7,828
|
|
19,480
|
|
5,378
|
|
|
2
|
|
|
32,688
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange and other
|
(55)
|
|
(145)
|
|
—
|
|
|
—
|
|
|
(200)
|
|
|
Acquisition3
|
268
|
|
—
|
|
19
|
|
|
—
|
|
|
287
|
|
|
Balance at December 31, 20211,2
|
8,041
|
|
19,335
|
|
5,397
|
|
|
2
|
|
|
32,775
|
|
1 Gross cost of goodwill as at December 31, 2021 and 2020 was $34.4 billion and $34.3 billion, respectively.
2 Accumulated impairment as at December 31, 2021 and 2020 was $1.6 billion.
3 In 2021, we recorded $268 million of goodwill related to the acquisition of Moda. See Note 8 - Acquisitions and Dispositions for further discussion.
17. ACCOUNTS PAYABLE AND OTHER
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Trade payables and operating accrued liabilities
|
4,470
|
|
3,497
|
|
|
Dividends payable
|
1,773
|
|
1,728
|
|
|
Current deferred credits
|
853
|
|
978
|
|
|
Construction payables and contractor holdbacks
|
844
|
|
855
|
|
|
Current derivative liabilities (Note 24)
|
717
|
|
896
|
|
|
Taxes payable
|
478
|
|
622
|
|
|
Other
|
632
|
|
652
|
|
|
|
9,767
|
|
9,228
|
|
18. DEBT
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
Weighted Average Interest Rate9
|
|
Maturity
|
|
2021
|
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Enbridge Inc.
|
|
|
|
|
|
|
|
|
US dollar senior notes
|
3.2
|
%
|
|
2022 - 2051
|
|
10,992
|
|
|
8,536
|
|
|
Medium-term notes
|
3.9
|
%
|
|
2022 - 2064
|
|
8,123
|
|
|
8,323
|
|
|
Sustainability-linked bonds
|
1.1
|
%
|
|
2033
|
|
2,363
|
|
|
—
|
|
|
Fixed-to-fixed subordinated term notes1
|
5.8
|
%
|
|
2080
|
|
1,263
|
|
|
1,274
|
|
|
Fixed-to-floating rate subordinated term notes2
|
5.8
|
%
|
|
2023 - 2028
|
|
6,442
|
|
|
6,477
|
|
|
Floating rate notes3
|
|
|
2022 - 2023
|
|
1,579
|
|
|
956
|
|
|
Commercial paper and credit facility draws
|
1.0
|
%
|
|
2022 - 2026
|
|
7,837
|
|
|
8,719
|
|
|
Other4
|
|
|
|
|
5
|
|
|
5
|
|
|
Enbridge (U.S.) Inc.
|
|
|
|
|
|
|
|
|
Commercial paper and credit facility draws
|
0.4
|
%
|
|
2023 - 2026
|
|
4,845
|
|
|
492
|
|
|
Other4
|
|
|
|
|
7
|
|
|
7
|
|
|
Enbridge Energy Partners, L.P.
|
|
|
|
|
|
|
|
|
Senior notes
|
6.5
|
%
|
|
2025 - 2045
|
|
3,095
|
|
|
3,886
|
|
|
Enbridge Gas Inc.
|
|
|
|
|
|
|
|
|
Medium-term notes
|
3.8
|
%
|
|
2022 - 2051
|
|
9,010
|
|
|
8,485
|
|
|
Debentures
|
9.1
|
%
|
|
2024 - 2025
|
|
210
|
|
|
210
|
|
|
Commercial paper and credit facility draws
|
0.5
|
%
|
|
2023
|
|
1,515
|
|
|
1,121
|
|
|
Enbridge Pipelines (Southern Lights) L.L.C.
|
|
|
|
|
|
|
|
|
Senior notes
|
4.0
|
%
|
|
2040
|
|
949
|
|
|
1,038
|
|
|
Enbridge Pipelines Inc.
|
|
|
|
|
|
|
|
|
Medium-term notes5
|
4.0
|
%
|
|
2022 - 2051
|
|
5,575
|
|
|
4,775
|
|
|
Debentures
|
8.2
|
%
|
|
2024
|
|
200
|
|
|
200
|
|
|
Commercial paper and credit facility draws
|
0.7
|
%
|
|
2023
|
|
667
|
|
|
1,278
|
|
|
Enbridge Southern Lights LP
|
|
|
|
|
|
|
|
|
Senior notes
|
4.0
|
%
|
|
2040
|
|
240
|
|
|
257
|
|
|
Spectra Energy Capital, LLC
|
|
|
|
|
|
|
|
|
Senior notes
|
7.0
|
%
|
|
2032 - 2038
|
|
218
|
|
|
220
|
|
|
Spectra Energy Partners, LP
|
|
|
|
|
|
|
|
|
Senior notes
|
3.9
|
%
|
|
2022 - 2048
|
|
8,451
|
|
|
8,332
|
|
|
Westcoast Energy Inc.
|
|
|
|
|
|
|
|
|
Medium-term notes
|
4.5
|
%
|
|
2022 - 2041
|
|
1,475
|
|
|
1,625
|
|
|
Debentures
|
8.1
|
%
|
|
2025 - 2026
|
|
275
|
|
|
275
|
|
|
Fair value adjustment
|
|
|
|
|
667
|
|
|
750
|
|
|
Other6
|
|
|
|
|
(363)
|
|
|
(344)
|
|
|
Total debt7
|
|
|
|
|
75,640
|
|
|
66,897
|
|
|
Current maturities
|
|
|
|
|
(6,164)
|
|
|
(2,957)
|
|
|
Short-term borrowings8
|
|
|
|
|
(1,515)
|
|
|
(1,121)
|
|
|
Long-term debt
|
|
|
|
|
67,961
|
|
|
62,819
|
|
1For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be set to equal to the Five-Year US Treasury Rate plus a margin of 5.31% from years 10 to 30 and a margin of 6.06% from years 30 to 60.
2For the initial 10 years, the notes carry a fixed interest rate. Subsequently, the interest rate will be floating and set to equal to the Canadian Dollar Offered Rate (CDOR) or the London Interbank Offered Rate (LIBOR) plus a margin. The notes would be converted automatically into Conversion Preference Shares in the event of bankruptcy and related events.
3The notes carry an interest rate equal to the three-month LIBOR plus a margin of 50 basis points and Secured Overnight Financing Rate (SOFR) plus a margin of 40 basis points.
4Primarily finance lease obligations.
5Included in medium-term notes is $100 million with a maturity date of 2112.
6Primarily unamortized discounts, premiums and debt issuance costs.
72021 - $36 billion and US$31 billion; 2020 - $35 billion and US$24 billion. Totals exclude capital lease obligations, unamortized discounts, premiums and debt issuance costs and fair value adjustment.
8Weighted average interest rates on outstanding commercial paper were 0.5% as at December 31, 2021 (2020 - 0.3%).
9Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2021.
As at December 31, 2021, all outstanding debt was unsecured.
CREDIT FACILITIES
The following table provides details of our committed credit facilities as at December 31, 2021:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Maturity1
|
Total Facilities
|
Draws2
|
Available
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
Enbridge Inc.
|
2022-2026
|
9,137
|
|
7,837
|
|
1,300
|
|
|
Enbridge (U.S.) Inc.
|
2023-2026
|
6,948
|
|
4,845
|
|
2,103
|
|
|
Enbridge Pipelines Inc.
|
2023
|
3,000
|
|
667
|
|
2,333
|
|
|
Enbridge Gas Inc.
|
2023
|
2,000
|
|
1,515
|
|
485
|
|
|
Total committed credit facilities
|
|
21,085
|
|
14,864
|
|
6,221
|
|
1Maturity date is inclusive of the one-year term out option for certain credit facilities.
2Includes facility draws and commercial paper issuances that are back-stopped by credit facilities.
On February 10, 2021, Enbridge Inc. entered into a three year, revolving, extendible, sustainability-linked credit facility for $1.0 billion with a syndicate of lenders and concurrently terminated our one year, revolving, syndicated credit facility for $3.0 billion.
On February 25, 2021, two term loans with an aggregate total of US$500 million were repaid with proceeds from a floating rate notes issuance.
On July 22 and 23, 2021, we renewed approximately $8.0 billion of our five-year credit facilities, extending the maturity date out to July 2026. We also extended approximately $10.0 billion of our 364-day extendible credit facilities to July 2022, which includes a one-year term out provision to July 2023.
On February 10, 2022 we renewed our three year $1.0 billion sustainability-linked credit facility, extending the maturity date out to July 2025.
In addition to the committed credit facilities noted above, we maintain $1.3 billion of uncommitted demand letter of credit facilities, of which $854 million was unutilized as at December 31, 2021. As at December 31, 2020, we had $849 million of uncommitted demand letter of credit facilities, of which $533 million was unutilized.
Our credit facilities carry a weighted average standby fee of 0.1% per annum on the unused portion and draws bear interest at market rates. Certain credit facilities serve as a back-stop to the commercial paper programs and we have the option to extend such facilities, which are currently scheduled to mature from 2022 to 2026.
As at December 31, 2021 and 2020, commercial paper and credit facility draws, net of short-term borrowings and non-revolving credit facilities that mature within one year, of $11.3 billion and $9.9 billion, respectively, were supported by the availability of long-term committed credit facilities and, therefore, have been classified as long-term debt.
LONG-TERM DEBT ISSUANCES
During the year ended December 31, 2021, we completed the following long-term debt issuances totaling US$3.9 billion and $3.2 billion:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company
|
Issue Date
|
|
Principal Amount
|
|
(millions of Canadian dollars unless otherwise stated)
|
|
|
Enbridge Inc.
|
|
|
|
|
February 2021
|
Floating rate senior-notes due February 20231
|
US$500
|
|
|
June 2021
|
2.50% Sustainability-linked senior notes due August 2033
|
US$1,000
|
|
|
June 2021
|
3.40% senior notes due August 2051
|
US$500
|
|
|
September 2021
|
3.10% Sustainability-linked medium-term notes due September 2033
|
$1,100
|
|
|
September 2021
|
4.10% medium-term notes due September 2051
|
$400
|
|
|
October 2021
|
0.55% senior notes due October 2023
|
US$500
|
|
|
October 2021
|
1.60% senior notes due October 2026
|
US$500
|
|
|
October 2021
|
3.40% senior notes due August 2051
|
US$500
|
|
Enbridge Gas Inc.
|
|
|
|
|
September 2021
|
2.35% medium-term notes due September 2031
|
$475
|
|
|
September 2021
|
3.20% medium-term notes due September 2051
|
$425
|
|
Enbridge Pipelines Inc.
|
|
|
|
|
May 2021
|
2.82% medium-term notes due May 2031
|
$400
|
|
|
May 2021
|
4.20% medium-term notes due May 2051
|
$400
|
|
Spectra Energy Partners, LP
|
|
|
|
|
September 2021
|
2.50% senior notes due September 20312
|
US$400
|
1Notes carry an interest rate equal to the SOFR plus a margin of 40 basis points.
2Issued through Texas Eastern Transmission, LP, a wholly-owned operating subsidiary of SEP.
On January 19, 2022, we closed a $750 million private placement offering of non-call 10-year fixed-to-fixed subordinated notes which mature on January 19, 2082. The net proceeds from the offering will be used to redeem the Preference Shares, Series 17 at par on March 1, 2022.
LONG-TERM DEBT REPAYMENTS
During the year ended December 31, 2021, we completed the following long-term debt repayments totaling $1.1 billion and US$914 million, respectively:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Company
|
Repayment Date
|
|
Principal Amount
|
|
(millions of Canadian dollars unless otherwise stated)
|
|
|
Enbridge Inc.
|
|
|
|
|
February 2021
|
4.26% medium-term notes
|
$200
|
|
|
March 2021
|
3.16% medium-term notes
|
$400
|
|
Enbridge Energy Partners, L.P.
|
|
|
|
|
June 2021
|
4.20% senior notes
|
US$600
|
|
Enbridge Gas Inc.
|
|
|
|
|
May 2021
|
2.76% medium-term notes
|
$200
|
|
|
December 2021
|
4.77% medium-term notes
|
$175
|
|
Enbridge Pipelines (Southern Lights) L.L.C.
|
|
|
|
|
June and December 2021
|
3.98% senior notes
|
US$64
|
|
Enbridge Southern Lights LP
|
|
|
|
|
June and December 2021
|
4.01% senior notes
|
$16
|
|
Spectra Energy Partners, LP
|
|
|
|
|
March 2021
|
4.60% senior notes
|
US$250
|
|
Westcoast Energy Inc.
|
|
|
|
|
October 2021
|
3.88% medium-term notes
|
$150
|
DEBT COVENANTS
Our credit facility agreements and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or termination of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2021, we were in compliance with all debt covenants.
INTEREST EXPENSE
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
Debentures and term notes
|
2,850
|
|
2,913
|
|
2,783
|
|
|
Commercial paper and credit facility draws
|
70
|
|
123
|
|
273
|
|
|
Amortization of fair value adjustment
|
(50)
|
|
(54)
|
|
(67)
|
|
|
Capitalized interest
|
(215)
|
|
(192)
|
|
(326)
|
|
|
|
2,655
|
|
2,790
|
|
2,663
|
|
19. ASSET RETIREMENT OBLIGATIONS
Our ARO relate mostly to the retirement of pipelines, renewable power generation assets and obligations related to right-of way agreements and contractual leases for land use.
The discount rates used to estimate the present value of the expected future cash flows for the year ended December 31, 2021 ranged from 0.9% to 9.0% (2020 - 1.8% to 9.0%).
A reconciliation of movements in our ARO liabilities is as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Obligations at beginning of year
|
496
|
|
520
|
|
|
|
|
|
|
Liabilities disposed
|
—
|
|
—
|
|
|
Liabilities incurred
|
—
|
|
—
|
|
|
Liabilities settled
|
(67)
|
|
(30)
|
|
|
Change in estimate and other
|
70
|
|
—
|
|
|
Foreign currency translation adjustment
|
(3)
|
|
(6)
|
|
|
Accretion expense
|
6
|
|
12
|
|
|
Obligations at end of year
|
502
|
|
496
|
|
|
Presented as follows:
|
|
|
|
Accounts payable and other
|
160
|
|
56
|
|
|
Other long-term liabilities
|
342
|
|
440
|
|
|
|
502
|
|
496
|
|
20. NONCONTROLLING INTERESTS
NONCONTROLLING INTERESTS
The following table provides additional information regarding Noncontrolling interests as presented in our Consolidated Statements of Financial Position:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Algonquin Gas Transmission, L.L.C
|
377
|
|
384
|
|
|
Maritimes & Northeast Pipeline, L.L.C
|
546
|
|
558
|
|
|
|
|
|
|
Renewable energy assets
|
1,503
|
|
1,646
|
|
|
Westcoast Energy Inc.1
|
116
|
|
408
|
|
|
|
|
|
|
|
2,542
|
|
2,996
|
|
1Includes nil and 12 million cumulative redeemable preferred shares as at December 31, 2021 and 2020, respectively.
Westcoast Energy Inc. Preferred Shares Redemption
On March 20, 2019, Westcoast Energy Inc. (Westcoast) exercised its right to redeem all of its outstanding 5.5% Cumulative Redeemable First Preferred Shares, Series 7 (Series 7 Shares) and all of its outstanding 5.6% Cumulative Redeemable First Preferred Shares, Series 8 (Series 8 Shares) at a price of $25 per Series 7 Share and $25 per Series 8 Share, respectively, for a total payment of $300 million. In addition, payment of $4 million was made for all accrued and unpaid dividends. As a result, we recorded a $300 million decrease in Noncontrolling interests for the year ended December 31, 2019.
On January 15, 2021, Westcoast redeemed its Cumulative Five-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 10 with a par value of $115 million. The par value of $115 million was included in Accounts payable and other in the Consolidated Statements of Financial Position as at December 31, 2020.
On October 15, 2021, Westcoast redeemed its Cumulative Five-Year Minimum Rate Reset Redeemable First Preferred Shares, Series 12 with a par value of $300 million. As a result, we recorded a decrease of $293 million, which represents the par value less related issuance costs, in Noncontrolling interests for the year ended December 31, 2021.
21. SHARE CAPITAL
Our authorized share capital consists of an unlimited number of common shares with no par value and an unlimited number of preference shares.
COMMON SHARES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
2020
|
2019
|
|
|
Number
|
|
Number
|
|
Number
|
|
|
December 31,
|
of Shares
|
Amount
|
of Shares
|
Amount
|
of Shares
|
Amount
|
|
(millions of Canadian dollars; number of shares in millions)
|
|
|
|
|
|
|
|
Balance at beginning of year
|
2,026
|
|
64,768
|
|
2,025
|
|
64,746
|
|
2,022
|
|
64,677
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Shares issued on exercise of stock options
|
—
|
|
31
|
|
1
|
|
22
|
|
3
|
|
69
|
|
|
Balance at end of year
|
2,026
|
|
64,799
|
|
2,026
|
|
64,768
|
|
2,025
|
|
64,746
|
|
PREFERENCE SHARES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
2020
|
2019
|
|
|
Number
|
|
Number
|
|
Number
|
|
|
December 31,
|
of Shares
|
Amount
|
of Shares
|
Amount
|
of Shares
|
Amount
|
|
(millions of Canadian dollars; number of shares in millions)
|
|
|
|
|
|
|
|
Preference Shares, Series A
|
5
|
|
125
|
|
5
|
|
125
|
|
5
|
|
125
|
|
|
Preference Shares, Series B
|
18
|
|
457
|
|
18
|
|
457
|
|
18
|
|
457
|
|
|
Preference Shares, Series C
|
2
|
|
43
|
|
2
|
|
43
|
|
2
|
|
43
|
|
|
Preference Shares, Series D
|
18
|
|
450
|
|
18
|
|
450
|
|
18
|
|
450
|
|
|
Preference Shares, Series F
|
20
|
|
500
|
|
20
|
|
500
|
|
20
|
|
500
|
|
|
Preference Shares, Series H
|
14
|
|
350
|
|
14
|
|
350
|
|
14
|
|
350
|
|
|
Preference Shares, Series J
|
8
|
|
199
|
|
8
|
|
199
|
|
8
|
|
199
|
|
|
Preference Shares, Series L
|
16
|
|
411
|
|
16
|
|
411
|
|
16
|
|
411
|
|
|
Preference Shares, Series N
|
18
|
|
450
|
|
18
|
|
450
|
|
18
|
|
450
|
|
|
Preference Shares, Series P
|
16
|
|
400
|
|
16
|
|
400
|
|
16
|
|
400
|
|
|
Preference Shares, Series R
|
16
|
|
400
|
|
16
|
|
400
|
|
16
|
|
400
|
|
|
Preference Shares, Series 1
|
16
|
|
411
|
|
16
|
|
411
|
|
16
|
|
411
|
|
|
Preference Shares, Series 3
|
24
|
|
600
|
|
24
|
|
600
|
|
24
|
|
600
|
|
|
Preference Shares, Series 5
|
8
|
|
206
|
|
8
|
|
206
|
|
8
|
|
206
|
|
|
Preference Shares, Series 7
|
10
|
|
250
|
|
10
|
|
250
|
|
10
|
|
250
|
|
|
Preference Shares, Series 9
|
11
|
|
275
|
|
11
|
|
275
|
|
11
|
|
275
|
|
|
Preference Shares, Series 11
|
20
|
|
500
|
|
20
|
|
500
|
|
20
|
|
500
|
|
|
Preference Shares, Series 13
|
14
|
|
350
|
|
14
|
|
350
|
|
14
|
|
350
|
|
|
Preference Shares, Series 15
|
11
|
|
275
|
|
11
|
|
275
|
|
11
|
|
275
|
|
|
Preference Shares, Series 17
|
30
|
|
750
|
|
30
|
|
750
|
|
30
|
|
750
|
|
|
Preference Shares, Series 19
|
20
|
|
500
|
|
20
|
|
500
|
|
20
|
|
500
|
|
|
Issuance costs
|
|
(155)
|
|
|
(155)
|
|
|
(155)
|
|
|
Balance at end of year
|
|
7,747
|
|
|
7,747
|
|
|
7,747
|
|
Characteristics of the preference shares are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Dividend Rate
|
Dividend1
|
Per Share Base
Redemption
Value2
|
Redemption and
Conversion
Option Date2,3
|
Right to
Convert
Into3,4
|
|
(Canadian dollars unless otherwise stated)
|
|
|
|
|
|
Preference Shares, Series A
|
5.50
|
%
|
$1.37500
|
$25
|
—
|
|
—
|
|
|
Preference Shares, Series B
|
3.42
|
%
|
$0.85360
|
$25
|
June 1, 2022
|
Series C
|
|
Preference Shares, Series C5
|
3-month treasury bill plus 2.40%
|
—
|
|
$25
|
June 1, 2022
|
Series B
|
|
Preference Shares, Series D
|
4.46
|
%
|
$1.11500
|
$25
|
March 1, 2023
|
Series E
|
|
Preference Shares, Series F
|
4.69
|
%
|
$1.17224
|
$25
|
June 1, 2023
|
Series G
|
|
Preference Shares, Series H
|
4.38
|
%
|
$1.09400
|
$25
|
September 1, 2023
|
Series I
|
|
Preference Shares, Series J
|
4.89
|
%
|
US$1.22160
|
US$25
|
June 1, 2022
|
Series K
|
|
Preference Shares, Series L
|
4.96
|
%
|
US$1.23972
|
US$25
|
September 1, 2022
|
Series M
|
|
Preference Shares, Series N
|
5.09
|
%
|
$1.27152
|
$25
|
December 1, 2023
|
Series O
|
|
Preference Shares, Series P
|
4.38
|
%
|
$1.09476
|
$25
|
March 1, 2024
|
Series Q
|
|
Preference Shares, Series R
|
4.07
|
%
|
$1.01825
|
$25
|
June 1, 2024
|
Series S
|
|
Preference Shares, Series 1
|
5.95
|
%
|
US$1.48728
|
US$25
|
June 1, 2023
|
Series 2
|
|
Preference Shares, Series 3
|
3.74
|
%
|
$0.93425
|
$25
|
September 1, 2024
|
Series 4
|
|
Preference Shares, Series 5
|
5.38
|
%
|
US$1.34383
|
US$25
|
March 1, 2024
|
Series 6
|
|
Preference Shares, Series 7
|
4.45
|
%
|
$1.11224
|
$25
|
March 1, 2024
|
Series 8
|
|
Preference Shares, Series 9
|
4.10
|
%
|
$1.02424
|
$25
|
December 1, 2024
|
Series 10
|
|
Preference Shares, Series 11
|
3.94
|
%
|
$0.98452
|
$25
|
March 1, 2025
|
Series 12
|
|
Preference Shares, Series 13
|
3.04
|
%
|
$0.76076
|
$25
|
June 1, 2025
|
Series 14
|
|
Preference Shares, Series 15
|
2.98
|
%
|
$0.74576
|
$25
|
September 1, 2025
|
Series 16
|
|
Preference Shares, Series 17
|
5.15
|
%
|
$1.28750
|
$25
|
March 1, 2022
|
Series 18
|
|
Preference Shares, Series 19
|
4.90
|
%
|
$1.22500
|
$25
|
March 1, 2023
|
Series 20
|
1The holder is entitled to receive a fixed, cumulative, quarterly preferential dividend, as declared by the Board of Directors. With the exception of Series A and Series C Preference Shares, such fixed dividend rate resets every five years beginning on the initial redemption and conversion option date. The Series 17 and Series 19 Preference Shares contain a feature where the fixed dividend rate, when reset every five years, will not be less than 5.15% and 4.90%, respectively. No other series of Preference Shares has this feature.
2Series A Preference Shares may be redeemed any time at our option. For all other series of Preference Shares, we may at our option, redeem all or a portion of the outstanding Preference Shares for the Base Redemption Value per share plus all accrued and unpaid dividends on the Redemption Option Date and on every fifth anniversary thereafter.
3The holder will have the right, subject to certain conditions, to convert their shares into Cumulative Redeemable Preference Shares of a specified series on a one-for-one basis on the Conversion Option Date and every fifth anniversary thereafter at an ascribed issue price equal to the Base Redemption Value.
4With the exception of Series A Preference Shares, after the redemption and conversion option dates, holders may elect to receive quarterly floating rate cumulative dividends per share at a rate equal to: $25 x (number of days in quarter/number of days in a year) x three-month Government of Canada treasury bill rate + 2.4% (Series C), 2.4% (Series E), 2.5% (Series G), 2.1% (Series I), 2.7% (Series O), 2.5% (Series Q), 2.5% (Series S), 2.4% (Series 4), 2.6% (Series 8), 2.7% (Series 10), 2.6% (Series 12), 2.7% (Series 14), 2.7% (Series 16), 4.1% (Series 18) or 3.2% (Series 20); or US$25 x (number of days in quarter/number of days in a year) x three-month US Government treasury bill rate + 3.1% (Series K), 3.2% (Series M), 3.1% (Series 2) or 2.8% (Series 6).
5The floating quarterly dividend amount for the Series C Preference Shares was increased to $0.15501 from $0.15349 on March 1, 2021, was increased to $0.15753 from $0.15501 on June 1, 2021, was increased to $0.16081 from $0.15753 on September 1, 2021 and was decreased to $0.15719 from $0.16081 on December 1, 2021, due to reset on a quarterly basis following the issuance thereof.
PREFERENCE SHARE REDEMPTION
We intend to exercise our right to redeem all of our outstanding cumulative redeemable minimum rate reset preference shares, Series 17, on March 1, 2022 at a price of $25 per Series 17 share, together with all accrued and unpaid dividends, if any.
SHAREHOLDER RIGHTS PLAN
The Shareholder Rights Plan is designed to encourage the fair treatment of our shareholders in connection with any takeover offer. Rights issued under the plan become exercisable when a person and any related parties acquires or announces its intention to acquire 20% or more of our outstanding common shares without complying with certain provisions set out in the plan or without approval of our Board of Directors. Should such an acquisition occur, each rights holder, other than the acquiring person and related parties, will have the right to purchase our common shares at a 50% discount to the market price at that time.
22. STOCK OPTION AND STOCK UNIT PLANS
We maintain three long-term incentive compensation plans: the ISO Plan, the PSU Plan and the RSU Plan. Total stock-based compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 was $157 million, $145 million and $117 million, respectively. Disclosure of activity and assumptions for material stock-based compensation plans are included below.
INCENTIVE STOCK OPTIONS
Certain key employees are granted ISOs to purchase common shares at the grant date market price. ISOs vest in equal annual installments over a four-year period and expire 10 years after the issue date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2021
|
Number
|
Weighted
Average
Exercise
Price
|
Weighted
Average
Remaining
Contractual
Life (years)
|
Aggregate
Intrinsic
Value
|
|
(options in thousands; intrinsic value in millions of Canadian dollars; weighted average exercise price in Canadian dollars)
|
|
|
|
|
|
Options outstanding at beginning of year
|
35,494
|
|
48.65
|
|
|
|
|
Options granted
|
4,072
|
|
43.86
|
|
|
|
|
Options exercised1
|
(4,142)
|
|
41.85
|
|
|
|
|
Options cancelled or expired
|
(1,407)
|
|
50.74
|
|
|
|
|
Options outstanding at end of year
|
34,017
|
|
49.28
|
|
5.7
|
128
|
|
|
Options vested at end of year2
|
22,029
|
|
49.84
|
|
4.5
|
64
|
|
1The total intrinsic value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $24 million, $13 million and $58 million, respectively, and cash received on exercise was $2 million, $4 million and $1 million, respectively.
2The total fair value of ISOs exercised during the years ended December 31, 2021, 2020 and 2019 was $25 million, $30 million and $32 million, respectively.
Weighted average assumptions used to determine the fair value of ISOs granted using the Black-Scholes-Merton option pricing model are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
Fair value per option (Canadian dollars)1
|
4.10
|
|
4.01
|
|
4.37
|
|
|
Valuation assumptions
|
|
|
|
|
Expected option term (years)2
|
6
|
6
|
5
|
|
Expected volatility3
|
25.5
|
%
|
18.3
|
%
|
19.9
|
%
|
|
Expected dividend yield4
|
7.6
|
%
|
5.9
|
%
|
6.1
|
%
|
|
Risk-free interest rate5
|
0.7
|
%
|
1.3
|
%
|
2.0
|
%
|
1Options granted to US employees are based on NYSE prices. The option value and assumptions shown are based on a weighted average of the US and the Canadian options. The fair values per option for the years ended December 31, 2021, 2020 and 2019 were $3.91, $3.75 and $4.04, respectively, for Canadian employees and US$3.65, US$3.62 and US$4.09, respectively, for US employees.
2The expected option term is six years based on historical exercise practice and five years for retirement eligible employees.
3Expected volatility is determined with reference to historic daily share price volatility and consideration of the implied volatility observable in call option values near the grant date.
4The expected dividend yield is the current annual dividend at the grant date divided by the current stock price.
5The risk-free interest rate is based on the Government of Canada’s Canadian Bond Yields and the US Treasury Bond Yields.
Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for ISOs was $16 million, $24 million and $32 million, respectively. As at December 31, 2021, unrecognized compensation expense related to non-vested stock-based compensation arrangements granted under the ISO Plan was $11 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.
PERFORMANCE STOCK UNITS
Under PSU awards for certain key employees, cash awards are paid following a three-year performance cycle. Awards are calculated by multiplying the number of units outstanding at the end of the performance period by Enbridge's weighted average share price for 20 days prior to the maturity of the grant and by a performance multiplier. The performance multiplier ranges from zero, if our performance fails to meet threshold performance levels, to a maximum of two if we perform within the highest range of the performance targets. The performance multiplier is derived through a calculation of our Total Shareholder Return percentile rank, in each case relative to a specified peer group of companies and our distributable cash flow per share, adjusted for unusual, non-operating or non-recurring items, relative to targets established at the time of grant. To calculate the 2021 expense, a multiplier of 0.5 was used for 2021 PSU grants, 0.5 for 2020 PSU grants and 1.3 for the 2019 PSU grants.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2021
|
Number
|
Weighted
Average
Remaining
Contractual
Life (years)
|
Aggregate
Intrinsic
Value
|
|
(units in thousands; intrinsic value in millions of Canadian dollars)
|
|
|
|
|
Units outstanding at beginning of year
|
3,056
|
|
|
|
|
Units granted
|
1,895
|
|
|
|
|
Units cancelled
|
(76)
|
|
|
|
|
Units matured1
|
(1,664)
|
|
|
|
|
Dividend reinvestment
|
218
|
|
|
|
|
Units outstanding at end of year
|
3,429
|
|
1.1
|
181
|
|
1The total amount paid during the years ended December 31, 2021, 2020 and 2019 for PSUs was $70 million, $14 million and $19 million, respectively.
Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for PSUs was $56 million, $76 million and $40 million, respectively. As at December 31, 2021, unrecognized compensation expense related to non-vested PSUs was $31 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.
RESTRICTED STOCK UNITS
Under RSU awards, cash awards are paid to certain of our employees vesting in equal installments on each of the first, second and third anniversaries of the grant date. Share settled awards are given to certain senior management employees following a three year maturity period. RSU holders receive cash or shares equal to our weighted average share price for 20 days prior to the maturity of the grant multiplied by the units outstanding on the maturity date.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2021
|
Number
|
Weighted
Average
Remaining
Contractual Life (years)
|
Aggregate
Intrinsic Value
|
|
(units in thousands; intrinsic value in millions of Canadian dollars)
|
|
|
|
|
Units outstanding at beginning of year
|
2,453
|
|
|
|
|
Units granted
|
1,514
|
|
|
|
|
Units cancelled
|
(75)
|
|
|
|
|
Units matured1
|
(1,433)
|
|
|
|
|
Dividend reinvestment
|
246
|
|
|
|
|
Units outstanding at end of year
|
2,705
|
|
1.1
|
129
|
|
1The total amount paid during the years ended December 31, 2021, 2020 and 2019 for RSUs was $72 million, $27 million and $34 million, respectively.
Compensation expense recorded for the years ended December 31, 2021, 2020 and 2019 for RSUs was $85 million, $44 million and $41 million, respectively. As at December 31, 2021, unrecognized compensation expense related to non-vested RSUs was $62 million. The expense is expected to be fully recognized over a weighted average period of approximately two years.
23. COMPONENTS OF ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)
Changes in AOCI attributable to our common shareholders for the years ended December 31, 2021, 2020 and 2019 are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Hedges
|
Excluded
Components
of Fair Value
Hedges
|
Net
Investment
Hedges
|
Cumulative
Translation
Adjustment
|
Equity
Investees
|
Pension and
OPEB
Adjustment
|
Total
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Balance at January 1, 2021
|
(1,326)
|
|
5
|
|
(215)
|
|
568
|
|
66
|
|
(499)
|
|
(1,401)
|
|
|
Other comprehensive income/(loss) retained in AOCI
|
238
|
|
(5)
|
|
49
|
|
(492)
|
|
(12)
|
|
520
|
|
298
|
|
|
Other comprehensive (income)/loss reclassified to earnings
|
|
|
|
|
|
|
|
|
Interest rate contracts1
|
296
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
296
|
|
|
Commodity contracts2
|
1
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
1
|
|
|
Foreign exchange contracts3
|
5
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
5
|
|
|
Other contracts4
|
2
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
2
|
|
|
Equity investment disposal
|
—
|
|
—
|
|
—
|
|
—
|
|
(66)
|
|
—
|
|
(66)
|
|
|
Amortization of pension and OPEB actuarial loss and prior service costs5
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
28
|
|
28
|
|
|
Other
|
17
|
|
—
|
|
—
|
|
(20)
|
|
3
|
|
—
|
|
—
|
|
|
|
559
|
|
(5)
|
|
49
|
|
(512)
|
|
(75)
|
|
548
|
|
564
|
|
|
Tax impact
|
|
|
|
|
|
|
|
|
Income tax on amounts retained in AOCI
|
(61)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(126)
|
|
(187)
|
|
|
Income tax on amounts reclassified to earnings
|
(69)
|
|
—
|
|
—
|
|
—
|
|
4
|
|
(7)
|
|
(72)
|
|
|
|
(130)
|
|
—
|
|
—
|
|
—
|
|
4
|
|
(133)
|
|
(259)
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2021
|
(897)
|
|
—
|
|
(166)
|
|
56
|
|
(5)
|
|
(84)
|
|
(1,096)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Hedges
|
Excluded
Components
of Fair Value
Hedges
|
Net
Investment
Hedges
|
Cumulative
Translation
Adjustment
|
Equity
Investees
|
Pension and
OPEB
Adjustment
|
Total
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Balance at January 1, 2020
|
(1,073)
|
|
—
|
|
(317)
|
|
1,396
|
|
67
|
|
(345)
|
|
(272)
|
|
|
Other comprehensive income/(loss) retained in AOCI
|
(591)
|
|
5
|
|
115
|
|
(828)
|
|
(2)
|
|
(221)
|
|
(1,522)
|
|
|
Other comprehensive (income)/loss reclassified to earnings
|
|
|
|
|
|
|
|
|
Interest rate contracts1
|
253
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
253
|
|
|
|
|
|
|
|
|
|
|
|
Foreign exchange contracts3
|
5
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
5
|
|
|
Other contracts4
|
(2)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(2)
|
|
|
Amortization of pension and OPEB actuarial loss and prior service costs5
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
17
|
|
17
|
|
|
|
(335)
|
|
5
|
|
115
|
|
(828)
|
|
(2)
|
|
(204)
|
|
(1,249)
|
|
|
Tax impact
|
|
|
|
|
|
|
|
|
Income tax on amounts retained in AOCI
|
140
|
|
—
|
|
(13)
|
|
—
|
|
1
|
|
54
|
|
182
|
|
|
Income tax on amounts reclassified to earnings
|
(58)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(4)
|
|
(62)
|
|
|
|
82
|
|
—
|
|
(13)
|
|
—
|
|
1
|
|
50
|
|
120
|
|
|
|
|
|
|
|
|
|
|
|
Balance at December 31, 2020
|
(1,326)
|
|
5
|
|
(215)
|
|
568
|
|
66
|
|
(499)
|
|
(1,401)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Cash Flow
Hedges
|
Net
Investment
Hedges
|
Cumulative
Translation
Adjustment
|
Equity
Investees
|
Pension and
OPEB
Adjustment
|
Total
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
Balance at January 1, 2019
|
(770)
|
|
(598)
|
|
4,323
|
|
34
|
|
(317)
|
|
2,672
|
|
|
Other comprehensive income/(loss) retained in AOCI
|
(599)
|
|
320
|
|
(2,927)
|
|
34
|
|
(124)
|
|
(3,296)
|
|
|
Other comprehensive (income)/loss reclassified to earnings
|
|
|
|
|
|
|
|
Interest rate contracts1
|
157
|
|
—
|
|
—
|
|
—
|
|
—
|
|
157
|
|
|
Commodity contracts2
|
(1)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(1)
|
|
|
Foreign exchange contracts3
|
5
|
|
—
|
|
—
|
|
—
|
|
—
|
|
5
|
|
|
Other contracts4
|
(3)
|
|
—
|
|
—
|
|
—
|
|
—
|
|
(3)
|
|
|
Amortization of pension and OPEB actuarial loss and prior service costs5
|
—
|
|
—
|
|
—
|
|
—
|
|
17
|
|
17
|
|
|
|
|
|
|
|
|
|
|
|
(441)
|
|
320
|
|
(2,927)
|
|
34
|
|
(107)
|
|
(3,121)
|
|
|
Tax impact
|
|
|
|
|
|
|
|
Income tax on amounts retained in AOCI
|
169
|
|
(39)
|
|
—
|
|
6
|
|
28
|
|
164
|
|
|
Income tax on amounts reclassified to earnings
|
(31)
|
|
—
|
|
—
|
|
—
|
|
(4)
|
|
(35)
|
|
|
|
|
|
|
|
|
|
|
|
138
|
|
(39)
|
|
—
|
|
6
|
|
24
|
|
129
|
|
|
Other
|
—
|
|
—
|
|
—
|
|
(7)
|
|
55
|
|
48
|
|
|
Balance at December 31, 2019
|
(1,073)
|
|
(317)
|
|
1,396
|
|
67
|
|
(345)
|
|
(272)
|
|
1Reported within Interest expense in the Consolidated Statements of Earnings.
2Reported within Transportation and other services revenue, Commodity sales revenue, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
3Reported within Transportation and other services revenue and Net foreign currency gain in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
5These components are included in the computation of net benefit costs and are reported within Other income/(expense) in the Consolidated Statements of Earnings.
24. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
MARKET RISK
Our earnings, cash flows and OCI are subject to movements in foreign exchange rates, interest rates, commodity prices and our share price (collectively, market risks). Formal risk management policies, processes and systems have been designed to mitigate these risks.
The following summarizes the types of market risks to which we are exposed and the risk management instruments used to mitigate them. We use a combination of qualifying and non-qualifying derivative instruments to manage the risks noted below.
Foreign Exchange Risk
We generate certain revenues, incur expenses and hold a number of investments and subsidiaries that are denominated in currencies other than Canadian dollars. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from foreign exchange rate variability.
We employ financial derivative instruments to hedge foreign currency denominated earnings exposure. A combination of qualifying and non-qualifying derivative instruments is used to hedge anticipated foreign currency denominated revenues and expenses and to manage variability in cash flows. We hedge certain net investments in US dollar denominated investments and subsidiaries using foreign currency derivatives and US dollar denominated debt.
Interest Rate Risk
Our earnings and cash flows are exposed to short-term interest rate variability due to the regular repricing of our variable rate debt, primarily commercial paper. We monitor our debt portfolio mix of fixed and variable rate debt instruments to manage a consolidated portfolio of floating rate debt within the Board of Directors approved policy limit of a maximum of 30% of floating rate debt as a percentage of total debt outstanding. We primarily use qualifying derivative instruments to manage interest rate risk. Pay fixed-receive floating interest rate swaps may be used to hedge against the effect of future interest rate movements. We have implemented a program to mitigate the impact of short-term interest rate volatility on interest expense via execution of floating to fixed interest rate swaps with an average swap rate of 3.9%.
We are exposed to changes in the fair value of fixed rate debt that arise as a result of changes in market interest rates. Pay floating-receive fixed interest rate swaps are used, when applicable, to hedge against future changes to the fair value of fixed rate debt which mitigates the impact of fluctuations in fair value via execution of fixed to floating interest rate swaps. As at December 31, 2021, we do not have any pay floating-receive fixed interest rate swaps outstanding.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate term debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have established a program including some of our subsidiaries to mitigate our exposure to long-term interest rate variability on select forecast term debt issuances via execution of floating to fixed interest rate swaps with an average swap rate of 2.0%.
Commodity Price Risk
Our earnings and cash flows are exposed to changes in commodity prices as a result of our ownership interests in certain assets and investments, as well as through the activities of our energy services subsidiaries. These commodities include natural gas, crude oil, power and NGL. We employ financial and physical derivative instruments to fix a portion of the variable price exposures that arise from physical transactions involving these commodities. We use primarily non-qualifying derivative instruments to manage commodity price risk.
Equity Price Risk
Equity price risk is the risk of earnings fluctuations due to changes in our share price. We have exposure to our own common share price through the issuance of various forms of stock-based compensation, which affect earnings through revaluation of the outstanding units every period. We use equity derivatives to manage the earnings volatility derived from one form of stock-based compensation, restricted share units. We use a combination of qualifying and non-qualifying derivative instruments to manage equity price risk.
TOTAL DERIVATIVE INSTRUMENTS
The following table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments.
We generally have a policy of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our financial derivative counterparties. These agreements provide for the net settlement of derivative instruments outstanding with specific counterparties in the event of bankruptcy or other significant credit events and reduce our credit risk exposure on financial derivative asset positions outstanding with the counterparties in those circumstances.
The following table summarizes the maximum potential settlement amounts in the event of these specific circumstances. All amounts are presented gross in the Consolidated Statements of Financial Position.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2021
|
Derivative
Instruments
Used as
Cash Flow Hedges
|
Derivative
Instruments
Used as Net
Investment Hedges
|
Derivative
Instruments
Used as
Fair Value Hedges
|
Non-
Qualifying
Derivative Instruments
|
Total Gross
Derivative
Instruments as Presented
|
Amounts
Available for Offset
|
Total Net
Derivative Instruments
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Accounts receivable and other
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
—
|
|
—
|
|
259
|
|
259
|
|
(41)
|
|
218
|
|
|
Interest rate contracts
|
64
|
|
—
|
|
—
|
|
—
|
|
64
|
|
—
|
|
64
|
|
|
Commodity contracts
|
—
|
|
—
|
|
—
|
|
204
|
|
204
|
|
(129)
|
|
75
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
2
|
|
2
|
|
—
|
|
2
|
|
|
|
64
|
|
—
|
|
—
|
|
465
|
|
529
|
|
(170)
|
|
359
|
|
|
Deferred amounts and other assets
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
—
|
|
—
|
|
240
|
|
240
|
|
(61)
|
|
179
|
|
|
Interest rate contracts
|
88
|
|
—
|
|
—
|
|
—
|
|
88
|
|
(1)
|
|
87
|
|
|
Commodity contracts
|
—
|
|
—
|
|
—
|
|
29
|
|
29
|
|
(13)
|
|
16
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
3
|
|
3
|
|
—
|
|
3
|
|
|
|
88
|
|
—
|
|
—
|
|
272
|
|
360
|
|
(75)
|
|
285
|
|
|
Accounts payable and other
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
(15)
|
|
—
|
|
(112)
|
|
(176)
|
|
(303)
|
|
41
|
|
(262)
|
|
|
Interest rate contracts
|
(150)
|
|
—
|
|
—
|
|
—
|
|
(150)
|
|
—
|
|
(150)
|
|
|
Commodity contracts
|
(14)
|
|
—
|
|
—
|
|
(250)
|
|
(264)
|
|
129
|
|
(135)
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
(179)
|
|
—
|
|
(112)
|
|
(426)
|
|
(717)
|
|
170
|
|
(547)
|
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
—
|
|
—
|
|
(423)
|
|
(423)
|
|
61
|
|
(362)
|
|
|
Interest rate contracts
|
(1)
|
|
—
|
|
—
|
|
(23)
|
|
(24)
|
|
1
|
|
(23)
|
|
|
Commodity contracts
|
(17)
|
|
—
|
|
—
|
|
(67)
|
|
(84)
|
|
13
|
|
(71)
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
(18)
|
|
—
|
|
—
|
|
(513)
|
|
(531)
|
|
75
|
|
(456)
|
|
|
Total net derivative asset/(liability)
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
(15)
|
|
—
|
|
(112)
|
|
(100)
|
|
(227)
|
|
—
|
|
(227)
|
|
|
Interest rate contracts
|
1
|
|
—
|
|
—
|
|
(23)
|
|
(22)
|
|
—
|
|
(22)
|
|
|
Commodity contracts
|
(31)
|
|
—
|
|
—
|
|
(84)
|
|
(115)
|
|
—
|
|
(115)
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
5
|
|
5
|
|
—
|
|
5
|
|
|
|
(45)
|
|
—
|
|
(112)
|
|
(202)
|
|
(359)
|
|
—
|
|
(359)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
Derivative
Instruments
Used as
Cash Flow Hedges
|
Derivative
Instruments
Used as Net Investment Hedges
|
Derivative
Instruments
Used as Fair Value Hedges
|
Non-
Qualifying
Derivative Instruments
|
Total Gross
Derivative
Instruments as Presented
|
Amounts
Available for Offset
|
Total Net
Derivative Instruments
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Accounts receivable and other
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
—
|
|
—
|
|
180
|
|
180
|
|
(28)
|
|
152
|
|
|
Interest rate contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Commodity contracts
|
—
|
|
—
|
|
—
|
|
143
|
|
143
|
|
(81)
|
|
62
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
—
|
|
—
|
|
—
|
|
323
|
|
323
|
|
(109)
|
|
214
|
|
|
Deferred amounts and other assets
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
14
|
|
—
|
|
—
|
|
452
|
|
466
|
|
(218)
|
|
248
|
|
|
Interest rate contracts
|
56
|
|
—
|
|
—
|
|
—
|
|
56
|
|
(25)
|
|
31
|
|
|
Commodity contracts
|
—
|
|
—
|
|
—
|
|
39
|
|
39
|
|
(9)
|
|
30
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
70
|
|
—
|
|
—
|
|
491
|
|
561
|
|
(252)
|
|
309
|
|
|
Accounts payable and other
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
(5)
|
|
—
|
|
(29)
|
|
(151)
|
|
(185)
|
|
28
|
|
(157)
|
|
|
Interest rate contracts
|
(423)
|
|
—
|
|
—
|
|
(2)
|
|
(425)
|
|
—
|
|
(425)
|
|
|
Commodity contracts
|
(2)
|
|
—
|
|
—
|
|
(278)
|
|
(280)
|
|
81
|
|
(199)
|
|
|
Other contracts
|
(1)
|
|
—
|
|
—
|
|
(3)
|
|
(4)
|
|
—
|
|
(4)
|
|
|
|
(431)
|
|
—
|
|
(29)
|
|
(434)
|
|
(894)
|
|
109
|
|
(785)
|
|
|
Other long-term liabilities
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
—
|
|
(87)
|
|
(673)
|
|
(760)
|
|
218
|
|
(542)
|
|
|
Interest rate contracts
|
(218)
|
|
—
|
|
—
|
|
(23)
|
|
(241)
|
|
25
|
|
(216)
|
|
|
Commodity contracts
|
(1)
|
|
—
|
|
—
|
|
(57)
|
|
(58)
|
|
9
|
|
(49)
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
(219)
|
|
—
|
|
(87)
|
|
(753)
|
|
(1,059)
|
|
252
|
|
(807)
|
|
|
Total net derivative asset/(liability)
|
|
|
|
|
|
|
|
|
Foreign exchange contracts
|
9
|
|
—
|
|
(116)
|
|
(192)
|
|
(299)
|
|
—
|
|
(299)
|
|
|
Interest rate contracts
|
(585)
|
|
—
|
|
—
|
|
(25)
|
|
(610)
|
|
—
|
|
(610)
|
|
|
Commodity contracts
|
(3)
|
|
—
|
|
—
|
|
(153)
|
|
(156)
|
|
—
|
|
(156)
|
|
|
Other contracts
|
(1)
|
|
—
|
|
—
|
|
(3)
|
|
(4)
|
|
—
|
|
(4)
|
|
|
|
(580)
|
|
—
|
|
(116)
|
|
(373)
|
|
(1,069)
|
|
—
|
|
(1,069)
|
|
The following table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
|
|
|
2020
|
|
|
As at December 31,
|
2022
|
2023
|
2024
|
2025
|
2026
|
Thereafter
|
|
Total
|
|
Total
|
|
|
Foreign exchange contracts - US dollar forwards - purchase (millions of US dollars)
|
2,508
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
2,508
|
|
|
3,522
|
|
|
|
Foreign exchange contracts - US dollar forwards - sell (millions of US dollars)
|
9,245
|
|
5,596
|
|
4,346
|
|
3,174
|
|
2,574
|
|
492
|
|
|
25,427
|
|
|
17,859
|
|
|
|
Foreign exchange contracts - British pound (GBP) forwards - sell (millions of GBP)
|
28
|
|
29
|
|
30
|
|
30
|
|
28
|
|
32
|
|
|
177
|
|
|
265
|
|
|
|
Foreign exchange contracts - Euro forwards - sell (millions of Euro)
|
104
|
|
92
|
|
91
|
|
86
|
|
85
|
|
343
|
|
|
801
|
|
|
885
|
|
|
|
Foreign exchange contracts - Japanese yen forwards - purchase (millions of yen)
|
72,500
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
72,500
|
|
|
72,500
|
|
|
|
Interest rate contracts - short-term pay fixed rate (millions of Canadian dollars)
|
395
|
|
47
|
|
35
|
|
30
|
|
26
|
|
64
|
|
|
597
|
|
|
4,635
|
|
|
|
Interest rate contracts - long-term pay fixed rate (millions of Canadian dollars)
|
2,363
|
|
1,784
|
|
1,132
|
|
—
|
|
—
|
|
—
|
|
|
5,279
|
|
|
5,396
|
|
|
|
Equity contracts (millions of Canadian dollars)
|
20
|
|
26
|
|
21
|
|
—
|
|
—
|
|
—
|
|
|
67
|
|
|
62
|
|
|
|
Commodity contracts - natural gas (billions of cubic feet)
|
165
|
|
18
|
|
5
|
|
11
|
|
—
|
|
—
|
|
|
199
|
|
|
173
|
|
|
|
Commodity contracts - crude oil (millions of barrels)
|
12
|
|
—
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
12
|
|
|
15
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Commodity contracts - power (megawatt per hour (MW/H)
|
(43)
|
|
(43)
|
|
(43)
|
|
(43)
|
|
—
|
|
—
|
|
|
(43)
|
|
1
|
(35)
|
|
1
|
1Total is an average net purchase/(sell) of power.
The Effect of Derivative Instruments on the Statements of Earnings and Comprehensive Income
The following table presents the effect of cash flow hedges and net investment hedges on our consolidated earnings and consolidated comprehensive income, before the effect of income taxes:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
Amount of unrealized gain/(loss) recognized in OCI
|
|
|
|
|
Cash flow hedges
|
|
|
|
|
Foreign exchange contracts
|
(29)
|
|
(1)
|
|
(19)
|
|
|
Interest rate contracts
|
252
|
|
(595)
|
|
(559)
|
|
|
Commodity contracts
|
(28)
|
|
2
|
|
(25)
|
|
|
Other contracts
|
1
|
|
(3)
|
|
10
|
|
|
Fair value hedges
|
|
|
|
|
Foreign exchange contracts
|
(5)
|
|
5
|
|
—
|
|
|
Net investment hedges
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
13
|
|
2
|
|
|
|
191
|
|
(579)
|
|
(591)
|
|
|
Amount of (gain)/loss reclassified from AOCI to earnings
|
|
|
|
|
Foreign exchange contracts1
|
5
|
|
5
|
|
5
|
|
|
Interest rate contracts2
|
296
|
|
253
|
|
157
|
|
|
Commodity contracts3
|
1
|
|
—
|
|
(1)
|
|
|
Other contracts4
|
2
|
|
(2)
|
|
(3)
|
|
|
|
304
|
|
256
|
|
158
|
|
1Reported within Transportation and other services revenues and Net foreign currency gain/(loss) in the Consolidated Statements of Earnings.
2Reported within Interest expense in the Consolidated Statements of Earnings.
3Reported within Transportation and other services revenue, Commodity sales revenues, Commodity costs and Operating and administrative expense in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expenses in the Consolidated Statements of Earnings.
We estimate that a loss of $47 million from AOCI related to cash flow hedges will be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the foreign exchange rates, interest rates and commodity prices in effect when derivative contracts that are currently outstanding mature. For all forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 36 months as at December 31, 2021.
Fair Value Derivatives
For interest rate derivative instruments that are designated and qualify as fair value hedges, the gain or loss on the derivative as well as the offsetting loss or gain on the hedged item attributable to the hedged risk is included in Interest expense in the Consolidated Statements of Earnings.
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Unrealized gain/(loss) on derivative
|
8
|
|
(116)
|
|
|
Unrealized gain/(loss) on hedged item
|
(15)
|
|
133
|
|
|
Realized loss on derivative
|
(41)
|
|
(12)
|
|
|
Realized gain on hedged item
|
45
|
|
—
|
|
Non-Qualifying Derivatives
The following table presents the unrealized gains and losses associated with changes in the fair value of our non-qualifying derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
Foreign exchange contracts1
|
92
|
|
902
|
|
1,626
|
|
|
Interest rate contracts2
|
2
|
|
(25)
|
|
178
|
|
|
Commodity contracts3
|
71
|
|
(114)
|
|
(62)
|
|
|
Other contracts4
|
8
|
|
(7)
|
|
9
|
|
|
Total unrealized derivative fair value gain/(loss), net
|
173
|
|
756
|
|
1,751
|
|
1For the respective annual periods, reported within Transportation and other services revenue (2021 - $98 million gain; 2020 - $533 million gain; 2019 - $930 million gain) and Net foreign currency gain/(loss) (2021 - $6 million loss; 2020 - $369 million gain; 2019 - $696 million gain) in the Consolidated Statements of Earnings.
2Reported as an increase within Interest expense in the Consolidated Statements of Earnings.
3For the respective annual periods, reported within Transportation and other services revenue (2021 - $9 million gain; 2020 - $2 million loss; 2019 - $26 million loss), Commodity sales (2021 - $160 million gain; 2020 - $321 million loss; 2019 - $544 million loss), Commodity costs (2021 - $105 million loss; 2020 - $207 million gain; 2019 - $459 million gain) and Operating and administrative expense (2021 - $7 million gain; 2020 - $2 million gain; 2019 - $49 million gain) in the Consolidated Statements of Earnings.
4Reported within Operating and administrative expense in the Consolidated Statements of Earnings.
LIQUIDITY RISK
Liquidity risk is the risk that we will not be able to meet our financial obligations, including commitments and guarantees, as they become due. In order to mitigate this risk, we forecast cash requirements over a 12-month rolling time period to determine whether sufficient funds will be available and maintain substantial capacity under our committed bank lines of credit to address any contingencies. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper and draws under committed credit facilities and long-term debt, which includes debentures and medium-term notes. We also maintain current shelf prospectuses with securities regulators which enables ready access to either the Canadian or US public capital markets, subject to market conditions. In addition, we maintain sufficient liquidity through committed credit facilities with a diversified group of banks and institutions which, if necessary, enables us to fund all anticipated requirements for approximately one year without accessing the capital markets. We are in compliance with all the terms and conditions of our committed credit facility agreements and term debt indentures as at December 31, 2021. As a result, all credit facilities are available to us and the banks are obligated to fund and have been funding us under the terms of the facilities.
CREDIT RISK
Entering into derivative instruments may result in exposure to credit risk from the possibility that a counterparty will default on its contractual obligations. In order to mitigate this risk, we enter into risk management transactions primarily with institutions that possess strong investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated through maintenance and monitoring of credit exposure limits and contractual requirements, netting arrangements, and ongoing monitoring of counterparty credit exposure using external credit rating services and other analytical tools.
We have credit concentrations and credit exposure, with respect to derivative instruments, in the following counterparty segments:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Canadian financial institutions
|
424
|
|
481
|
|
|
US financial institutions
|
130
|
|
99
|
|
|
European financial institutions
|
181
|
|
28
|
|
|
Asian financial institutions
|
30
|
|
167
|
|
|
Other1
|
122
|
|
97
|
|
|
|
887
|
|
872
|
|
1Other is comprised of commodity clearing house and physical natural gas and crude oil counterparties.
As at December 31, 2021, we provided letters of credit totaling nil in lieu of providing cash collateral to our counterparties pursuant to the terms of the relevant International Swaps and Derivatives Association agreements. We held no cash collateral on derivative asset exposures as at December 31, 2021 and December 31, 2020.
Gross derivative balances have been presented without the effects of collateral posted. Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates, and are reflected at fair value. For derivative liabilities, our non-performance risk is considered in the valuation.
Credit risk also arises from trade and other long-term receivables, and is mitigated through credit exposure limits and contractual requirements, assessment of credit ratings and netting arrangements. Within Enbridge Gas, credit risk is mitigated by the utilities' large and diversified customer base and the ability to recover an estimate for doubtful accounts through the ratemaking process. We actively monitor the financial strength of large industrial customers and, in select cases, have obtained additional security to minimize the risk of default on receivables. Generally, we classify and provide for receivables older than 30 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.
FAIR VALUE MEASUREMENTS
Our financial assets and liabilities measured at fair value on a recurring basis include derivative instruments. We also disclose the fair value of other financial instruments not measured at fair value. The fair value of financial instruments reflects our best estimates of market value based on generally accepted valuation techniques or models and is supported by observable market prices and rates. When such values are not available, we use discounted cash flow analysis from applicable yield curves based on observable market inputs to estimate fair value.
FAIR VALUE OF FINANCIAL INSTRUMENTS
We categorize our derivative instruments measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement.
Level 1
Level 1 includes derivatives measured at fair value based on unadjusted quoted prices for identical assets and liabilities in active markets that are accessible at the measurement date. An active market for a derivative is considered to be a market where transactions occur with sufficient frequency and volume to provide pricing information on an ongoing basis. Our Level 1 instruments consist primarily of exchange traded derivatives used to mitigate the risk of crude oil price fluctuations.
Level 2
Level 2 includes derivative valuations determined using directly or indirectly observable inputs other than quoted prices included within Level 1. Derivatives in this category are valued using models or other industry standard valuation techniques derived from observable market data. Such valuation techniques include inputs such as quoted forward prices, time value, volatility factors and broker quotes that can be observed or corroborated in the market for the entire duration of the derivative. Derivatives valued using Level 2 inputs include non-exchange traded derivatives such as over-the-counter foreign exchange forward and cross currency swap contracts, interest rate swaps, physical forward commodity contracts, as well as commodity swaps for which observable inputs can be obtained.
We have also categorized the fair value of our held to maturity preferred share investment and long-term debt as Level 2. The fair value of our held to maturity preferred share investment is primarily based on the yield of certain Government of Canada bonds. The fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor.
Level 3
Level 3 includes derivative valuations based on inputs which are less observable, unavailable or where the observable data does not support a significant portion of the derivatives’ fair value. Generally, Level 3 derivatives are longer dated transactions, occur in less active markets, occur at locations where pricing information is not available or have no binding broker quote to support Level 2 classification. We have developed methodologies, benchmarked against industry standards, to determine fair value for these derivatives based on extrapolation of observable future prices and rates. Derivatives valued using Level 3 inputs primarily include long-dated derivative power contracts and NGL and natural gas contracts, basis swaps, commodity swaps, power and energy swaps, as well as physical forward commodity contracts. We do not have any other financial instruments categorized in Level 3.
We use the most observable inputs available to estimate the fair value of our derivatives. When possible, we estimate the fair value of our derivatives based on quoted market prices. If quoted market prices are not available, we use estimates from third party brokers. For non-exchange traded derivatives classified in Levels 2 and 3, we use standard valuation techniques to calculate the estimated fair value. These methods include discounted cash flows for forwards and swaps and Black-Scholes-Merton pricing models for options. Depending on the type of derivative and nature of the underlying risk, we use observable market prices (interest, foreign exchange, commodity and share price) and volatility as primary inputs to these valuation techniques. Finally, we consider our own credit default swap spread as well as the credit default swap spreads associated with our counterparties in our estimation of fair value.
We have categorized our derivative assets and liabilities measured at fair value as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2021
|
Level 1
|
Level 2
|
Level 3
|
Total Gross Derivative Instruments
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
Financial assets
|
|
|
|
|
|
Current derivative assets
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
259
|
|
—
|
|
259
|
|
|
Interest rate contracts
|
—
|
|
64
|
|
—
|
|
64
|
|
|
Commodity contracts
|
38
|
|
71
|
|
95
|
|
204
|
|
|
Other contracts
|
—
|
|
2
|
|
—
|
|
2
|
|
|
|
38
|
|
396
|
|
95
|
|
529
|
|
|
Long-term derivative assets
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
240
|
|
—
|
|
240
|
|
|
Interest rate contracts
|
—
|
|
88
|
|
—
|
|
88
|
|
|
Commodity contracts
|
—
|
|
21
|
|
8
|
|
29
|
|
|
Other contracts
|
—
|
|
3
|
|
—
|
|
3
|
|
|
|
—
|
|
352
|
|
8
|
|
360
|
|
|
Financial liabilities
|
|
|
|
|
|
Current derivative liabilities
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
(303)
|
|
—
|
|
(303)
|
|
|
Interest rate contracts
|
—
|
|
(150)
|
|
—
|
|
(150)
|
|
|
Commodity contracts
|
(52)
|
|
(66)
|
|
(146)
|
|
(264)
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
(52)
|
|
(519)
|
|
(146)
|
|
(717)
|
|
|
Long-term derivative liabilities
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
(423)
|
|
—
|
|
(423)
|
|
|
Interest rate contracts
|
—
|
|
(24)
|
|
—
|
|
(24)
|
|
|
Commodity contracts
|
—
|
|
(19)
|
|
(65)
|
|
(84)
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
—
|
|
(466)
|
|
(65)
|
|
(531)
|
|
|
Total net financial asset/(liability)
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
(227)
|
|
—
|
|
(227)
|
|
|
Interest rate contracts
|
—
|
|
(22)
|
|
—
|
|
(22)
|
|
|
Commodity contracts
|
(14)
|
|
7
|
|
(108)
|
|
(115)
|
|
|
Other contracts
|
—
|
|
5
|
|
—
|
|
5
|
|
|
|
(14)
|
|
(237)
|
|
(108)
|
|
(359)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2020
|
Level 1
|
Level 2
|
Level 3
|
Total Gross Derivative Instruments
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
Financial assets
|
|
|
|
|
|
Current derivative assets
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
180
|
|
—
|
|
180
|
|
|
Interest rate contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Commodity contracts
|
43
|
|
33
|
|
67
|
|
143
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
43
|
|
213
|
|
67
|
|
323
|
|
|
Long-term derivative assets
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
466
|
|
—
|
|
466
|
|
|
Interest rate contracts
|
—
|
|
56
|
|
—
|
|
56
|
|
|
Commodity contracts
|
1
|
|
24
|
|
14
|
|
39
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
1
|
|
546
|
|
14
|
|
561
|
|
|
Financial liabilities
|
|
|
|
|
|
Current derivative liabilities
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
(185)
|
|
—
|
|
(185)
|
|
|
Interest rate contracts
|
—
|
|
(425)
|
|
—
|
|
(425)
|
|
|
Commodity contracts
|
(39)
|
|
(18)
|
|
(223)
|
|
(280)
|
|
|
Other contracts
|
—
|
|
(4)
|
|
—
|
|
(4)
|
|
|
|
(39)
|
|
(632)
|
|
(223)
|
|
(894)
|
|
|
Long-term derivative liabilities
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
(760)
|
|
—
|
|
(760)
|
|
|
Interest rate contracts
|
—
|
|
(241)
|
|
—
|
|
(241)
|
|
|
Commodity contracts
|
(1)
|
|
(8)
|
|
(49)
|
|
(58)
|
|
|
Other contracts
|
—
|
|
—
|
|
—
|
|
—
|
|
|
|
(1)
|
|
(1,009)
|
|
(49)
|
|
(1,059)
|
|
|
Total net financial asset/(liability)
|
|
|
|
|
|
Foreign exchange contracts
|
—
|
|
(299)
|
|
—
|
|
(299)
|
|
|
Interest rate contracts
|
—
|
|
(610)
|
|
—
|
|
(610)
|
|
|
Commodity contracts
|
4
|
|
31
|
|
(191)
|
|
(156)
|
|
|
Other contracts
|
—
|
|
(4)
|
|
—
|
|
(4)
|
|
|
|
4
|
|
(882)
|
|
(191)
|
|
(1,069)
|
|
The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2021
|
Fair Value
|
Unobservable Input
|
Minimum Price
|
Maximum Price
|
Weighted Average Price
|
Unit of Measurement
|
|
(fair value in millions of Canadian dollars)
|
|
|
|
|
|
|
|
Commodity contracts - financial1
|
|
|
|
|
|
|
|
Natural gas
|
(19)
|
|
Forward gas price
|
3.12
|
9.05
|
4.49
|
$/mmbtu2
|
|
Crude
|
3
|
|
Forward crude price
|
76.02
|
98.99
|
91.73
|
$/barrel
|
|
|
|
|
|
|
|
|
|
Power
|
(60)
|
|
Forward power price
|
31.00
|
125.13
|
76.23
|
$/MW/H
|
|
Commodity contracts - physical1
|
|
|
|
|
|
|
|
Natural gas
|
(56)
|
|
Forward gas price
|
2.65
|
9.25
|
4.63
|
$/mmbtu2
|
|
Crude
|
24
|
|
Forward crude price
|
68.66
|
97.00
|
87.97
|
$/barrel
|
|
|
|
|
|
|
|
|
|
|
(108)
|
|
|
|
|
|
|
1Financial and physical forward commodity contracts are valued using a market approach valuation technique.
2One million British thermal units (mmbtu).
If adjusted, the significant unobservable inputs disclosed in the table above would have a direct impact on the fair value of our Level 3 derivative instruments. The significant unobservable inputs used in the fair value measurement of Level 3 derivative instruments include forward commodity prices, and for option contracts, price volatility. Changes in forward commodity prices could result in significantly different fair values for our Level 3 derivatives. Changes in price volatility would change the value of the option contracts. Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of price volatility.
Changes in net fair value of derivative assets and liabilities classified as Level 3 in the fair value hierarchy were as follows:
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Level 3 net derivative liability at beginning of period
|
(191)
|
|
(69)
|
|
|
Total gain/(loss)
|
|
|
|
Included in earnings1
|
(39)
|
|
(123)
|
|
|
Included in OCI
|
(29)
|
|
2
|
|
|
Settlements
|
151
|
|
(1)
|
|
|
Level 3 net derivative liability at end of period
|
(108)
|
|
(191)
|
|
1Reported within Transportation and other services revenue, Commodity costs and Operating and administrative expenses in the Consolidated Statements of Earnings.
There were no transfers into or out of Level 3 as at December 31, 2021 or 2020.
NET INVESTMENT HEDGES
We have designated a portion of our US dollar denominated debt, as well as a portfolio of foreign exchange forward contracts, as a hedge of our net investment in US dollar denominated investments and subsidiaries.
During the years ended December 31, 2021 and 2020, we recognized unrealized foreign exchange gains of $49 million and $117 million, respectively, on the translation of US dollar denominated debt and an unrealized gain on the change in fair value of our outstanding foreign exchange forward contracts of nil and $13 million, respectively, in OCI. During the years ended December 31, 2021 and 2020, we recognized a realized loss of nil and $15 million, respectively, in OCI associated with the settlement of foreign exchange forward contracts. No realized gains or losses associated with the settlement of US dollar denominated debt that had matured during the period were recognized in OCI during the years ended December 31, 2021 and 2020.
FAIR VALUE OF OTHER FINANCIAL INSTRUMENTS
Certain long-term investments in other entities with no actively quoted prices are classified as FVMA investments and are recorded at cost less impairment. The carrying value of FVMA investments totaled $52 million as at December 31, 2021 and 2020.
We have Restricted long-term investments held in trust totaling $630 million and $553 million as at December 31, 2021 and 2020, respectively, which are recognized at fair value.
As at December 31, 2021 and 2020, our long-term debt had a carrying value of $74.4 billion and $66.1 billion, respectively, before debt issuance costs and a fair value of $82.0 billion and $75.1 billion, respectively. We also have non-current notes receivable carried at book value and recorded in Deferred amounts and other assets in the Consolidated Statements of Financial Position. As at December 31, 2021 and 2020, the non-current notes receivable had a carrying value of $1.0 billion and $1.1 billion, respectively, which also approximates their fair value.
The fair value of other financial assets and liabilities other than derivative instruments, other long-term investments, restricted long-term investments and long-term debt approximate their cost due to the short period to maturity.
25. INCOME TAXES
INCOME TAX RATE RECONCILIATION
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
Earnings before income taxes
|
7,729
|
4,190
|
|
7,535
|
|
|
Canadian federal statutory income tax rate
|
15
|
%
|
15
|
%
|
15
|
%
|
|
Expected federal taxes at statutory rate
|
1,159
|
629
|
|
1,130
|
|
|
Increase/(decrease) resulting from:
|
|
|
|
|
Provincial and state income taxes1
|
228
|
|
288
|
|
415
|
|
|
Foreign and other statutory rate differentials2
|
134
|
|
(53)
|
|
129
|
|
|
|
|
|
|
|
Effects of rate-regulated accounting3
|
(139)
|
|
(145)
|
|
(63)
|
|
|
Foreign allowable interest deductions4
|
—
|
|
(4)
|
|
(29)
|
|
|
Part VI.1 tax, net of federal Part I deduction5
|
73
|
|
76
|
|
78
|
|
|
|
|
|
|
|
US Minimum Tax6
|
—
|
|
44
|
|
67
|
|
|
Non-taxable portion of gain on sale of investment7
|
(23)
|
|
—
|
|
—
|
|
|
Valuation allowance8
|
5
|
|
(6)
|
|
26
|
|
|
Intercorporate investments9
|
—
|
|
—
|
|
(14)
|
|
|
Noncontrolling interests
|
(17)
|
|
(8)
|
|
(13)
|
|
|
Other
|
(5)
|
|
(47)
|
|
(18)
|
|
|
Income tax expense
|
1,415
|
|
774
|
|
1,708
|
|
|
Effective income tax rate
|
18.3%
|
18.5%
|
22.7%
|
1 The change in provincial and state income taxes from 2020 to 2021 reflects the 2020 impact of state tax apportionment and rate changes in both the US and Canada offset by the increase in earnings from US and Canadian operations in 2021.
2 The change in foreign and other statutory rate differentials from 2020 to 2021 reflects the increase in earnings from US operations partially offset by higher rate benefits from foreign operations.
3 The amount in 2019 included the federal component of the tax benefit of the write-off of regulatory assets.
4 The decrease in foreign allowable interest deductions from 2019 to 2021 was due to changes in the related loan portfolio.
5 Part VI.1 tax is a tax levied on preferred share dividends paid in Canada.
6 There was no US Minimum Tax in 2021 as a result of tax losses from bonus tax depreciation.
7 The amount in 2021 relates to the federal impact of the gain on sale of the investment in Noverco.
8 The increase in 2021 is due to the federal component of the tax effect of a valuation allowance on additional deferred tax assets that are not more likely than not to be realized.
9 The amount in 2019 relates to the federal component of changes in assertions regarding the manner of recovery of intercorporate investments such that deferred tax related to outside basis temporary differences was required to be recorded for MATL.
COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
Earnings before income taxes
|
|
|
|
|
Canada
|
3,399
|
|
2,789
|
|
3,560
|
|
|
US
|
3,336
|
|
407
|
|
3,115
|
|
|
Other
|
994
|
|
994
|
|
860
|
|
|
|
7,729
|
|
4,190
|
|
7,535
|
|
|
Current income taxes
|
|
|
|
|
Canada
|
162
|
|
165
|
|
347
|
|
|
US
|
80
|
|
64
|
|
107
|
|
|
Other
|
82
|
|
98
|
|
98
|
|
|
|
324
|
|
327
|
|
552
|
|
|
Deferred income taxes
|
|
|
|
|
Canada
|
344
|
|
378
|
|
490
|
|
|
US
|
741
|
|
66
|
|
672
|
|
|
Other
|
6
|
|
3
|
|
(6)
|
|
|
|
1,091
|
|
447
|
|
1,156
|
|
|
Income tax expense
|
1,415
|
|
774
|
|
1,708
|
|
COMPONENTS OF DEFERRED INCOME TAXES
Deferred income tax assets and liabilities are recognized for the future tax consequences of differences between carrying amounts of assets and liabilities and their respective tax bases. Major components of deferred income tax assets and liabilities are as follows:
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Deferred income tax liabilities
|
|
|
|
Property, plant and equipment
|
(8,721)
|
|
(7,786)
|
|
|
Investments
|
(6,097)
|
|
(4,649)
|
|
|
Regulatory assets
|
(1,245)
|
|
(1,156)
|
|
|
Other
|
(208)
|
|
(127)
|
|
|
Total deferred income tax liabilities
|
(16,271)
|
|
(13,718)
|
|
|
Deferred income tax assets
|
|
|
|
Financial instruments
|
315
|
|
518
|
|
|
Pension and OPEB plans
|
110
|
|
251
|
|
|
Loss carryforwards
|
3,081
|
|
2,005
|
|
|
Other
|
1,648
|
|
1,461
|
|
|
Total deferred income tax assets
|
5,154
|
|
4,235
|
|
|
Less valuation allowance
|
(84)
|
|
(79)
|
|
|
Total deferred income tax assets, net
|
5,070
|
|
4,156
|
|
|
Net deferred income tax liabilities
|
(11,201)
|
|
(9,562)
|
|
|
Presented as follows:
|
|
|
|
Total deferred income tax assets
|
488
|
|
770
|
|
|
Total deferred income tax liabilities
|
(11,689)
|
|
(10,332)
|
|
|
Net deferred income tax liabilities
|
(11,201)
|
|
(9,562)
|
|
A valuation allowance has been established for certain loss and credit carryforwards, and outside basis temporary differences on investments that reduce deferred income tax assets to an amount that will more likely than not be realized.
As at December 31, 2021, we recognized the benefit of unused tax loss carryforwards of $1.9 billion (2020 - $2.6 billion) in Canada which expire in 2026 and beyond.
As at December 31, 2021, we recognized the benefit of unused tax loss carryforwards of $11.0 billion (2020 - $5.8 billion) in the US. Unused tax loss carryforwards of $3.5 billion (2020 - $2.4 billion) begin to expire in 2023, and unused tax loss carryforwards of $7.5 billion (2020 - $3.4 billion) have no expiration.
We have not provided for deferred income taxes on the difference between the carrying value of substantially all of our foreign subsidiaries and their corresponding tax basis as the earnings of those subsidiaries are intended to be permanently reinvested in their operations. As such, these investments are not anticipated to give rise to income taxes in the foreseeable future. The difference between the carrying values of the investments and their tax bases is largely a result of unremitted earnings and currency translation adjustments. The unremitted earnings and currency translation adjustment for which no deferred taxes have been recognized in respect of foreign subsidiaries were $4.3 billion and $5.5 billion for the periods December 31, 2021 and 2020, respectively. If such earnings are remitted, in the form of dividends or otherwise, we may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is not practicable.
Enbridge and certain of our subsidiaries are subject to taxation in Canada, the US and other foreign jurisdictions. The material jurisdictions in which we are subject to potential examinations include the US (Federal) and Canada (Federal, Alberta and Ontario). We are open to examination by Canadian tax authorities for the 2012 to 2021 tax years and by US tax authorities for the 2018 to 2021 tax years. We are currently under examination for income tax matters in Canada for the 2014 to 2018 tax years. We are not currently under examination for income tax matters in any other material jurisdiction where we are subject to income tax.
UNRECOGNIZED TAX BENEFITS
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Unrecognized tax benefits at beginning of year
|
121
|
|
129
|
|
|
Gross increases for tax positions of current year
|
1
|
|
1
|
|
|
|
|
|
|
Gross decreases for tax positions of prior year
|
(26)
|
|
(1)
|
|
|
Change in translation of foreign currency
|
(1)
|
|
(3)
|
|
|
Lapses of statute of limitations
|
(19)
|
|
(5)
|
|
|
|
|
|
|
Unrecognized tax benefits at end of year
|
76
|
|
121
|
|
The unrecognized tax benefits as at December 31, 2021, if recognized, would impact our effective income tax rate. We do not anticipate further adjustments to the unrecognized tax benefits during the next 12 months that would have a material impact on our consolidated financial statements.
We recognize accrued interest and penalties related to unrecognized tax benefits as a component of income taxes. Interest and penalties included in income taxes for the years ended December 31, 2021 and 2020 were a $5 million recovery and $3 million expense, respectively. As at December 31, 2021 and 2020, interest and penalties of $12 million and $17 million, respectively, have been accrued.
26. PENSION AND OTHER POSTRETIREMENT BENEFITS
PENSION PLANS
We sponsor Canadian and US contributory and non-contributory registered defined benefit and defined contribution pension plans, which provide benefits covering substantially all employees. The Canadian Plans provide defined benefit and defined contribution pension benefits to our Canadian employees. The US Plans provide defined benefit pension benefits to our US employees. We also sponsor supplemental non-contributory defined benefit pension plans, which provide non-registered benefits for certain employees in Canada and the US.
Defined Benefit Pension Plan Benefits
Benefits payable from the defined benefit pension plans are based on each plan participant’s years of service and final average remuneration. Some benefits are partially inflation-indexed after a plan participant’s retirement. Our contributions are made in accordance with independent actuarial valuations. Participant contributions to contributory defined benefit pension plans are based upon each plan participant’s current eligible remuneration.
Defined Contribution Pension Plan Benefits
Our contributions are based on each plan participant’s current eligible remuneration. Our contributions for some defined contribution pension plans are also based on age and years of service. Our defined contribution pension benefit costs are equal to the amount of contributions required to be made by us.
Benefit Obligations, Plan Assets and Funded Status
The following table details the changes in the projected benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit pension plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
December 31,
|
2021
|
2020
|
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
Change in projected benefit obligation
|
|
|
|
|
|
|
Projected benefit obligation at beginning of year
|
4,855
|
|
4,446
|
|
|
1,243
|
|
1,230
|
|
|
Service cost
|
139
|
|
148
|
|
|
44
|
|
44
|
|
|
Interest cost
|
101
|
|
128
|
|
|
17
|
|
31
|
|
|
Participant contributions
|
28
|
|
31
|
|
|
—
|
|
—
|
|
|
Actuarial (gain)/loss1
|
(329)
|
|
292
|
|
|
(21)
|
|
95
|
|
|
Benefits paid
|
(194)
|
|
(190)
|
|
|
(84)
|
|
(128)
|
|
|
Foreign currency exchange rate changes
|
—
|
|
—
|
|
|
(11)
|
|
(23)
|
|
|
Other
|
—
|
|
—
|
|
|
(4)
|
|
(6)
|
|
|
Projected benefit obligation at end of year2
|
4,600
|
|
4,855
|
|
|
1,184
|
|
1,243
|
|
|
Change in plan assets
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
4,077
|
|
3,827
|
|
|
1,062
|
|
1,104
|
|
|
Actual return on plan assets
|
505
|
|
288
|
|
|
151
|
|
83
|
|
|
Employer contributions
|
120
|
|
121
|
|
|
43
|
|
27
|
|
|
Participant contributions
|
28
|
|
31
|
|
|
—
|
|
—
|
|
|
Benefits paid
|
(194)
|
|
(190)
|
|
|
(84)
|
|
(128)
|
|
|
Foreign currency exchange rate changes
|
—
|
|
—
|
|
|
(8)
|
|
(18)
|
|
|
Other
|
—
|
|
—
|
|
|
(4)
|
|
(6)
|
|
|
Fair value of plan assets at end of year3
|
4,536
|
|
4,077
|
|
|
1,160
|
|
1,062
|
|
|
Underfunded status at end of year
|
(64)
|
|
(778)
|
|
|
(24)
|
|
(181)
|
|
|
Presented as follows:
|
|
|
|
|
|
|
Deferred amounts and other assets
|
250
|
|
35
|
|
|
98
|
|
—
|
|
|
Accounts payable and other
|
(9)
|
|
(9)
|
|
|
(4)
|
|
(3)
|
|
|
Other long-term liabilities
|
(305)
|
|
(804)
|
|
|
(118)
|
|
(178)
|
|
|
|
(64)
|
|
(778)
|
|
|
(24)
|
|
(181)
|
|
1Primarily due to increase in the discount rate used to measure the benefit obligations (2020 - primarily due to decrease in the discount rate used to measure the benefit obligations).
2The accumulated benefit obligation for our Canadian pension plans was $4.3 billion and $4.5 billion as at December 31, 2021 and 2020, respectively. The accumulated benefit obligation for our US pension plans was $1.1 billion and $1.2 billion as at December 31, 2021 and 2020, respectively.
3Assets in the amount of $13 million (2020 - $11 million) and $84 million (2020 - $59 million), related to our Canadian and United States non-registered supplemental pension plan obligations, are held in grantor trusts and rabbi trusts that, in accordance with federal tax regulations, are not restricted from creditors. These assets are committed for the future settlement of benefit obligations included in the underfunded status as at the end of the year, however they are excluded from plan assets for accounting purposes.
Certain of our pension plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the accumulated benefit obligation and fair value of plan assets were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
December 31,
|
2021
|
2020
|
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
Accumulated benefit obligation
|
440
|
|
4,094
|
|
|
115
|
|
1,207
|
|
|
Fair value of plan assets
|
247
|
|
3,621
|
|
|
—
|
|
1,062
|
|
Certain of our pension plans have projected benefit obligations in excess of the fair value of plan assets. For these plans, the projected benefit obligation and fair value of plan assets were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
December 31,
|
2021
|
2020
|
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
Projected benefit obligation
|
1,272
|
|
4,434
|
|
|
121
|
|
1,243
|
|
|
Fair value of plan assets
|
1,020
|
|
3,621
|
|
|
—
|
|
1,062
|
|
Amount Recognized in Accumulated Other Comprehensive Income
The amount of pre-tax AOCI relating to our pension plans are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
December 31,
|
2021
|
2020
|
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
Net actuarial loss
|
226
|
|
542
|
|
|
92
|
|
233
|
|
|
Prior service credit
|
—
|
|
—
|
|
|
(1)
|
|
(1)
|
|
|
Total amount recognized in AOCI1
|
226
|
|
542
|
|
|
91
|
|
232
|
|
1 Excludes amounts related to cumulative translation adjustment.
Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income
The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our pension plans are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Service cost
|
139
|
|
148
|
|
149
|
|
|
44
|
|
44
|
|
45
|
|
|
Interest cost1
|
101
|
|
128
|
|
139
|
|
|
17
|
|
31
|
|
41
|
|
|
Expected return on plan assets1
|
(252)
|
|
(260)
|
|
(245)
|
|
|
(73)
|
|
(88)
|
|
(78)
|
|
|
Amortization/settlement of net actuarial loss1
|
54
|
|
42
|
|
41
|
|
|
11
|
|
1
|
|
2
|
|
|
Amortization/curtailment of prior service credit1
|
—
|
|
—
|
|
—
|
|
|
—
|
|
(1)
|
|
(1)
|
|
|
Net periodic benefit (credit)/cost
|
42
|
|
58
|
|
84
|
|
|
(1)
|
|
(13)
|
|
9
|
|
|
Defined contribution benefit cost
|
7
|
|
6
|
|
8
|
|
|
—
|
|
—
|
|
—
|
|
|
Net pension (credit)/cost recognized in Earnings
|
49
|
|
64
|
|
92
|
|
|
(1)
|
|
(13)
|
|
9
|
|
|
Amount recognized in OCI:
|
|
|
|
|
|
|
|
|
|
Effect of plan combination
|
—
|
|
—
|
|
—
|
|
|
—
|
|
—
|
|
(6)
|
|
|
|
Amortization/settlement of net actuarial loss
|
(25)
|
|
(21)
|
|
(26)
|
|
|
(11)
|
|
(1)
|
|
(2)
|
|
|
|
Amortization/curtailment of prior service credit
|
—
|
|
—
|
|
—
|
|
|
—
|
|
1
|
|
1
|
|
|
|
Net actuarial (gain)/loss arising during the year
|
(291)
|
|
118
|
|
115
|
|
|
(99)
|
|
100
|
|
8
|
|
|
Total amount recognized in OCI
|
(316)
|
|
97
|
|
89
|
|
|
(110)
|
|
100
|
|
1
|
|
|
Total amount recognized in Comprehensive income
|
(267)
|
|
161
|
|
181
|
|
|
(111)
|
|
87
|
|
10
|
|
1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
Actuarial Assumptions
The weighted average assumptions made in the measurement of the projected benefit obligation and net periodic benefit cost of our pension plans are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
|
2021
|
2020
|
2019
|
|
2021
|
2020
|
2019
|
|
Projected benefit obligation
|
|
|
|
|
|
|
|
|
Discount rate
|
3.2
|
%
|
2.6
|
%
|
3.0
|
%
|
|
2.6
|
%
|
2.2
|
%
|
3.0
|
%
|
|
Rate of salary increase
|
2.9
|
%
|
2.3
|
%
|
3.2
|
%
|
|
2.8
|
%
|
2.7
|
%
|
2.9
|
%
|
|
Cash balance interest credit rate
|
N/A
|
N/A
|
N/A
|
|
4.3
|
%
|
4.3
|
%
|
4.5
|
%
|
|
Net periodic benefit cost
|
|
|
|
|
|
|
|
|
Discount rate
|
2.6
|
%
|
3.0
|
%
|
3.8
|
%
|
|
2.2
|
%
|
3.0
|
%
|
3.9
|
%
|
|
Rate of return on plan assets
|
6.2
|
%
|
6.8
|
%
|
7.0
|
%
|
|
7.3
|
%
|
7.9
|
%
|
8.0
|
%
|
|
Rate of salary increase
|
2.3
|
%
|
3.2
|
%
|
3.2
|
%
|
|
2.7
|
%
|
2.9
|
%
|
2.9
|
%
|
|
Cash balance interest credit rate
|
N/A
|
N/A
|
N/A
|
|
4.3
|
%
|
4.5
|
%
|
4.5
|
%
|
OTHER POSTRETIREMENT BENEFIT PLANS
We sponsor funded and unfunded defined benefit OPEB Plans, which provide non-contributory supplemental health, dental, life and health spending account benefit coverage for certain qualifying retired employees.
Benefit Obligations, Plan Assets and Funded Status
The following table details the changes in the accumulated postretirement benefit obligation, the fair value of plan assets and the recorded assets or liabilities for our defined benefit OPEB plans:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
December 31,
|
2021
|
2020
|
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
Change in accumulated postretirement benefit obligation
|
|
|
|
|
|
|
Accumulated postretirement benefit obligation at beginning of year
|
321
|
|
293
|
|
|
254
|
|
288
|
|
|
Service cost
|
6
|
|
5
|
|
|
1
|
|
2
|
|
|
Interest cost
|
7
|
|
8
|
|
|
3
|
|
7
|
|
|
Participant contributions
|
—
|
|
—
|
|
|
8
|
|
4
|
|
|
Actuarial (gain)/loss1
|
(51)
|
|
21
|
|
|
(69)
|
|
17
|
|
|
Benefits paid
|
(9)
|
|
(6)
|
|
|
(22)
|
|
(28)
|
|
|
Plan amendments
|
—
|
|
—
|
|
|
—
|
|
(33)
|
|
|
Foreign currency exchange rate changes
|
—
|
|
—
|
|
|
(3)
|
|
(4)
|
|
|
Other
|
—
|
|
—
|
|
|
1
|
|
1
|
|
|
Accumulated postretirement benefit obligation at end of year
|
274
|
|
321
|
|
|
173
|
|
254
|
|
|
Change in plan assets
|
|
|
|
|
|
|
Fair value of plan assets at beginning of year
|
—
|
|
—
|
|
|
188
|
|
188
|
|
|
Actual return on plan assets
|
—
|
|
—
|
|
|
22
|
|
14
|
|
|
Employer contributions
|
9
|
|
6
|
|
|
6
|
|
12
|
|
|
Participant contributions
|
—
|
|
—
|
|
|
8
|
|
4
|
|
|
Benefits paid
|
(9)
|
|
(6)
|
|
|
(22)
|
|
(28)
|
|
|
Foreign currency exchange rate changes
|
—
|
|
—
|
|
|
(3)
|
|
(3)
|
|
|
Other
|
—
|
|
—
|
|
|
2
|
|
1
|
|
|
Fair value of plan assets at end of year
|
—
|
|
—
|
|
|
201
|
|
188
|
|
|
Overfunded/(underfunded) status at end of year
|
(274)
|
|
(321)
|
|
|
28
|
|
(66)
|
|
|
Presented as follows:
|
|
|
|
|
|
|
Deferred amounts and other assets
|
—
|
|
—
|
|
|
71
|
|
19
|
|
|
Accounts payable and other
|
(12)
|
|
(13)
|
|
|
—
|
|
(6)
|
|
|
Other long-term liabilities
|
(262)
|
|
(308)
|
|
|
(43)
|
|
(79)
|
|
|
|
(274)
|
|
(321)
|
|
|
28
|
|
(66)
|
|
1 Primarily due to increase in the discount rate used to measure the benefit obligations (2020 - primarily due to decrease in the discount rate used to measure the benefit obligations).
Certain of our OPEB plans have accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the accumulated benefit obligation and fair value of plan assets were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
December 31,
|
2021
|
2020
|
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
Accumulated benefit obligation
|
274
|
|
321
|
|
|
94
|
|
191
|
|
|
Fair value of plan assets
|
—
|
|
—
|
|
|
51
|
|
106
|
|
Amount Recognized in Accumulated Other Comprehensive Income
The amount of pre-tax AOCI relating to our OPEB plans are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
December 31,
|
2021
|
2020
|
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
Net actuarial (gain)/loss
|
(35)
|
|
15
|
|
|
(104)
|
|
(7)
|
|
|
Prior service credit
|
(1)
|
|
(1)
|
|
|
(37)
|
|
(44)
|
|
|
Total amount recognized in AOCI1
|
(36)
|
|
14
|
|
|
(141)
|
|
(51)
|
|
1 Excludes amounts related to cumulative translation adjustment.
Net Periodic Benefit Cost and Other Amounts Recognized in Comprehensive Income
The components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensive income related to our OPEB plans are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Service cost
|
6
|
|
5
|
|
5
|
|
|
1
|
|
2
|
|
2
|
|
|
Interest cost1
|
7
|
|
8
|
|
10
|
|
|
3
|
|
7
|
|
10
|
|
|
Expected return on plan assets1
|
—
|
|
—
|
|
—
|
|
|
(10)
|
|
(12)
|
|
(12)
|
|
|
Amortization/settlement of net actuarial gain1
|
—
|
|
(1)
|
|
(7)
|
|
|
(1)
|
|
(1)
|
|
—
|
|
|
Amortization/curtailment of prior service credit1
|
—
|
|
—
|
|
(1)
|
|
|
(7)
|
|
(2)
|
|
(2)
|
|
|
Net periodic benefit (credit)/cost recognized in Earnings
|
13
|
|
12
|
|
7
|
|
|
(14)
|
|
(6)
|
|
(2)
|
|
|
Amount recognized in OCI:
|
|
|
|
|
|
|
|
|
Amortization/settlement of net actuarial gain
|
—
|
|
1
|
|
7
|
|
|
1
|
|
1
|
|
—
|
|
|
Amortization/curtailment of prior service credit
|
—
|
|
—
|
|
1
|
|
|
7
|
|
2
|
|
2
|
|
|
Net actuarial (gain)/loss arising during the year
|
(50)
|
|
21
|
|
15
|
|
|
(80)
|
|
15
|
|
(8)
|
|
|
Prior service credit
|
—
|
|
—
|
|
—
|
|
|
—
|
|
(33)
|
|
—
|
|
|
Total amount recognized in OCI
|
(50)
|
|
22
|
|
23
|
|
|
(72)
|
|
(15)
|
|
(6)
|
|
|
Total amount recognized in Comprehensive income
|
(37)
|
|
34
|
|
30
|
|
|
(86)
|
|
(21)
|
|
(8)
|
|
1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.
Actuarial Assumptions
The weighted average assumptions made in the measurement of the accumulated postretirement benefit obligation and net periodic benefit cost of our OPEB plans are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
|
2021
|
2020
|
2019
|
|
2021
|
2020
|
2019
|
|
Accumulated postretirement benefit obligation
|
|
|
|
|
|
|
|
|
Discount rate
|
3.2
|
%
|
2.6
|
%
|
3.1
|
%
|
|
2.4
|
%
|
2.0
|
%
|
2.8
|
%
|
|
Net periodic benefit cost
|
|
|
|
|
|
|
|
|
Discount rate
|
2.6
|
%
|
3.1
|
%
|
3.8
|
%
|
|
2.0
|
%
|
2.8
|
%
|
4.0
|
%
|
|
Rate of return on plan assets
|
N/A
|
N/A
|
N/A
|
|
6.0
|
%
|
6.7
|
%
|
6.7
|
%
|
Assumed Health Care Cost Trend Rates
The assumed rates for the next year used to measure the expected cost of benefits are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
|
2021
|
2020
|
|
2021
|
2020
|
|
Health care cost trend rate assumed for next year
|
4.0
|
%
|
4.0
|
%
|
|
7.0
|
%
|
6.8
|
%
|
|
Rate to which the cost trend is assumed to decline (ultimate trend rate)
|
4.0
|
%
|
4.0
|
%
|
|
4.5
|
%
|
4.5
|
%
|
|
Year that the rate reaches the ultimate trend rate
|
N/A
|
N/A
|
|
2037
|
2037
|
PLAN ASSETS
We manage the investment risk of our pension funds by setting a long-term asset mix policy for each plan after consideration of: (i) the nature of pension plan liabilities; (ii) the investment horizon of the plan; (iii) the going concern and solvency funded status and cash flow requirements of the plan; (iv) our operating environment and financial situation and our ability to withstand fluctuations in pension contributions; and (v) the future economic and capital markets outlook with respect to investment returns, volatility of returns and correlation between assets.
The overall expected rate of return on plan assets is based on the asset allocation targets with estimates for returns based on long-term expectations.
The asset allocation targets and major categories of plan assets are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
|
Target
|
December 31,
|
|
Target
|
December 31,
|
|
Asset Category
|
Allocation
|
2021
|
2020
|
|
Allocation
|
2021
|
2020
|
|
Equity securities
|
43.8
|
%
|
46.7
|
%
|
47.2
|
%
|
|
45.0
|
%
|
52.5
|
%
|
55.6
|
%
|
|
Fixed income securities
|
28.9
|
%
|
29.8
|
%
|
29.6
|
%
|
|
20.1
|
%
|
18.4
|
%
|
17.2
|
%
|
|
Alternatives1
|
27.3
|
%
|
23.5
|
%
|
23.2
|
%
|
|
34.9
|
%
|
29.1
|
%
|
27.2
|
%
|
1Alternatives include investments in private debt, private equity, infrastructure and real estate funds. Fund values are based on the net asset value of the funds that invest directly in the aforementioned underlying investments. The values of the investments have been estimated using the capital accounts representing the plan's ownership interest in the funds.
Pension Plans
The following table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
|
Level 11
|
Level 22
|
Level 33
|
Total
|
|
Level 11
|
Level 22
|
Level 33
|
Total
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
|
|
December 31, 2021
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
180
|
|
—
|
|
—
|
|
180
|
|
|
10
|
|
—
|
|
—
|
|
10
|
|
|
Equity securities
|
|
|
|
|
|
|
|
|
|
|
Canada
|
198
|
|
228
|
|
—
|
|
426
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
US
|
1
|
|
—
|
|
—
|
|
1
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Global
|
—
|
|
1,693
|
|
—
|
|
1,693
|
|
|
—
|
|
609
|
|
—
|
|
609
|
|
|
Fixed income securities
|
|
|
|
|
|
|
|
|
|
|
Government
|
258
|
|
459
|
|
—
|
|
717
|
|
|
—
|
|
86
|
|
—
|
|
86
|
|
|
Corporate
|
—
|
|
453
|
|
—
|
|
453
|
|
|
—
|
|
118
|
|
—
|
|
118
|
|
|
Alternatives4
|
—
|
|
—
|
|
1,064
|
|
1,064
|
|
|
—
|
|
—
|
|
337
|
|
337
|
|
|
Forward currency contracts
|
—
|
|
2
|
|
—
|
|
2
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Total pension plan assets at fair value
|
637
|
|
2,835
|
|
1,064
|
|
4,536
|
|
|
10
|
|
813
|
|
337
|
|
1,160
|
|
|
December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
213
|
|
—
|
|
—
|
|
213
|
|
|
5
|
|
—
|
|
—
|
|
5
|
|
|
Equity securities
|
|
|
|
|
|
|
|
|
|
|
Canada
|
178
|
|
188
|
|
—
|
|
366
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
US
|
2
|
|
—
|
|
—
|
|
2
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Global
|
—
|
|
1,556
|
|
—
|
|
1,556
|
|
|
—
|
|
590
|
|
—
|
|
590
|
|
|
Fixed income securities
|
|
|
|
|
|
|
|
|
|
|
Government
|
207
|
|
378
|
|
—
|
|
585
|
|
|
—
|
|
75
|
|
—
|
|
75
|
|
|
Corporate
|
—
|
|
410
|
|
—
|
|
410
|
|
|
—
|
|
103
|
|
—
|
|
103
|
|
|
Alternatives4
|
—
|
|
—
|
|
912
|
|
912
|
|
|
—
|
|
—
|
|
289
|
|
289
|
|
|
Forward currency contracts
|
—
|
|
33
|
|
—
|
|
33
|
|
|
—
|
|
—
|
|
—
|
|
—
|
|
|
Total pension plan assets at fair value
|
600
|
|
2,565
|
|
912
|
|
4,077
|
|
|
5
|
|
768
|
|
289
|
|
1,062
|
|
1Level 1 assets include assets with quoted prices in active markets for identical assets.
2Level 2 assets include assets with significant observable inputs.
3Level 3 assets include assets with significant unobservable inputs.
4Alternatives include investments in private debt, private equity, infrastructure and real estate funds.
Changes in the net fair value of pension plan assets classified as Level 3 in the fair value hierarchy were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Canada
|
|
US
|
|
December 31,
|
2021
|
2020
|
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
Balance at beginning of year
|
912
|
|
852
|
|
|
289
|
|
276
|
|
|
Unrealized and realized gains/(losses)
|
77
|
|
(27)
|
|
|
38
|
|
7
|
|
|
Purchases and settlements, net
|
75
|
|
87
|
|
|
10
|
|
6
|
|
|
Balance at end of year
|
1,064
|
|
912
|
|
|
337
|
|
289
|
|
OPEB Plans
The following table summarizes the fair value of plan assets for our US funded OPEB plans recorded at each fair value hierarchy level:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Level 11
|
Level 22
|
Level 33
|
Total
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
|
|
December 31, 2021
|
|
|
|
|
|
|
|
|
|
|
Cash and cash equivalents
|
|
|
|
|
|
4
|
|
—
|
|
—
|
|
4
|
|
|
Equity securities
|
|
|
|
|
|
|
|
|
|
|
US
|
|
|
|
|
|
—
|
|
39
|
|
—
|
|
39
|
|
|
Global
|
|
|
|
|
|
—
|
|
75
|
|
—
|
|
75
|
|
|
Fixed income securities
|
|
|
|
|
|
|
|
|
|
|
Government
|
|
|
|
|
|
47
|
|
6
|
|
—
|
|
53
|
|
|
Corporate
|
|
|
|
|
|
—
|
|
8
|
|
—
|
|
8
|
|
|
Alternatives4
|
|
|
|
|
|
—
|
|
—
|
|
22
|
|
22
|
|
|
Total OPEB plan assets at fair value
|
|
|
|
|
|
51
|
|
128
|
|
22
|
|
201
|
|
|
December 31, 2020
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Equity securities
|
|
|
|
|
|
|
|
|
|
|
US
|
|
|
|
|
|
—
|
|
35
|
|
—
|
|
35
|
|
|
Global
|
|
|
|
|
|
—
|
|
79
|
|
—
|
|
79
|
|
|
Fixed income securities
|
|
|
|
|
|
|
|
|
|
|
Government
|
|
|
|
|
|
38
|
|
6
|
|
—
|
|
44
|
|
|
Corporate
|
|
|
|
|
|
—
|
|
8
|
|
—
|
|
8
|
|
|
Alternatives4
|
|
|
|
|
|
—
|
|
—
|
|
22
|
|
22
|
|
|
Total OPEB plan assets at fair value
|
|
|
|
|
|
38
|
|
128
|
|
22
|
|
188
|
|
1Level 1 assets include assets with quoted prices in active markets for identical assets.
2Level 2 assets include assets with significant observable inputs.
3Level 3 assets include assets with significant unobservable inputs.
4Alternatives includes investments in private debt, private equity, infrastructure and real estate.
Changes in the net fair value of US funded OPEB plan assets classified as Level 3 in the fair value hierarchy were as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
December 31,
|
|
|
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
Balance at beginning of year
|
|
|
|
22
|
|
18
|
|
|
Unrealized and realized gains
|
|
|
|
2
|
|
1
|
|
|
Purchases and settlements, net
|
|
|
|
(2)
|
|
3
|
|
|
Balance at end of year
|
|
|
|
22
|
|
22
|
|
EXPECTED BENEFIT PAYMENTS
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ending December 31,
|
2022
|
2023
|
2024
|
2025
|
2026
|
2027-2031
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
Pension
|
|
|
|
|
|
|
|
Canada
|
197
|
|
203
|
|
208
|
|
212
|
|
217
|
|
1,163
|
|
|
US
|
80
|
|
78
|
|
78
|
|
76
|
|
77
|
|
374
|
|
|
OPEB
|
|
|
|
|
|
|
|
Canada
|
12
|
|
12
|
|
12
|
|
13
|
|
13
|
|
67
|
|
|
US
|
17
|
|
15
|
|
14
|
|
13
|
|
12
|
|
51
|
|
EXPECTED EMPLOYER CONTRIBUTIONS
In 2022, we expect to contribute approximately $110 million and $4 million to the Canadian and US pension plans, respectively, and $12 million and $6 million to the Canadian and US OPEB plans, respectively.
RETIREMENT SAVINGS PLANS
In addition to the pension and OPEB plans discussed above, we also have defined contribution employee savings plans available to US employees. Employees may participate in a matching contribution where we match a certain percentage of before-tax employee contributions of up to 6.0% of eligible pay per pay period. For the years ended December 31, 2021, 2020 and 2019, pre-tax employer matching contribution costs were $27 million each year, respectively.
27. LEASES
LESSEE
We incur operating lease expenses related primarily to real estate, pipelines, storage and equipment. Our operating leases have remaining lease terms of 5 months to 25 years as at December 31, 2021.
For the years ended December 31, 2021 and 2020, we incurred operating lease expenses of $95 million and $107 million, respectively. Operating lease expenses are reported under Operating and administrative expense in the Consolidated Statements of Earnings.
For the years ended December 31, 2021 and 2020, operating lease payments to settle lease liabilities were $118 million and $133 million, respectively. Operating lease payments are reported under Operating activities in the Consolidated Statements of Cash Flows.
Supplemental Statements of Financial Position Information
|
|
|
|
|
|
|
|
|
|
|
|
December 31, 2021
|
December 31,
2020
|
|
(millions of Canadian dollars, except lease term and discount rate)
|
|
|
|
Operating leases1
|
|
|
|
Operating lease right-of-use assets, net2
|
645
|
708
|
|
|
|
|
|
Operating lease liabilities - current3
|
92
|
80
|
|
Operating lease liabilities - long-term3
|
612
|
681
|
|
Total operating lease liabilities
|
704
|
761
|
|
|
|
|
|
Finance leases
|
|
|
|
Finance lease right-of-use assets, net4
|
49
|
57
|
|
|
|
|
|
Finance lease liabilities - current5
|
13
|
11
|
|
Finance lease liabilities - long-term3
|
33
|
42
|
|
Total finance lease liabilities
|
46
|
53
|
|
|
|
|
|
Weighted average remaining lease term
|
|
|
|
Operating leases
|
12 years
|
13 years
|
|
Finance leases
|
7 years
|
7 years
|
|
|
|
|
|
Weighted average discount rate
|
|
|
|
Operating leases
|
4.1
|
%
|
4.1
|
%
|
|
Finance leases
|
3.8
|
%
|
3.8
|
%
|
1Affiliate right-of-use assets, current lease liabilities and long-term lease liabilities as at December 31, 2021 were $51 million (December 31, 2020 - $65 million), $5 million (December 31, 2020 - $5 million) and $47 million (December 31, 2020 - $52 million), respectively.
2Operating lease right-of-use assets are reported under Deferred amounts and other assets in the Consolidated Statements of Financial Position.
3Current operating lease liabilities and long-term operating and finance lease liabilities are reported under Accounts payable and other and Other long-term liabilities, respectively, in the Consolidated Statements of Financial Position.
4Finance lease right-of-use assets are reported under Property, plant and equipment, net in the Consolidated Statements of Financial Position.
5Current finance lease liabilities are reported under Current portion of long-term debt in the Consolidated Statements of Financial Position.
As at December 31, 2021, our operating and finance lease liabilities are expected to mature as follows:
|
|
|
|
|
|
|
|
|
|
|
|
Operating leases
|
Finance leases
|
|
(millions of Canadian dollars)
|
|
|
|
2022
|
117
|
|
15
|
|
|
2023
|
98
|
|
13
|
|
|
2024
|
91
|
|
9
|
|
|
2025
|
84
|
|
2
|
|
|
2026
|
72
|
|
1
|
|
|
Thereafter
|
455
|
|
11
|
|
|
Total undiscounted lease payments
|
917
|
|
51
|
|
|
Less imputed interest
|
(213)
|
|
(5)
|
|
|
Total
|
704
|
|
46
|
|
LESSOR
We receive revenues from operating leases primarily related to natural gas and crude oil storage and processing facilities, rail cars, and wind power generation assets. Our operating leases have remaining lease terms of 1 month to 30 years as at December 31, 2021.
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
|
(millions of Canadian dollars)
|
|
|
|
Operating lease income
|
263
|
|
265
|
|
|
Variable lease income
|
333
|
|
361
|
|
|
Total lease income1
|
596
|
|
626
|
|
1Lease income is recorded under Transportation and other services in the Consolidated Statements of Earnings.
As at December 31, 2021, the following table sets out future lease payments to be received under operating lease contracts where we are the lessor:
|
|
|
|
|
|
|
|
|
Operating leases
|
|
(millions of Canadian dollars)
|
|
|
2022
|
235
|
|
|
2023
|
215
|
|
|
2024
|
205
|
|
|
2025
|
196
|
|
|
2026
|
191
|
|
|
Thereafter
|
1,938
|
|
|
Future lease payments
|
2,980
|
|
28. CHANGES IN OPERATING ASSETS AND LIABILITIES
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
Accounts receivable and other
|
(1,228)
|
|
1,546
|
|
(547)
|
|
|
Accounts receivable from affiliates
|
(38)
|
|
8
|
|
6
|
|
|
Inventory
|
(118)
|
|
(254)
|
|
(24)
|
|
|
Deferred amounts and other assets
|
(195)
|
|
(586)
|
|
133
|
|
|
Accounts payable and other
|
(63)
|
|
(770)
|
|
63
|
|
|
Accounts payable to affiliates
|
52
|
|
1
|
|
(24)
|
|
|
Interest payable
|
43
|
|
31
|
|
(41)
|
|
|
Other long-term liabilities
|
(69)
|
|
117
|
|
175
|
|
|
|
(1,616)
|
|
93
|
|
(259)
|
|
29. RELATED PARTY TRANSACTIONS
Related party transactions are conducted in the normal course of business and, unless otherwise noted, are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties.
We provide transportation services to several significantly influenced investees which we record as transportation and other services revenue. We also purchase and sell natural gas and crude oil with several of our significantly influenced investees. These revenues and costs are recorded as commodity sales and commodity costs. We contract for firm transportation services to meet our annual natural gas supply requirements which we record as gas distribution costs.
Our transactions with significantly influenced investees are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Year ended December 31,
|
2021
|
2020
|
2019
|
|
(millions of Canadian dollars)
|
|
|
|
|
Transportation and other services
|
149
|
|
133
|
|
140
|
|
|
Commodity sales
|
20
|
|
21
|
|
107
|
|
|
Operating and administrative1
|
292
|
|
252
|
|
241
|
|
|
Commodity costs2
|
790
|
|
518
|
|
773
|
|
|
Gas distribution costs
|
131
|
|
135
|
|
133
|
|
1During the years December 31, 2021, 2020 and 2019, we had Operating and administrative costs from the Seaway Crude Pipeline System of $389 million, $342 million and $327 million, respectively. These costs are a result of an operational contract where we utilize capacity on Seaway Crude Pipeline System assets for use in our Liquids Pipelines business. The costs are offset by recoveries recorded on expenses incurred by us on behalf of our significantly influenced investees of $104 million, $94 million and $86 million for the years ended December 31, 2021, 2020 and 2019.
2During the years December 31, 2021, 2020 and 2019, we had Commodity costs from the Aux Sable Canada LP. of $447 million, $91 million and $272 million, respectively.
LONG-TERM NOTES RECEIVABLE FROM AFFILIATES
As at December 31, 2021, amounts receivable from affiliates include a series of loans totaling $954 million ($1,108 million as at December 31, 2020), which require quarterly or semi-annual interest payments at annual interest rates ranging from 3% to 8%. Interest income recognized from these notes totaled $39 million, $44 million and $40 million for the years ended December 31, 2021, 2020 and 2019, respectively. The amounts receivable from affiliates are included in Deferred amounts and other assets in the Consolidated Statements of Financial position.
30. COMMITMENTS AND CONTINGENCIES
COMMITMENTS
As at December 31, 2021, we have commitments as detailed below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Total
|
Less
than
1 year
|
2 years
|
3 years
|
4 years
|
5 years
|
Thereafter
|
|
(millions of Canadian dollars)
|
|
|
|
|
|
|
|
|
Annual debt maturities1
|
73,809
|
|
6,164
|
|
7,910
|
|
4,559
|
|
4,357
|
|
11,007
|
|
39,812
|
|
|
Interest obligations2
|
36,044
|
|
2,531
|
|
2,389
|
|
2,229
|
|
2,073
|
|
1,925
|
|
24,897
|
|
|
Purchase of services, pipe and other materials, including transportation3
|
7,876
|
|
2,945
|
|
1,010
|
|
736
|
|
561
|
|
607
|
|
2,017
|
|
|
Maintenance agreements
|
346
|
|
41
|
|
20
|
|
20
|
|
21
|
|
21
|
|
223
|
|
|
Right-of-ways commitments
|
1,249
|
|
35
|
|
35
|
|
35
|
|
36
|
|
37
|
|
1,071
|
|
|
Total
|
119,324
|
|
11,716
|
|
11,364
|
|
7,579
|
|
7,048
|
|
13,597
|
|
68,020
|
|
1Includes debentures, term notes, commercial paper and credit facility draws based on the facility's maturity date and excludes short-term borrowings, debt discounts, debt issuance costs, finance lease obligations and fair value adjustment. We have the ability under certain debt facilities to call and repay the obligations prior to scheduled maturities. Therefore, the actual timing of future cash repayments could be materially different than presented above.
2Includes debentures and term notes bearing interest at fixed, floating and fixed-to-floating rates.
3Includes capital and operating commitments. Consists primarily of gas transportation and storage contracts, firm capacity payments and gas purchase commitments, transportation, service and product purchase obligations, and power commitments.
ENVIRONMENTAL
We are subject to various Canadian and US federal, state and local laws relating to the protection of the environment. These laws and regulations can change from time to time, imposing new obligations on us.
Environmental risk is inherent to liquid hydrocarbon and natural gas pipeline operations, and Enbridge and its affiliates are, at times, subject to environmental remediation at various sites where we operate. We manage this environmental risk through appropriate environmental policies, programs and practices to minimize any impact our operations may have on the environment. To the extent that we are unable to recover payment for environmental liabilities from insurance or other potentially responsible parties, we will be responsible for payment of liabilities arising from environmental incidents associated with our operating activities.
AUX SABLE
On October 14, 2016, an amended claim was filed against Aux Sable by a counterparty to an NGL supply agreement. On January 5, 2017, Aux Sable filed a Statement of Defence with respect to this claim.
On November 27, 2019, the counterparty filed an amended amended claim providing further particulars of its claim against Aux Sable, increasing its damages claimed, and adding defendants Aux Sable Liquid Products Inc. and Aux Sable Extraction LLC (general partners of the previously existing defendants). Aux Sable filed an amended Statement of Defence responding to the amended amended claim on January 31, 2020.
While the final outcome of this action cannot be predicted with certainty, at this time management believes that the ultimate resolution of this action will not have a material impact on our consolidated financial position or results of operations.
TAX MATTERS
We and our subsidiaries maintain tax liabilities related to uncertain tax positions. While fully supportable in our view, these tax positions, if challenged by tax authorities, may not be fully sustained on review.
OTHER LITIGATION
We and our subsidiaries are involved in various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and challenges to regulatory approvals and permits. While the final outcome of such actions and proceedings cannot be predicted with certainty, management believes that the resolution of such actions and proceedings will not have a material impact on our consolidated financial position or results of operations.
31. GUARANTEES
In the normal course of conducting business, we may enter into agreements which indemnify third parties and affiliates. We may also be a party to agreements with subsidiaries, jointly owned entities, unconsolidated entities such as equity method investees, or entities with other ownership arrangements that require us to provide financial and performance guarantees. Financial guarantees include stand-by letters of credit, debt guarantees, surety bonds and indemnifications. To varying degrees, these guarantees involve elements of performance and credit risk, which are not included on our Consolidated Statements of Financial Position. Performance guarantees require us to make payments to a third party if the guaranteed entity does not perform on its contractual obligations, such as debt agreements, purchase or sale agreements, and construction contracts and leases.
We typically enter into these arrangements to facilitate commercial transactions with third parties. Examples include indemnifying counterparties pursuant to sale agreements for assets or businesses in matters such as breaches of representations, warranties or covenants, loss or damages to property, environmental liabilities, and litigation and contingent liabilities. We may indemnify third parties for certain liabilities relating to environmental matters arising from operations prior to the purchase or transfer of certain assets and interests. Similarly, we may indemnify the purchaser of assets for certain tax liabilities incurred while we owned the assets, a misrepresentation related to taxes that result in a loss to the purchaser or other certain tax liabilities related to those assets.
The likelihood of having to perform under these guarantees and indemnifications is largely dependent upon future operations of various subsidiaries, investees and other third parties, or the occurrence of certain future events. We cannot reasonably estimate the total maximum potential amounts that could become payable to third parties and affiliates under such agreements described above; however, historically, we have not made any significant payments under guarantee or indemnification provisions. While these agreements may specify a maximum potential exposure, or a specified duration to the guarantee or indemnification obligation, there are circumstances where the amount and duration are unlimited. As at December 31, 2021 guarantees and indemnifications have not had, and are not reasonably likely to have, a material effect on our financial condition, changes in financial condition, earnings, liquidity, capital expenditures or capital resources.
32. QUARTERLY FINANCIAL DATA (UNAUDITED)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Q1
|
Q2
|
Q3
|
Q4
|
Total
|
|
(unaudited; millions of Canadian dollars, except per share amounts)
|
|
|
|
|
|
|
2021
|
|
|
|
|
|
|
Operating revenues
|
12,187
|
|
10,948
|
|
11,466
|
|
12,470
|
|
47,071
|
|
|
Operating income
|
2,548
|
|
1,816
|
|
1,388
|
|
2,053
|
|
7,805
|
|
|
Earnings
|
2,014
|
|
1,521
|
|
814
|
|
1,965
|
|
6,314
|
|
|
Earnings attributable to controlling interests
|
1,992
|
|
1,484
|
|
780
|
|
1,933
|
|
6,189
|
|
|
Earnings attributable to common shareholders
|
1,900
|
|
1,394
|
|
682
|
|
1,840
|
|
5,816
|
|
|
Earnings per common share
|
|
|
|
|
|
|
Basic
|
0.94
|
|
0.69
|
|
0.34
|
|
0.91
|
|
2.87
|
|
|
Diluted
|
0.94
|
|
0.69
|
|
0.34
|
|
0.91
|
|
2.87
|
|
|
2020
|
|
|
|
|
|
|
Operating revenues
|
12,013
|
|
7,956
|
|
9,110
|
|
10,008
|
|
39,087
|
|
|
Operating income
|
1,513
|
|
2,098
|
|
2,095
|
|
2,251
|
|
7,957
|
|
|
Earnings/(loss)
|
(1,364)
|
|
1,777
|
|
1,104
|
|
1,899
|
|
3,416
|
|
|
Earnings/(loss) attributable to controlling interests
|
(1,333)
|
|
1,741
|
|
1,084
|
|
1,871
|
|
3,363
|
|
|
Earnings/(loss) attributable to common shareholders
|
(1,429)
|
|
1,647
|
|
990
|
|
1,775
|
|
2,983
|
|
|
Earnings/(loss) per common share
|
|
|
|
|
|
|
Basic
|
(0.71)
|
|
0.82
|
|
0.49
|
|
0.88
|
|
1.48
|
|
|
Diluted
|
(0.71)
|
|
0.82
|
|
0.49
|
|
0.88
|
|
1.48
|
|