Enhanced Investments - Financial Portal

Published: 2021-02-12

ENBRIDGE GAS INC.
(a subsidiary of Enbridge Inc.)
	CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2020

MANAGEMENT'S REPORT
TO THE SHAREHOLDERS OF ENBRIDGE GAS INC.
Financial ReportingManagement of Enbridge Gas Inc. (the Company) is responsible for the accompanying consolidated financial statements. The consolidated financial statements have been prepared in accordance with general y accepted accounting principles in the United States of America (U.S. GAAP) and necessarily include amounts that reflect management's judgment and best estimates.
The Board of Directors is responsible for al aspects related to governance of the Company. The Company does not have an Audit Committee, having received an exemption from such requirement.
Internal Control over Financial ReportingManagement is also responsible for establishing and maintaining adequate internal control over financial reporting. The Company's internal control over financial reporting includes policies and procedures to facilitate the preparation of relevant, reliable and timely information, to prepare consolidated financial statements for external reporting purposes in accordance with U.S. GAAP and to provide reasonable assurance that assets are safeguarded.
PricewaterhouseCoopers LLP, independent auditors appointed by the shareholders of the Company, have conducted an audit of the consolidated financial statements of the Company in accordance with Canadian general y accepted auditing standards and have issued an unqualified audit report, which is accompanying the consolidated financial statements.
"signed"	"signed"
Cynthia L. Hansen	Tanya M. Ferguson
President	Vice President, Finance
February 12, 2021

Independent auditor’s report

To the Shareholders of Enbridge Gas Inc.

Our opinion

In our opinion, the accompanying consolidated financial statements present fairly, in all material respects, the financial position of Enbridge Gas Inc. (the Company) as at December 31, 2020 and 2019, and the results of its operations and its cash flows for the years then ended in accordance with accounting principles generally accepted in the United States of America (US GAAP).

What we have audited The Company’s consolidated financial statements comprise:

● the consolidated statements of earnings for the years ended December 31, 2020 and 2019;

● the consolidated statements of comprehensive income for the years ended December 31, 2020 and

2019;

● the consolidated statements of changes in equity for the years ended December 31, 2020 and 2019;

● the consolidated statements of cash flows for the years ended December 31, 2020 and 2019;

● the consolidated statements of financial position as at December 31, 2020 and 2019; and

● the notes to the consolidated financial statements, which include significant accounting policies and

other explanatory information.

Basis for opinion

We conducted our audit in accordance with Canadian generally accepted auditing standards. Our responsibilities under those standards are further described in the Auditor’s responsibilities for the audit of the consolidated financial statements section of our report.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our opinion.

Independence We are independent of the Company in accordance with the ethical requirements that are relevant to our audit of the consolidated financial statements in Canada. We have fulfilled our other ethical responsibilities in accordance with these requirements.

PricewaterhouseCoopers LLP PwC Tower, 18 York Street, Suite 2600, Toronto, Ontario, Canada M5J 0B2

T: +1 416 863 1133, F: +1 416 365 8215

“PwC” refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership.

Other information

Management is responsible for the other information. The other information comprises the Management’s Discussion and Analysis.

Our opinion on the consolidated financial statements does not cover the other information and we do not express any form of assurance conclusion thereon.

In connection with our audit of the consolidated financial statements, our responsibility is to read the other information identified above and, in doing so, consider whether the other information is materially inconsistent with the consolidated financial statements or our knowledge obtained in the audit, or otherwise appears to be materially misstated.

If, based on the work we have performed, we conclude that there is a material misstatement of this other information, we are required to report that fact. We have nothing to report in this regard.

Responsibilities of management and those charged with governance for the consolidated financial statements

Management is responsible for the preparation and fair presentation of the consolidated financial statements in accordance with US GAAP, and for such internal control as management determines is necessary to enable the preparation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

In preparing the consolidated financial statements, management is responsible for assessing the Company’s ability to continue as a going concern, disclosing, as applicable, matters related to going concern and using the going concern basis of accounting unless management either intends to liquidate the Company or to cease operations, or has no realistic alternative but to do so.

Those charged with governance are responsible for overseeing the Company’s financial reporting process.

Auditor’s responsibilities for the audit of the consolidated financial statements

Our objectives are to obtain reasonable assurance about whether the consolidated financial statements as a whole are free from material misstatement, whether due to fraud or error, and to issue an auditor’s report that includes our opinion. Reasonable assurance is a high level of assurance, but is not a guarantee that an audit conducted in accordance with Canadian generally accepted auditing standards will always detect a material misstatement when it exists. Misstatements can arise from fraud or error and are considered material if, individually or in the aggregate, they could reasonably be expected to influence the economic decisions of users taken on the basis of these consolidated financial statements.

As part of an audit in accordance with Canadian generally accepted auditing standards, we exercise professional judgment and maintain professional skepticism throughout the audit. We also:

● Identify and assess the risks of material misstatement of the consolidated financial statements,

whether due to fraud or error, design and perform audit procedures responsive to those risks, and obtain audit evidence that is sufficient and appropriate to provide a basis for our opinion. The risk of not detecting a material misstatement resulting from fraud is higher than for one resulting from error, as fraud may involve collusion, forgery, intentional omissions, misrepresentations, or the override of internal control.

● Obtain an understanding of internal control relevant to the audit in order to design audit procedures

that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control.

● Evaluate the appropriateness of accounting policies used and the reasonableness of accounting

estimates and related disclosures made by management.

● Conclude on the appropriateness of management’s use of the going concern basis of accounting and,

based on the audit evidence obtained, whether a material uncertainty exists related to events or conditions that may cast significant doubt on the Company’s ability to continue as a going concern. If we conclude that a material uncertainty exists, we are required to draw attention in our auditor’s report to the related disclosures in the consolidated financial statements or, if such disclosures are inadequate, to modify our opinion. Our conclusions are based on the audit evidence obtained up to the date of our auditor’s report. However, future events or conditions may cause the Company to cease to continue as a going concern.

● Evaluate the overall presentation, structure and content of the consolidated financial statements,

including the disclosures, and whether the consolidated financial statements represent the underlying transactions and events in a manner that achieves fair presentation.

● Obtain sufficient appropriate audit evidence regarding the financial information of the entities or

business activities within the Company to express an opinion on the consolidated financial statements. We are responsible for the direction, supervision and performance of the group audit. We remain solely responsible for our audit opinion.

We communicate with those charged with governance regarding, among other matters, the planned scope and timing of the audit and significant audit findings, including any significant deficiencies in internal control that we identify during our audit.

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants, Licensed Public Accountants

Toronto, OntarioFebruary 12, 2021

ENBRIDGE GAS INC.
	CONSOLIDATED STATEMENTS OF EARNINGS
		Year ended December 31,	2020	2019
		(mil ions of Canadian dol ars)Operating revenues
		Gas commodity and distribution			3,631	4,152
		Storage, transportation and other			884	923
		Total operating revenues (Note 4)			4,515	5,075
		Operating expenses
		Gas commodity and distribution costs			1,812	2,334
		Operating and administrative			1,137	1,109
		Depreciation and amortization			655	638
		Total operating expenses			3,604	4,081
		Operating income			911	994
		Other income			56	20
		Interest expense, net (Note 10)			(412)	(400)
		Earnings before income taxes			555	614
		Income tax expense (Note 15)			(58)	(58)
		Earnings			497	556
		The accompanying notes are an integral part of these consolidated financial statements.
					1

ENBRIDGE GAS INC.
	CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
	Year ended December 31,	2020	2019
	(mil ions of Canadian dol ars)Earnings
				497	556
	Other comprehensive income/(loss), net of tax (Notes 12 and 13)
	Change in unrealized loss on cash flow hedges			(37)	(37)
	Reclassification to earnings of loss on cash flow hedges			15	4
	Recognition of regulatory offset			—	55
	Actuarial loss on other postretirement benefits (OPEB) (Note 16)			(10)	(12)
	Foreign currency translation adjustment			—	(5)
	Other comprehensive (loss)/income, net of tax			(32)	5
	Comprehensive income			465	561
	The accompanying notes are an integral part of these consolidated financial statements.
				2

ENBRIDGE GAS INC.
	CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY
		Year ended December 31,	2020	2019
		(mil ions of Canadian dol ars)
		Common shares (Note 11)
	Balance at beginning of year				3,517	3,030
	Capital contribution				800	800
	Return of capital				(800)	(313)
		Balance at end of year			3,517	3,517
		Additional paid-in capital
	Balance at beginning and end of year				7,253	7,253
		Deficit
	Balance at beginning of year				(720)	(339)
	Earnings				497	556
	Common share dividends declared				(450)	(937)
	Adoption of new accounting standard				(2)	—
		Balance at end of year			(675)	(720)
		Accumulated other comprehensive loss (Note 12)
	Balance at beginning of year				(46)	(51)
	Other comprehensive (loss)/income, net of tax				(32)	5
		Balance at end of year			(78)	(46)
		Total equity			10,017	10,004
		The accompanying notes are an integral part of these consolidated financial statements.
					3

ENBRIDGE GAS INC.
	CONSOLIDATED STATEMENTS OF CASH FLOWS
		Year ended December 31,	2020	2019
		(mil ions of Canadian dol ars)Operating activitiesEarnings
					497	556
		Adjustments to reconcile earnings to net cash provided by operating activities:
		Depreciation and amortization			655	638
		Deferred income tax recovery			(25)	(31)
		Net defined pension and OPEB costs			(31)	(17)
		Loss on disposition			—	10
		Other			13	5
		Changes in operating assets and liabilities (Note 18)			93	116
		Net cash provided by operating activities			1,202	1,277
		Investing activities
		Capital expenditures			(1,109)	(1,073)
		Additions to intangible assets			(76)	(36)
		Proceeds from disposition			—	72
		Net cash used in investing activities			(1,185)	(1,037)
		Financing activities
		Net change in short-term borrowings			223	(127)
		Short-term repayments to affiliate			—	(32)
		Repayment of loans from affiliates			(650)	(300)
		Term note issuances, net of issue costs			1,192	697
		Term note repayments			(400)	—
		Common share dividends			(450)	(937)
		Return of capital			(800)	(313)
		Capital contribution received			800	800
		Net cash used in financing activities			(85)	(212)
		Net (decrease)/increase in cash			(68)	28
		Cash, cash equivalents and restricted cash at beginning of year			77	49
		Cash at end of year			9	77
		Supplementary cash flow information
		Cash paid for income taxes			66	12
		Cash paid for interest, net of amounts capitalized			385	381
		Property, plant and equipment non-cash accruals			20	34
		The accompanying notes are an integral part of these consolidated financial statements.
					4

ENBRIDGE GAS INC.
	CONSOLIDATED STATEMENTS OF FINANCIAL POSITION
		December 31,	2020	2019
		(mil ions of Canadian dol ars; number of shares in mil ions)AssetsCurrent assets
	Cash				9	77
	Accounts receivable and other (Note 6)				1,161	1,317
	Accounts receivable from affiliates (Note 19)				92	46
	Gas inventory				659	631
					1,921	2,071
		Property, plant and equipment, net (Note 7)			15,866	15,418
		Intangible assets, net (Note 8)			174	173
		Deferred amounts and other assets			2,492	2,235
		Goodwil			4,784	4,784
		Total assets			25,237	24,681
		Liabilities and equityCurrent liabilities
	Short-term borrowings (Note 10)				1,121	898
	Accounts payable and other (Note 9)				1,295	1,369
	Accounts payable to affiliates (Note 19)				134	113
	Current portion of long-term debt (Note 10)				376	400
					2,926	2,780
		Long-term debt (Note 10)			8,606	7,815
		Other long-term liabilities			2,166	1,999
		Deferred income taxes (Note 15)			1,522	1,433
		Loan from affiliate (Note 19)			—	650
					15,220	14,677
		Commitments and contingencies (Note 21)Equity
	Share capital (Note 11)
	Common shares (522 mil ion shares outstanding at December 31, 2020 and
	2019)				3,517	3,517
	Additional paid-in capital				7,253	7,253
	Deficit				(675)	(720)
	Accumulated other comprehensive loss (Note 12)				(78)	(46)
					10,017	10,004
		Total liabilities and equity			25,237	24,681
		The accompanying notes are an integral part of these consolidated financial statements.
		Approved by the Board of Directors:
		"signed"			"signed"
		Cynthia L. Hansen			David G. Unruh
		Director			Director
						5

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS
	1. BUSINESS OVERVIEW
	The terms "we," "our," "us" and "Enbridge Gas" as used in these financial statements refer col ectively to Enbridge Gas Inc. and its subsidiaries unless the context suggests otherwise. Enbridge Gas is a whol y-owned indirect subsidiary of Enbridge Inc. (Enbridge). Enbridge provides administrative and general support services to us.
	Enbridge Gas is a rate-regulated natural gas distribution, storage and transmission utility, serving residential, commercial and industrial customers in Ontario. We also served areas in northern New York State through our whol y-owned subsidiary, St. Lawrence Gas Company, Inc. (St. Lawrence Gas), prior to its disposition on November 1, 2019.
	AMALGAMATIONOn January 1, 2019, Enbridge Gas Distribution Inc. (EGD) and Union Gas Limited (Union Gas) amalgamated and have continued from this date as Enbridge Gas, which continues to have al of the assets, rights, contracts, liabilities and obligations of each of EGD and Union Gas, including licenses and permits.
	2. SIGNIFICANT ACCOUNTING POLICIES
	These consolidated financial statements are prepared in accordance with general y accepted accounting principles in the United States of America (U.S. GAAP). Amounts are stated in Canadian dol ars unless otherwise noted.
	We are permitted to use U.S. GAAP as our primary basis of accounting for purposes of meeting our continuous disclosure obligations under an exemption granted by securities regulators in Canada.
	BASIS OF PRESENTATION AND USE OF ESTIMATESThe preparation of financial statements in conformity with U.S. GAAP requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as wel 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: carrying values of regulatory assets and liabilities (Note 5); unbil ed revenues; estimates of revenue; expected credit losses; depreciation rates and carrying value of property, plant and equipment (Note 7); amortization rates and carrying value of intangible assets (Note 8); measurement of goodwil ; fair value of asset retirement obligations (AROs); fair value of financial instruments (Note 13); provisions for income taxes (Note 15); assumptions used to measure retirement benefits and OPEB (Note 16); and commitments and contingencies (Note 21). 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.
	REGULATIONOur utility operations within Ontario are regulated by the Ontario Energy Board (OEB), while the utility operations of St. Lawrence Gas were regulated by the New York State Public Service Commission. 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 U.S. GAAP for non rate-regulated entities.
		6

As a result of rate regulated accounting, we have recognized a number of regulatory assets and liabilities. 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 and amounts col ected from customers in advance of costs being incurred. 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. The regulator’s future actions may differ from current expectations or future legislative changes may impact the regulatory environment in which we operate. 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 general y not recognize regulatory assets or liabilities and the earnings impact would be recorded in the period the expenses are incurred or revenues are earned. We believe that the recovery of our regulatory assets as at December 31, 2020 is probable over the periods described in Note 5. Regulatory Matters.
With the approval of the regulator, 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.
REVENUE RECOGNITIONRevenue from contracts with customers are general y recognized upon the fulfil ment of the performance obligations for the distribution, storage, transportation and sale of natural gas. For distribution and transportation service arrangements, where the services are simultaneously received and consumed by the customer, revenues are recorded on the basis of 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. Revenues from storage services are recognized as the storage services are provided.
A significant portion of our operations are subject to regulation and, accordingly, there are circumstances where the revenues recognized do not match the amounts bil ed. Revenue under such circumstances is recognized in a manner that is consistent with the underlying rate-setting mechanism as approved by the regulator. This may give rise to regulatory deferral accounts pending disposition by decisions of the regulator, which are accounted for under Accounting Standards Codification (ASC) 980 - Regulated Operations.
PUSH-DOWN ACCOUNTINGEGD elected to apply push-down accounting in respect of its original acquisition by its ultimate parent, Enbridge, when it first adopted U.S. GAAP. On the original acquisition, the fair value adjustment was recorded by Enbridge rather than by EGD. Upon adopting push-down accounting, the historical cost of EGD’s property, plant and equipment and related accounts was adjusted by the remaining unamortized fair value adjustment.
We have applied push-down accounting with respect to the accounts of Union Gas from February 27, 2017, the date upon which Enbridge acquired common control of EGD and Union Gas. The carrying values of certain assets and liabilities of Union Gas transferred to EGD have been adjusted to reflect Enbridge's historical cost as at February 27, 2017.
	7

DERIVATIVE INSTRUMENTS AND HEDGINGDerivatives in Qualifying Hedging RelationshipsWe use derivative financial instruments to manage our exposure to changes in interest rates and foreign exchange rates. 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 and net investment hedges. There were no outstanding derivative instruments relating to fair value or net investment hedges as at December 31, 2020 and 2019.
Cash Flow HedgesWe use cash flow hedges to manage our exposure to changes in interest rates and foreign exchange rates related to our unregulated storage revenue. 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.
Classification of DerivativesWe 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 the 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 OffsetAssets 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 CostsTransaction 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 deduction from 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.
INCOME TAXESIncome 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 theircarrying 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 taxes can be recovered through rates. Any interest and/or penalty incurred related to tax is reflected in Income taxes.
	8

FOREIGN CURRENCY TRANSACTIONS AND TRANSLATIONForeign currency transactions are those transactions whose terms are denominated in a currency other than the currency of the primary economic environment in which Enbridge Gas or a reporting subsidiary operates, referred to as the functional currency. Transactions denominated in foreign currencies are translated into 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 rate of exchange in effect at the balance sheet date. Exchange gains and losses resulting from translation of monetary assets and liabilities are included in the Consolidated Statements of Earnings in the period in which they arise.
Prior to its sale in 2019, our only foreign operation was St. Lawrence Gas. The functional currency of St. Lawrence Gas was the United States dol ar (USD). The effects of translating the financial statements of St. Lawrence Gas to Canadian dol ars were included in the cumulative translation adjustment component of Accumulated other comprehensive income/loss (AOCI) and were recognized in earnings upon its sale. Asset and liability accounts were translated at the exchange rates in effect on the balance sheet date, while revenues and expenses were translated using monthly average exchange rates.
CASHWe combine cash and bank indebtedness where the corresponding bank accounts are subject to cash pooling arrangements.
RECEIVABLES AND CURRENT EXPECTED CREDIT LOSSESAccounts receivable are measured at cost. For accounts receivable, a loss al owance 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.
NATURAL GAS IMBALANCESThe Consolidated Statements of Financial Position include balances as a result of differences in gas volumes received and delivered for customers. Since certain imbalances are settled 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.
GAS INVENTORYGas inventories primarily consist of natural gas held in storage and also include costs such as storage injection and demand costs. Natural gas in storage is recorded at the prices approved by the regulators in the determination of distribution rates. The actual price of gas purchased may differ from the regulator’s approved price. The difference between the approved price and the actual cost of the gas purchased is deferred as a liability for future refund or as an asset for col ection as approved by the regulator.
PROPERTY, PLANT AND EQUIPMENTProperty, plant and equipment is recorded at historical cost, including associated operating costs and an al owance for interest incurred during construction as authorized by the regulator. 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.
	9

The pool method of accounting for property, plant and equipment is fol owed whereby similar assets with comparable useful lives are grouped and depreciated as a pool, as approved by the regulator. When grouped assets are retired or otherwise disposed of, gains and losses are not reflected in earnings, but are booked as an adjustment to accumulated depreciation until the last asset in the pool is disposed of. Gains and losses on the disposal of assets not subject to the pool method of accounting, such as land, are reflected in earnings. Depreciation of property, plant and equipment is provided on a straight-line basis over the estimated useful lives of the assets, as approved by the regulator, commencing when the asset is placed in service. Depreciation expense includes a provision for future removal and site restoration costs at rates approved by the regulator.
IMPAIRMENTWe 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 the undiscounted cash flows expected from the asset, we calculate fair value based on the discounted cash flows and write the assets down to the extent that the carrying value exceeds the fair value.
LEASESWe recognize an arrangement as a lease when a customer has the right to obtain substantial y al of the economic benefits from the use of an asset, as wel 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 as is 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 ASSETSDeferred amounts and other assets primarily include costs which regulatory authorities have permitted, or are expected to permit, to be recovered through future rates, including: deferred income taxes; derivative financial instruments; and actuarial gains and losses arising from defined benefit pension plans.
INTANGIBLE ASSETSIntangible assets consist primarily of certain software costs. We capitalize costs incurred during the application development stage of internal use software projects. Intangible assets are general y amortized on a straight line basis over their expected lives, commencing when the asset is available for use.
GOODWILLGoodwil represents the excess of the purchase price over the fair value of net identifiable assets on acquisition of a business. The carrying value of goodwil , which is not amortized, is assessed for impairment annual y, or more frequently if events or changes in circumstances arise that suggest the carrying value of goodwil may be impaired. We perform our annual review of the goodwil balance on April 1.
	10

We have the option to first assess qualitative factors to determine whether it is necessary to perform the quantitative goodwil impairment test. When performing a qualitative assessment, we determine the drivers of fair value 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, assessment of macroeconomic trends, regulatory environments, capital accessibility, operating income trends and industry conditions. Based on our assessment of the qualitative factors, if we determine it is more likely than not that the fair value is less than its carrying amount, a quantitative goodwil impairment test is performed.
The quantitative goodwil impairment test involves determining the fair value of goodwil and comparing that value to its carrying value. If the carrying value, including al ocated goodwil , exceeds its fair value, goodwil impairment is measured at the amount by which the carrying value exceeds the fair value. This amount should not exceed the carrying amount of goodwil . Fair value is estimated using a discounted cash flow model technique. The determination of fair value using the discounted cash flow model 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. The cash flow projections included significant judgments and assumptions relating to revenue growth rates and expected future capital expenditure.
ASSET RETIREMENT OBLIGATIONSAsset retirement obligations (ARO) associated with the retirement of long-lived assets are measured at fair value and recognized as Other long-term liabilities in the period in which they can be reasonably determined. The 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. AROs 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.
For the majority of our assets, it is not possible to make a reasonable estimate of AROs due to the indeterminate timing and scope of the asset retirements.
PENSION AND OPEBWe provide pension benefits through defined benefit and defined contribution pension plans and OPEB, including group health care and life insurance benefits through defined benefit OPEB plans.
Defined benefit pension obligation and net periodic benefit cost are estimated using the projected unitcredit 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 unitcredit method, where benefits are attributed to years of service, taking into consideration projection of benefit costs.
We use mortality tables issued by the Canadian Institute of Actuaries (revised in 2014) to measure the benefit obligation of our pension plans.
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.
	11

Funded pension plan assets are measured at fair value. The expected return on funded pension plan assets is determined using market-related values and assumptions on the invested asset mix consistentwith the investment policies relating to the plan assets. The market-related values reflect estimated returnon 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 (funded pension plans) and from changes in actuarial assumptions used to determine the accrued benefit obligation, including discount rate, changes in headcount and salaryinflation 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 (funded pension 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 definedbenefit OPEB plans are presented as a component of AOCI in the Consolidated Statements ofChanges in Equity. Any unrecognized OPEB-related actuarial gains and losses and prior service costsand credits that arise during the period are recognized as a component of OCI, net of tax. Cumulativeunrecognized net actuarial gains and losses and prior service costs arising from defined benefit pensionplans, which have been permitted or are expected to be permitted by the regulator, to be recoveredthrough future rates, are presented as a component of Deferred amounts and other assets in theConsolidated Statements of Financial Position.
We 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 col ected 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.
COMMITMENTS AND CONTINGENCIESLiabilities for other commitments and contingencies are recognized when, after ful y 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.
		12

3. CHANGES IN ACCOUNTING POLICIES
ADOPTION OF NEW ACCOUNTING STANDARDSReference Rate ReformEffective July 1, 2020, we adopted Accounting Standards Update (ASU) 2020-04 on a prospective basis. The new standard was issued in March 2020 to provide temporary optional guidance in accounting for reference rate reform. The new guidance provides optional expedients and exceptions for applying general y accepted accounting principles when accounting for contract modifications, hedging relationships and other transactions impacted by rate reform, subject to meeting certain criteria. ASU 2020-04 is effective until December 31, 2022. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Disclosure EffectivenessEffective January 1, 2020, we adopted ASU 2018-13 on both a retrospective and prospective basis depending on the change. The new standard was issued to improve the disclosure requirements for fair value measurements by eliminating and modifying some disclosures, while also adding new disclosures. The adoption of this ASU did not have a material impact on our consolidated financial statements.
Accounting for Credit LossesEffective January 1, 2020, we adopted ASU 2016-13 on a modified retrospective basis.
The new standard was issued in June 2016 with the intent of providing financial statement users with more useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The previous accounting treatment used the incurred loss methodology for recognizing credit losses that delayed the recognition until it was probable a loss had been incurred. The accounting update adds a new impairment model, known as the current expected credit loss model, which is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an al owance its estimate of expected credit losses, which the Financial Accounting Standards Board believes results in more timely recognition of such losses.
Further, ASU 2018-19 was issued in November 2018 to clarify that operating lease receivables should be accounted for under the new leases standard, ASC 842, and are not within the scope of ASC 326, Financial Instruments - Credit Losses.
For accounts receivable, a loss al owance 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.
The adoption of this ASU did not have a material impact on our consolidated financial statements.
FUTURE ACCOUNTING POLICY CHANGESAccounting for Income TaxesASU 2019-12 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, as wel as provides simplification by clarifying and amending existing guidance. ASU 2019-12 is effective January 1, 2021 and entities are permitted to adopt the standard early. The adoption of ASU 2019-12 is not expected to have a material impact on our consolidated financial statements.
	13

Disclosure EffectivenessASU 2018-14 was issued in August 2018 to improve disclosure requirements for employers that sponsor defined benefit pension or other postretirement plans. The amendment modifies the current guidance by adding and removing several disclosure requirements while also clarifying the guidance on current disclosure requirements. ASU 2018-14 is effective January 1, 2021 and entities are permitted to adopt the standard early. The adoption of ASU 2018-14 is not expected to have a material impact on our consolidated financial statements.
4. REVENUES
REVENUE FROM CONTRACTS WITH CUSTOMERSMajor Services
Year ended December 31,	2020	2019
(mil ions of Canadian dol ars) Gas commodity and distribution revenues - residential
			2,560	2,847
Gas commodity and distribution revenues - commercial and industrial			1,077	1,316
Storage revenue			144	140
Transportation revenue			681	716
Other revenues			62	65
Total revenue from contracts with customers			4,524	5,084
Other1			(9)	(9)
Total revenues			4,515	5,075
1 Primarily relates to the effects of rate-regulated accounting.
We disaggregate revenues into categories which represent our principal performance obligations. These revenue categories also represent the most significant revenue streams, and consequently are considered to be the most relevant revenue information for management to consider in evaluating performance.
Contract Balances
		Contract
			Receivables	Liabilities
(mil ions of Canadian dol ars)Balance as at December 31, 2020
				738	—
Balance as at December 31, 2019				613	65
Receivables represent an unconditional right to consideration where only the passage of time is requiredbefore payment of consideration is due, and consist of trade accounts receivable, unbil ed revenue and other accrued receivable balances.
Contract liabilities represent payments received for performance obligations which have not been fulfil ed under our equal monthly payment plan. Revenue recognized during the year ended December 31, 2020 included $65 mil ion of contract liabilities which had not been fulfil ed as at the beginning of the year. The increase in contract liabilities from cash received, net of amounts recognized as revenues during the year ended December 31, 2020, was nil.
				14

Performance Obligations
	Nature of Performance Obligation
Gas commodity and distribution revenue	•	Supply and delivery of natural gas to customers
Storage and transportation revenue	•	Storage and transportation of natural gas on behalf
	of customers
Other revenue	•	Other bil ing and service fees
We recognized a reduction of revenue of $22 mil ion during the year ended December 31, 2020 from performance obligations satisfied in previous periods, primarily resulting from differences in actual and estimated consumption. The associated reduction in gas commodity and distribution costs was also recognized in the current year.
Payment TermsPayments from distribution customers are received on a continuous basis based on established bil ing cycles. Our policy requires that customers settle their bil ings in accordance with the payment terms listed on their bil , which is general y within 20 days. Payments from storage customers are received monthly under long-term storage capacity contracts. Payments from transportation customers are received on a continuous basis based on established bil ing cycles or monthly under long-term transportation capacity contracts.
Revenue to be Recognized from Unfulfilled Performance ObligationsTotal revenue from performance obligations expected to be fulfil ed in future periods is $581 mil ion, of which $310 mil ion is expected to be recognized during the year ending December 31, 2021.
The performance obligations above reflect revenues expected to be recognized in future periods from unfulfil ed performance obligations pursuant to contracts with customers for the purchase of natural gas distribution, storage and transportation services. Certain revenues are excluded from the amounts above under the fol owing ASC 606 optional exemptions:
•		certain revenues, such as flow-through costs charged to customers, which are recognized at the amount for which we have the right to invoice our customers; and
•		revenue from contracts with customers that have an original expected duration of one year or less.
Variable consideration is also excluded from the amounts above due to the uncertainty of the associated consideration, which is general y resolved when actual volumes and prices are determined. For example, we consider interruptible transportation service revenues to be variable revenues since volumes cannot be reasonably estimated.
A significant portion of our operations are subject to regulation. Accordingly, the amounts above, in addition to revenues that are not regulated, only include revenue for which the underlying rate has been approved by regulation, where applicable. The revenues excluded from the amounts above could represent a significant portion of our overal revenues and revenue from contracts with customers.
SIGNIFICANT JUDGMENTS MADE IN RECOGNIZING REVENUERevenue RecognitionRevenue from contracts with customers is general y recognized upon the fulfil ment of the performance obligations as described above. Distribution and transportation service revenues are recorded on the basis of 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.
	15

Due to regulatory mechanisms, there are circumstances where revenues recognized do not match the amounts bil ed. Under such circumstances, revenue is recognized in a manner that is consistent with the underlying rate setting mechanism as approved by the regulator. This may give rise to regulatory deferral accounts pending disposition by decisions of the regulator.
Recognition and Measurement of Revenues
Year ended December 31,	2020	2019
(mil ions of Canadian dol ars) Revenue from products and services transferred over time1
			4,464	5,019
Revenue from products transferred at a point in time2			60	65
Total revenue from contracts with customers			4,524	5,084
1 Revenue from distribution, storage and transportation services.2 Primarily from Other revenues.
Performance Obligations Satisfied Over TimeFor arrangements involving the distribution and transportation of natural gas, where the services are simultaneously received and consumed by the customer, we recognize revenue over time using an output method based on volumes of commodities delivered. The measurement of the volumes delivered corresponds directly to the benefits received by the customers during that period. Revenue from storage services are recognized as the services are provided.
Determination of Transaction PricesPrices for distribution and transportation services and regulated storage services are prescribed by regulation. Fees for unregulated storage services are determined through negotiations with customers and are based on market rates.
Prices for natural gas sold are driven by market prices and the Quarterly Rate Adjustment Mechanism (QRAM) in place that al ows for rates to reflect changes in natural gas prices, subject to regulatory approval.
5. REGULATORY MATTERS
We record assets and liabilities that result from regulated ratemaking processes that would not be recorded under U.S. GAAP for non-regulated entities. See Note 2 for further discussion.
We are regulated by the OEB pursuant to the provisions of the Ontario Energy Board Act, (1998), which is part of a package of legislation known as the Energy Competition Act, (1998). This legislation provides for different forms of regulation and competition in the energy (electricity and natural gas) industry in Ontario.
RATE APPROVALSOur 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 wel as an earnings sharing mechanism that requires us to share equal y with customers any earnings in excess of 150 basis points over the annual OEB approved return on equity.
			16

FINANCIAL STATEMENT EFFECTSAccounting for rate-regulated activities has resulted in the recognition of the fol owing regulatory assets and liabilities in the Consolidated Statements of Financial Position:
			Recovery/Refund
December 31,	2020	2019		Period Ends
(mil ions of Canadian dol ars)Current regulatory assets Federal carbon receivables1
					—	145		2020
Demand side management program					31	28		2021
Purchase gas variance2					—	23		2021
Other current regulatory assets					86	94		2021
Total current regulatory assets3 (Note 6)					117	290
Long-term regulatory assets Deferred income taxes4
					1,393	1,266		Various
Pension plan receivable5					342	222		Various
Long-term debt6					334	362	2022-2046
Accounting policy changes7					169	175		Various
Transition impact of accounting changes8					53	53		2032
Other long-term regulatory assets					34	12		Various
Total long-term regulatory assets3					2,325	2,090
Total regulatory assets					2,442	2,380
Current regulatory liabilities Purchase gas variance2
					153	41		2021
Other current regulatory liabilities					73	176		2021
Total current regulatory liabilities9 (Note 9)					226	217
Long-term regulatory liabilities Future removal and site restoration reserves10
					1,455	1,424		Various
Accelerated capital cost al owance					43	28		Various
Other long-term regulatory liabilities					45	19		Various
Total long-term regulatory liabilities9					1,543	1,471
Total regulatory liabilities					1,769	1,688
1 The federal carbon balance is the difference between actual carbon costs and carbon costs recovered in rates, as wel as the
administration costs associated with the impacts of the federal carbon program requirements. This balance has been recovered from customers in the fourth quarter of 2020 in accordance with the OEB's approval.
2 Purchase gas variance is the difference between the actual cost and the approved cost of natural gas reflected in rates. We have
been granted OEB approval to refund this balance to, or col ect this balance from, customers on a rol ing 12 month basis as part of the QRAM process.
3 Current regulatory assets are included in Accounts receivable and other, while long-term regulatory assets are included in
Deferred amounts and other assets.
4 The deferred income taxes balance 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 the temporary differences. In the absence of rate-regulated accounting, this regulatory balance and the related earnings impact would not be recorded.
5 The pension plan balance 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.
6 The debt balance represents our regulatory offset to the fair value adjustment to debt acquired in Enbridge's merger with Spectra
Energy Corp. (Spectra Energy) and pushed down to Enbridge Gas. 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.
7 The accounting policy changes deferral reflects unamortized accumulated actuarial gains/losses and past service costs incurred
by Union Gas, relating to the period up to Enbridge's 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 and recovered in rates, as previously approved by the OEB.
8 The transition impact of accounting changes balance represents our right to recover costs resulting from the adoption of the
accrual basis of accounting for pension and OPEB costs upon transition to U.S. GAAP in 2012. Pursuant to the OEB rate order, the balance as at December 31, 2012 is to be col ected in rates over a 20 year period, commencing in 2013.
						17

9 Current regulatory liabilities are included in Accounts payable and other, while long-term regulatory liabilities are included in Other
long-term liabilities.
10 Future removal and site restoration reserves consists of amounts col ected 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 col ected as part of the depreciation expense charged on property, plant and equipment that is reflected in rates. The settlement of this balance wil 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 col ected.
OTHER ITEMS AFFECTED BY RATE REGULATIONOperating Cost CapitalizationWith the approval of the OEB, we capitalize a percentage of certain operating costs. We 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-regulated accounting, a portion of such operating costs would be charged to earnings in the year incurred.
We entered into a services contract relating to asset management initiatives. The majority of these costs were capitalized to Gas mains in accordance with regulatory approval. As at December 31, 2020, the net book value of the costs included in Gas mains, services and other in Property, plant and equipment, net was $96 mil ion (2019 - $103 mil ion).
Work and Asset Management Solution (WAMS) is our integrated work and asset management system. As at December 31, 2020, the net book value of the WAMS asset included in Intangible assets, net was $51 mil ion (2019 - $60 mil ion).
Gas InventoriesNatural gas in storage is recorded in inventory at the reference prices approved by the OEB in the determination of customers’ system supply rates. Included in Gas inventory as at December 31, 2020 is $60 mil ion (2019 - $66 mil ion) related to storage injection and demand costs. Consistent with the regulatory recovery pattern, these costs are recorded in gas inventories during our off-peak months and charged to gas costs during the peak winter months. In the absence of rate-regulated accounting, these costs would be expensed as incurred, and inventory would be recorded at the lower of cost or market value.
6. ACCOUNTS RECEIVABLE AND OTHER
December 31,	2020	2019
(mil ions of Canadian dol ars)Trade receivables and unbil ed revenues, net1
			855	857
Regulatory assets (Note 5)			117	290
Rebil ables receivable			76	88
Gas imbalances			54	44
Other			59	38
			1,161	1,317
1 Net of al owance for expected credit losses of $45 mil ion as at December 31, 2020 and al owance for doubtful accounts of $38
mil ion as at December 31, 2019.
			18

7. PROPERTY, PLANT AND EQUIPMENT
	Weighted Average
December 31,	Depreciation Rate	2020	2019
(mil ions of Canadian dol ars)Regulated property, plant and equipment
Gas transmission				2.5%	1,752	1,505
Gas mains, services and other				2.6%	12,476	12,114
Compressors, meters and other operating equipment				4.3%	3,235	2,918
Storage				2.8%	975	919
Land and right-of-way1				1.0%	361	334
Vehicles, office furniture, equipment and other buildings
and improvements				10.7%	434	506
Under construction				—%	177	223
						19,410	18,519
Accumulated depreciation						(3,946)	(3,490)
						15,464	15,029
Unregulated property, plant and equipment
Gas mains, services and other				5.6%	13	13
Compressors, meters and other operating equipment				1.3%	41	40
Storage				3.0%	365	347
Land and right-of-way1				1.7%	37	32
Under construction				—%	30	24
						486	456
Accumulated depreciation						(84)	(67)
						402	389
Property, plant and equipment, net						15,866	15,418
1 The measurement of weighted average depreciation rate excludes non-depreciable assets.
Depreciation expense, including amounts col ected for future removal and site restoration costs, was $583 mil ion for the year ended December 31, 2020 (2019 - $558 mil ion).
Included within depreciation expense is $22 mil ion for the year ended December 31, 2020 (2019 - $22 mil ion) in incremental depreciation resulting from push-down accounting (Note 2).
DISPOSITIONOn November 1, 2019, we closed the sale of St. Lawrence Gas for total cash proceeds of approximately $72 mil ion (US$55 mil ion). A loss on disposal of approximately $10 mil ion before tax was included in Other income in the Consolidated Statements of Earnings in 2019.
						19

8. INTANGIBLE ASSETS
December 31,	2020	2019
(mil ions of Canadian dol ars)Software and Customer Information System
				654	592
Less: Accumulated amortization				(480)	(419)
Intangible assets, net				174	173
For the year ended December 31, 2020, the weighted average amortization rate for software and CIS was 11.8% (2019 - 13.9%).
Intangible assets include $35 mil ion of work-in-progress as at December 31, 2020 (2019 - $16 mil ion). Total amortization expense for intangible assets was $72 mil ion for the year ended December 31, 2020 (2019 - $80 mil ion). The fol owing table presents our expected amortization expense associated with existing intangible assets for the years indicated as fol ows:

				2021	2022	2023	2024	2025
(mil ions of Canadian dol ars)Forecast of amortization expense
							64	18	16	16	16
9. ACCOUNTS PAYABLE AND OTHER
December 31,	2020	2019
(mil ions of Canadian dol ars)Trade payables and accrued liabilities
				491	464
Regulatory liabilities (Note 5)				226	217
Federal carbon program liability				194	140
Construction payables and contractor holdbacks				73	112
Gas imbalances				54	44
Taxes payable				47	114
Other				210	278
				1,295	1,369

10. DEBT
					Weighted Average
December 31,					Interest Rate3	Maturity				2020	2019
(mil ions of Canadian dol ars)Medium-term notes
								3.9 % 2021-2050	8,485	7,685
Debentures								9.1 % 2024-2025	210	210
Commercial paper and credit facility draws								0.3 %	2022	1,121	898
Other1							(47)	(42)
Fair value adjustment from push down accounting (Note 2)							334	362
Total debt		10,103	9,113
Current maturities							(376)	(400)
Short-term borrowings2		(1,121)	(898)
Long-term debt		8,606	7,815
1 Primarily unamortized discounts, premiums and debt issuance costs.2 Weighted average interest rate - 0.3% (2019 - 2.0%).3 Calculated based on term notes, debentures, commercial paper and credit facility draws outstanding as at December 31, 2020.
As at December 31, 2020, al outstanding debt was unsecured.
									20

CREDIT FACILITIESWe actively manage our bank funding sources to ensure adequate liquidity and to optimize pricing and other terms. The fol owing table provides details of our external credit facility at December 31, 2020:
		Total
	Maturity	Facility	Draws2	Available
(mil ions of Canadian dol ars)364 day extendible credit facility
	20221	2,000	1,121	879
1 Maturity date is inclusive of the one-year term out provision.2 Includes facility draws and commercial paper issuances, net of discount, that are back-stopped by the credit facility.
On July 24, 2020, we extended our 364 extendible credit facility to July 23, 2022, inclusive of a one-year term out provision.
The credit facility carries a standby fee of 0.3% on the unused portion and the draws bear interest at market rates.
As at December 31, 2020, we have access to Enbridge's demand letter of credit facilities totaling $495 mil ion (2019 - $495 mil ion). As at December 31, 2020 and 2019, $14 mil ion of letters of credit were issued by us.
LONG-TERM DEBT ISSUANCESDuring the year ended December 31, 2020, we completed the fol owing long-term debt issuances totaling $1.2 bil ion:
				Principal
Issue Date				Amount
(mil ions of Canadian dol ars)April 2020
					2.90% medium-term notes due April 2030		$600
April 2020					3.65% medium-term notes due April 2050		$600
With proceeds from these issuances, we repaid the outstanding $650 mil ion subordinated promissory note, as wel as the related interest payable, due to Westcoast Energy Inc. on April 1, 2020. The note was presented as Loan from affiliate in the Consolidated Statements of Financial Position as at December 31, 2019.
LONG-TERM DEBT REPAYMENTDuring the year ended December 31, 2020, we completed the fol owing long-term debt repayment totaling $400 mil ion:
				Principal
Repayment Date				Amount
(mil ions of Canadian dol ars)November 2020
					4.04% medium-term notes		$400
DEBT COVENANTSOur credit facility agreement and term debt indentures include standard events of default and covenant provisions whereby accelerated repayment and/or terminations of the agreements may result if we were to default on payment or violate certain covenants. As at December 31, 2020, we are in compliance with al debt covenants.
						21

INTEREST EXPENSE

Year ended December 31,	2020	2019
(mil ions of Canadian dol ars)Debentures and term notes
			380	331
Commercial paper and credit facility draws			17	31
Interest on loans from affiliate			6	31
Other interest and finance costs			14	12
Capitalized interest			(5)	(5)
			412	400
11. SHARE CAPITAL
As at December 31, 2020, our authorized share capital consisted of an unlimited number of common shares with no par value and an unlimited number of preference shares. Our Class A and Class B common shares are held by Enbridge Energy Distribution Inc. (EEDI) and Great Lakes Basin Energy LP (GLBE), respectively. Both classes of common shares are identical in every respect, and dividends cannot be paid to one class without paying dividends to the other. As at December 31, 2020 and 2019, no preferred shares were issued and outstanding.
COMMON SHARES
			2020	2019
				Number	Number
December 31,				of shares	Amount	of shares	Amount
(mil ions of Canadian dol ars; number of shares in mil ions)Class A
Balance at beginning of year					282		2,636	233	2,373
Common shares converted from amalgamation1					—	—	(233)	(2,373)
Common shares issued from amalgamation1					—	—	282	2,373
Capital contribution					—		432	—	432
Return of capital					—		(432)	—	(169)
					282		2,636	282	2,636
Class B
Balance at beginning of year					240		881	58	657
Common shares converted from amalgamation2					—	—	(58)	(657)
Common shares issued from amalgamation2					—	—	240	657
Capital contribution					—		368	—	368
Return of capital					—		(368)	—	(144)
					240		881	240	881
Balance at end of year					522		3,517	522	3,517
1 On January 1, 2019, we issued to EEDI, which whol y-owned EGD and owned 1% of Union Gas, 281,881,334 Class A common
shares in exchange for 232,749,988 EGD common shares and 621,866 Union Gas Class A common shares.
2 On January 1, 2019, we issued to GLBE, which owned 99% of Union Gas, 240,020,243 Class B common shares in exchange for
57,822,650 Union Gas common shares.
The capital contribution and return of capital transactions to the stated capital of Class A and Class B common shares had no impact on the total shares outstanding.
						22

12. COMPONENTS OF AOCI
Changes in AOCI for the years ended December 31, 2020 and 2019 are as fol ows:
	2020
			Cumulative
		Cash Flow	Translation	OPEB
		Hedges	Adjustment	Adjustment			Total
(mil ions of Canadian dol ars)Balance at January 1, 2020
					(42)	—		(4)	(46)
Other comprehensive loss retained in AOCI					(49)	—		(13)	(62)
Other comprehensive loss reclassified to earnings					17	—		—	17
					(74)	—		(17)	(91)
Tax impact
Income tax on amounts retained in AOCI					12	—		3	15
Income tax on amounts reclassified to earnings			(2)	—		—	(2)
					10	—		3	13
Balance at December 31, 2020					(64)	—		(14)	(78)
	2019
			Cumulative	Pension and
		Cash Flow	Translation	OPEB
		Hedges	Adjustment	Adjustment			Total
(mil ions of Canadian dol ars)Balance at January 1, 2019
			(9)	5		(47)	(51)
Other comprehensive (loss)/income retained in AOCI1					(50)	(2)		58	6
Other comprehensive loss/(income) reclassified to earnings			5	(3)		—	2
					(54)	—		11	(43)
Tax impact
Income tax on amounts retained in AOCI1					13	—		(15)	(2)
Income tax on amounts reclassified to earnings			(1)	—		—	(1)
					12	—		(15)	(3)
Balance at December 31, 2019					(42)	—		(4)	(46)
1 OCI for the year ended December 31, 2019 was increased by an adjustment of $74 mil ion in respect of Enbridge Gas applying
rate-regulated accounting to record a regulatory offset to certain pension liabilities. An offsetting amount of $19 mil ion was also recorded in OCI for the related tax impact.
13. RISK MANAGEMENT AND FINANCIAL INSTRUMENTS
MARKET RISKOur earnings, cash flows and OCI are subject to movements in natural gas prices, foreign exchange rates and interest rates (col ectively, market risk). Portions of these risks are borne by customers through certain regulatory mechanisms. Formal risk management policies, processes and systems have been designed to mitigate these risks.
The fol owing 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.
Natural Gas Price RiskNatural gas price risk is the risk of gain or loss due to changes in the market price of natural gas. In compliance with the directive of the OEB, fluctuations in natural gas prices are borne by our customers.
						23

Foreign Exchange RiskForeign exchange risk is the risk of gain or loss due to the volatility of currency exchange rates. We generate certain revenues, incur expenses and hold cash balances that are denominated in USD. As a result, our earnings, cash flows and OCI are exposed to fluctuations resulting from USD exchange rate variability.
We have implemented a policy to hedge a portion of our USD denominated unregulated storage revenue exposures. Qualifying derivative instruments are used to hedge anticipated USD denominated revenues and to manage variability in cash flows.
A portion of our natural gas purchases are denominated in USD and, as a result, there is exposure to fluctuations in the exchange rate of the USD against the Canadian dol ar. Realized foreign exchange gains or losses relating to natural gas purchases are passed on to customers, therefore, we have no net exposure to movements in the foreign exchange rate on natural gas purchases.
Until November 1, 2019, we held a subsidiary that generated revenues denominated in USD.
Interest Rate RiskOur 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. Pay fixed-receive floating interest rate swaps are used to hedge against the effect of future interest rate movements. We have implemented a program to significantly 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 2.3%.
Our earnings and cash flows are also exposed to variability in longer term interest rates ahead of anticipated fixed rate debt issuances. Forward starting interest rate swaps are used to hedge against the effect of future interest rate movements. We have implemented a program to significantly 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 1.9%.
COVID-19 PANDEMIC RISKThe COVID-19 pandemic has caused significant volatility in Canada, the United States and international markets. While we have taken proactive measures to deliver energy safely and reliably during this pandemic, given the ongoing dynamic nature of the circumstances surrounding COVID-19, the impact of this pandemic on our business remains uncertain.
	24

TOTAL DERIVATIVE INSTRUMENTSThe fol owing table summarizes the Consolidated Statements of Financial Position location and carrying value of our derivative instruments.
We general y have a common practice of entering into individual International Swaps and Derivatives Association, Inc. agreements, or other similar derivative agreements, with the majority of our 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 event, and would reduce our credit risk exposure on derivative asset positions outstanding with these counterparties in those particular circumstances. The fol owing table also summarizes the maximum potential settlement amount in the event of those specific circumstances. Al amounts are presented gross in the Consolidated Statements of Financial Position.
	Derivative		Total Gross
	Instruments	Non-Qualifying	Derivative	Amounts	Total Net
	Used as Cash	Derivative	Instruments as	Available for	Derivative
December 31, 2020	Flow Hedges	Instruments	Presented	Offset	Instruments
(mil ions of Canadian dol ars)Deferred amounts and other assets
Interest rate contracts		8				—	8	(1)	7
		8				—	8	(1)	7
Accounts payable to affiliates
Interest rate contracts		(43)				—	(43)	—	(43)
		(43)				—	(43)	—	(43)
Other long-term liabilities
Interest rate contracts		(1)				—	(1)	1	—
		(1)				—	(1)	1	—
Total net derivative liability
Interest rate contracts		(36)				—	(36)	—	(36)
		(36)				—	(36)	—	(36)
	Derivative		Total Gross
	Instruments	Non-Qualifying	Derivative	Amounts	Total Net
	Used as Cash	Derivative	Instruments as	Available for	Derivative
December 31, 2019	Flow Hedges	Instruments	Presented	Offset	Instruments
(mil ions of Canadian dol ars)Accounts payable to affiliates
Interest rate contracts		(9)				—	(9)	—	(9)
		(9)				—	(9)	—	(9)
Other long-term liabilities
Interest rate contracts		(13)				—	(13)	—	(13)
		(13)				—	(13)	—	(13)
Total net derivative liability
Interest rate contracts		(22)				—	(22)	—	(22)
		(22)				—	(22)	—	(22)
The fol owing table summarizes the maturity and notional principal or quantity outstanding related to our derivative instruments.
December 31, 2020	2021	2022				2023	2024	2025 Thereafter	Total
Foreign exchange contracts - United
States dol ar forwards - sel (mil ions of
USD)										2	1	—	—	—	—	3
Interest rate contracts - short-term
borrowings (mil ions of Canadian dol ars)										387	18	—	—	—	—	405
Interest rate contracts - long-term debt
(mil ions of Canadian dol ars)										275	200	200	—	—	—	675
		25

The Effect of Derivative Instruments on the Consolidated Statements of Earnings and Comprehensive IncomeThe fol owing table presents the effect of cash flow hedges on our consolidated earnings and comprehensive income, before the effect of income taxes.
Year ended December 31,	2020	2019
(mil ions of Canadian dol ars)
Amount of unrealized loss recognized in OCI
Cash flow hedges
Interest rate contracts			(49)	(50)
			(49)	(50)
Amount of loss/(gain) reclassified from AOCI to earnings
Interest rate contracts1			17	6
Foreign exchange contracts			—	(1)
			17	5
1 Reported within Interest expense, net in the Consolidated Statements of Earnings.
We estimate that a loss of $10 mil ion of AOCI related to unrealized cash flow hedges wil be reclassified to earnings in the next 12 months. Actual amounts reclassified to earnings depend on the interest and foreign exchange rates in effect when derivative contracts that are currently outstanding mature. For al forecasted transactions, the maximum term over which we are hedging exposures to the variability of cash flows is 13 months as at December 31, 2020.
LIQUIDITY RISKLiquidity risk is the risk that we wil not be able to meet our financial obligations, including commitments, as they become due. In order to manage this risk, we forecast cash requirements over a 12-month rol ing time period to determine whether sufficient funds wil be available. Our primary sources of liquidity and capital resources are funds generated from operations, the issuance of commercial paper, draws under the committed credit facility and long-term debt, which includes debentures and medium-term notes and, if necessary, additional liquidity is available through intercompany transactions with our ultimate parent, Enbridge, and other related entities. These sources are expected to be sufficient to enable us to fund al anticipated requirements. We maintain a current medium-term note shelf prospectus with securities regulators, which enables ready access to the Canadian public capital markets, subject to market conditions. We also maintain a committed credit facility with a diversified group of banks and institutions. We were in compliance with al of the terms and conditions of our committed credit facility as at December 31, 2020. As a result, the credit facility is available to us and the banks are obligated to fund us under the terms of the facility.
CREDIT RISKCredit risk arises from the possibility that a counterparty wil default on its contractual obligations. We are exposed to credit risk from accounts receivable and derivative financial instruments. Exposure to credit risk is mitigated by our large and diversified customer base and the ability to recover an estimate for doubtful accounts for utility operations through the rate-making 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 of receivables. General y, we classify receivables older than 20 days as past due. The maximum exposure to credit risk related to non-derivative financial assets is their carrying value.
In July 2020, we began administering the Government of Ontario-funded COVID-19 Energy Assistance Program (CEAP) to eligible residential natural gas customers who have experienced hardships as a result of the COVID-19 pandemic. In August 2020, the CEAP was expanded to include smal business and registered charity customers. Additional government assistance programs may also be administered by us in the future.
			26

Our policy requires that customers settle their bil ings in accordance with the payment terms listed on their bil , which general y require payment in ful within 20 days. A provision for credit and recovery risk associated with accounts receivable has been made accordingly.
Our expected credit loss is determined based on historical credit losses by age of receivables, adjusted for any forward-looking information and management expectations, using a loss al owance matrix. This estimate is revised each reporting period to reflect current expectations. When we have determined that col ection efforts are unlikely to be successful, amounts charged to the expected credit loss account are applied against the impaired accounts receivable.
Estimated costs associated with uncol ectible accounts receivable are recovered through regulated distribution rates, which largely limits our exposure to credit risk related to accounts receivable, to the extent such estimates are accurate.
Entering into derivative financial instruments may also result in exposure to credit risk. We enter into risk management transactions primarily with institutions that possess investment grade credit ratings. Credit risk relating to derivative counterparties is mitigated by credit exposure limits and contractual requirements, frequent assessment of counterparty credit ratings and netting arrangements. As at December 31, 2020, we have $8 mil ion credit concentrations and credit exposure with Enbridge and its affiliates.
Derivative assets are adjusted for non-performance risk of our counterparties using their credit default swap spread rates and are reflected in the fair value. For derivative liabilities, our non-performance risk is considered in the valuation.
FAIR VALUE MEASUREMENTSOur 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 values of financial instruments reflect our best estimates of fair value based on general y accepted valuation techniques or models and are 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 INSTRUMENTSWe 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 1Level 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. We do not have any derivative instruments classified as Level 1.
Level 2Level 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 interest rate swaps for which observable inputs can be obtained.
	27

Level 3Level 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 derivative’s fair value. General y, 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 a 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. We do not have any derivative instruments classified as 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, including discounted cash flows for forwards and swaps. Depending on the type of derivative and the nature of the underlying risk, we use observable market prices (interest, foreign exchange and natural gas) and volatility as primary inputs to these valuation techniques. Final y, we consider our own credit default swap spread, as wel as the credit default swap spreads associated with our counterparties, in our estimation of fair value.
At December 31, 2020, we had Level 2 derivative assets with a fair value of $8 mil ion, (2019 - nil) and Level 2 derivative liabilities with a fair value of $44 mil ion (2019 - $22 mil ion).
FAIR VALUE OF OTHER FINANCIAL INSTRUMENTSThe fair value of our long-term debt is based on quoted market prices for instruments of similar yield, credit risk and tenor, and is classified as a Level 2 measurement. At December 31, 2020, our long-term debt, including the current portion, had a carrying value of $8.7 bil ion (2019 - $7.9 bil ion) before debt issuance costs and fair value adjustment from push down accounting, and a fair value of $10.7 bil ion (2019 - $9.2 bil ion).
The fair value of financial assets and liabilities, other than derivative instruments and long-term debt, approximate their carrying value due to the short period to maturity.
14. LEASES
LESSEEWe incur operating lease payments related to natural gas transportation, storage and real estate assets. These lease agreements have remaining lease terms of 3 months to 17 years, some of which include options to terminate at our discretion.
For the years ended December 31, 2020 and 2019, we incurred operating lease expenses of $9 mil ion and $7 mil ion, respectively. Operating lease expenses are reported within Operating and administrative expense in the Consolidated Statements of Earnings.
For the years ended December 31, 2020 and 2019, operating lease payments made to settle lease liabilities were $9 mil ion and $7 mil ion, respectively. Operating lease payments are reported within Operating activities in the Consolidated Statements of Cash Flows.
	28

Supplemental Consolidated Statements of Financial Position Information
December 31,	2020	2019
(mil ions of Canadian dol ars, except lease term and discount rate)Operating leasesOperating lease right-of-use assets, net1
	53	46
Operating lease liabilities - current2	6	6
Operating lease liabilities - long-term3	47	40
Total operating lease liabilities	53	46
Weighted average remaining lease termOperating leases
	9 years	9 years
Weighted average discount rateOperating leases
	3.1%	3.3%
1 Right-of-use assets are reported within Deferred amounts and other assets in the Consolidated Statements of Financial Position.2 Current lease liabilities are reported within Accounts payable and other and Accounts payable to affiliates in the Consolidated
Statements of Financial Position.
3 Long-term lease liabilities are reported within Other long-term liabilities in the Consolidated Statements of Financial Position.
As at December 31, 2020, we have lease commitments as detailed below:
			Operating leases
(mil ions of Canadian dol ars)2021
		8
2022		7
2023		7
2024		6
2025		6
Thereafter		27
Total undiscounted lease payments		61
Less imputed interest		(8)
Total operating lease liabilities		53

LESSORWe receive revenues from operating and sales-type leases primarily related to natural gas equipment and real estate assets. Our lease agreements have remaining lease terms of 1 month to 20 years for the year ended December 31, 2020.
As at December 31, 2020, the fol owing table sets out future lease payments to be received under operating lease and sales-type lease contracts where we are the lessor:
				Operating leases Sales-type leases
(mil ions of Canadian dol ars)
2021					2	1
2022					1	1
2023					1	1
2024					1	1
2025					1	1
Thereafter					3	18
Future lease payments to be received					9	23
					29

15. INCOME TAXES
INCOME TAX RATE RECONCILIATION
Year ended December 31,	2020	2019
(mil ions of Canadian dol ars)
			Earnings before income taxes	555	614
Canadian federal statutory income tax rate	15%	15%
Expected federal taxes at statutory rate	83	92
Increase/(decrease) resulting from:
Provincial and state income taxes	(13)	29
Effects of rate-regulated accounting1	(46)	(52)
Part VI.1 tax, net of federal Part I deduction1	41	—
Non-taxable portion of loss on sale of investment to unrelated party	—	(1)
Other2	(7)	(10)
Income tax expense	58	58
Effective income tax rate	10.5%	9.4%
1 The provincial tax component of these items is included in Provincial and state income taxes above.2 Includes miscel aneous permanent differences. These include the tax effect of items such as non-deductible meals and
entertainment and a change in prior year estimates arising from the filing of tax returns in respect of the prior year.
COMPONENTS OF PRETAX EARNINGS AND INCOME TAXES
Year ended December 31,	2020	2019
(mil ions of Canadian dol ars)

Earnings before income taxes
				555	638
Canada
United States				—	(24)
				555	614

Current income taxes
Canada				84	85
United States				(1)	4
				83	89

Deferred income taxes
Canada				(25)	(25)
United States				—	(6)
				(25)	(31)

Income tax expense				58	58
				30

COMPONENTS OF DEFERRED INCOME TAXESDeferred 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 fol ows:
December 31,	2020	2019

(mil ions of Canadian dol ars)
Deferred income tax liabilities
Property, plant and equipment					(1,586)	(1,497)
Regulatory assets					(368)	(335)
Deferrals					(10)	(17)
Pension and OPEB plans					(13)	(8)
Other					(2)	(1)
Total deferred income tax liabilities					(1,979)	(1,858)
Deferred income tax assets
Future removal and site restoration reserves					391	373
Minimum tax credits					40	30
Financial instruments					24	15
Other					2	7
Total deferred income tax assets					457	425
Net deferred income tax liabilities					(1,522)	(1,433)
Enbridge Gas is subject to taxation in Canada. Prior to its disposition on November 1, 2019, we were also subject to taxation in the United States through our whol y-owned subsidiary St. Lawrence Gas. The material jurisdiction in which we are subject to potential examinations is Canada (Federal and Ontario). We are open to examination by Canadian tax authorities for 2012 to 2020 tax years, and are currently under examination for income tax matters in Canada for 2015 to 2017 tax years.
UNRECOGNIZED TAX BENEFITS
Year ended December 31,			2020	2019
(mil ions of Canadian dol ars)Unrecognized tax benefits at beginning of year
			39	39
Gross increases for tax positions of current year			—	3
Gross decreases for tax positions of prior year			(2)	(1)
Lapses of statute of limitations			(3)	(2)
Unrecognized tax benefits at end of year			34	39
The unrecognized tax benefits as at December 31, 2020, 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. Income taxes for the years ended December 31, 2020 and 2019 included no amounts of interest and penalties. As at December 31, 2020 and 2019, interest and penalties of $1 mil ion have been accrued.
16. PENSION AND OTHER POSTRETIREMENT BENEFITS
PENSION PLANSWe provide pension benefits, covering substantial y al employees, through contributory and non-contributory registered defined benefit and defined contribution pension plans. We also provide non-registered pension benefits for certain employees through supplemental non-contributory defined benefit pension plans.
					31

Defined Benefit Pension Plan BenefitsBenefits payable from the defined benefit pension plans are based on each plan participant’s years ofservice and final average remuneration. Some benefits are partial y 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 BenefitsOur 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.
OTHER POSTRETIREMENT BENEFIT PLANSWe provide non-contributory supplemental health, dental, life and health spending account benefit coverage for certain qualifying retired employees, through unfunded defined benefit OPEB plans.
BENEFIT OBLIGATIONS, PLAN ASSETS AND FUNDED STATUSThe fol owing table details the changes in the benefit obligation, the fair value of plan assets and therecorded assets or liabilities for our defined benefit pension and OPEB plans:
	Pension	OPEB
December 31,	2020		2019	2020	2019
(mil ions of Canadian dol ars)

Change in benefit obligation
									2,331		2,080	170	153
Benefit obligation at beginning of year
Service cost						68	63	3		2
Interest cost						66	72	5		5
Participant contributions						15	14	—		—
Actuarial loss1						160	210	13		15
Benefits paid						(108)	(108)	(5)		(5)
Benefit obligation at end of year2						2,532	2,331	186		170
Change in plan assetsFair value of plan assets at beginning of year
						2,108	1,923	—		—
Actual return on plan assets						152	237	—		—
Employer contributions						52	42	5		5
Participant contributions						15	14	—		—
Benefits paid						(108)	(108)	(5)		(5)
Fair value of plan assets at end of year						2,219	2,108	—		—
Underfunded status at end of year						(313)	(223)	(186)		(170)
Presented as fol ows:
Deferred amounts and other assets						35	34	—		—
Accounts payable and other						(3)	(2)	(7)		(7)
Other long-term liabilities						(345)	(255)	(179)		(163)
						(313)	(223)	(186)		(170)
1 Primarily due to decrease in the discount rate used to measure the benefit obligations.2 For pension plans, the benefit obligation is the projected benefit obligation. For OPEB plans, the benefit obligation is the
accumulated postretirement benefit obligation. The accumulated benefit obligation for our pension plans was $2.4 bil ion and $2.2 bil ion as at December 31, 2020 and 2019, respectively.
						32

Certain of our pension plans have projected and accumulated benefit obligations in excess of the fair value of plan assets. For these plans, the projected benefit obligation, accumulated benefit obligation and fair value of plan assets were as fol ows:
December 31,	2020	2019
(mil ions of Canadian dol ars)Projected benefit obligation
			2,115	784
Accumulated benefit obligation			1,963	686
Fair value of plan assets			1,767	593
AMOUNT RECOGNIZED IN AOCIThe amount of pre-tax AOCI relating to our OPEB plans are as fol ows:
December 31,	2020	2019
(mil ions of Canadian dol ars)
						18	5
Net actuarial loss
Total amount recognized in AOCI			18	5
NET PERIODIC BENEFIT COST AND OTHER AMOUNTS RECOGNIZED IN COMPREHENSIVE INCOMEThe components of net periodic benefit cost and other amounts recognized in pre-tax Comprehensiveincome related to our pension and OPEB plans are as fol ows:
				Pension	OPEB
Year ended December 31,				2020	2019	2020	2019
(mil ions of Canadian dol ars) Service cost
							68	63 1	3	2
Interest cost1							66	72	5	5
Expected return on plan assets1							(136)	(129)	—	—
Amortization of net actuarial loss1,2							20	16	—	—
Net periodic benefit cost							18	22 —		8	7
Defined contribution benefit cost							2	2	—	—
Net pension and OPEB cost recognized in Earnings							20	24	8	7
Amount recognized in OCI:
Adjustment for rate-regulated accounting (Note 12)							—	(74)	—	—
Net actuarial loss arising during the year							—	—	13	16
Total amount recognized in OCI							—	(74)	13	16
Total amount recognized in Comprehensive income							20	(50)	21	23
1 Reported within Other income/(expense) in the Consolidated Statements of Earnings.2 Reflects amortization of net actuarial loss arising from pension plans that are recognized as long-term regulatory assets (Note 5).
ACTUARIAL ASSUMPTIONSThe weighted average assumptions made in the measurement of the benefit obligation and net periodicbenefit cost of our defined benefit pension and OPEB plans are as fol ows:
				Pension	OPEB

				2020	2019	2020	2019
Benefit obligationsDiscount rate
				2.6%	3.1%	2.6%	3.1%
Rate of salary increase				2.6%	3.2%	2.4%	3.3%
Net benefit costDiscount rate
				3.1%	3.8%	3.1%	3.8%
Rate of return on plan assets				6.5%	6.8%	N/A	N/A
Rate of salary increase				3.2%	3.2%	3.3%	3.3%
							33

ASSUMED HEALTH CARE COST TREND RATESThe assumed rates for the next year used to measure the expected cost of benefits are as fol ows:
	2020	2019
Health care cost trend rate assumed for next year	4.0%	4.0%
Rate to which the cost trend is assumed to decline (ultimate trend rate)	4.0%	4.0%
PLAN ASSETSWe 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; (i ) the investment horizon of the plan; (i i) 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 overal expected rate of return on plan assets is based on the asset al ocation targets with estimatesfor returns based on long-term expectations.
The asset al ocation targets and major categories of plan assets are as fol ows:
			Target	December 31,
Asset Category			Allocation	2020	2019
Equity securities			40.8%	46.3%	45.7%
Fixed income securities			35.5%	31.9%	33.7%
Alternatives1			23.7%	21.8%	20.6%
1 Alternatives 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.
The fol owing table summarizes the fair value of plan assets for our pension plans recorded at each fair value hierarchy level:
				2020	2019
December 31,					Level 11	Level 22		Level 33	Total	Level 11				Level 22	Level 33	Total
(mil ions of Canadian dol ars) Cash and cash equivalents
						50	—		—	50				53	—	—	53
Equity securities
Canada						103	111		— 214	92	112	— 204
Global						—	813		— 813	—	760	— 760
Fixed income securities
Government						125	249		— 374		117	272	— 389
Corporate						—	284		— 284	—	268	— 268
Alternatives4						—	—		466 466	—	—							427 427
Forward currency contracts						—	18		—	18				—	7	—	7
Total pension plan assets at fair value						278	1,475		466 2,219		262	1,419							427 2,108
1 Level 1 assets include assets with quoted prices in active markets for identical assets.2 Level 2 assets include assets with significant observable inputs.3 Level 3 assets include assets with significant unobservable inputs.4 Alternatives include investments in private debt, private equity, infrastructure and real estate funds.
				34

Changes in the net fair value of plan assets classified as Level 3 in the fair value hierarchy were as fol ows:
December 31,	2020	2019
(mil ions of Canadian dol ars)
			427	298
Balance at beginning of year
Unrealized and realized gains			(3)	9
Purchases and settlements, net			42	120
Balance at end of year			466	427
EXPECTED BENEFIT PAYMENTS
Year ending December 31,			2021	2022	2023	2024	2025	2026-2030
(mil ions of Canadian dol ars)
															108	109	111	113	115	599
Pension
OPEB									7	7	8	8	8	41
EXPECTED EMPLOYER CONTRIBUTIONSIn 2021, we expect to contribute approximately $39 mil ion and $7 mil ion to the pension plans and OPEB plans, respectively.
17. SEVERANCE COSTS
For the year ended December 31, 2020, we incurred $74 mil ion in severance costs related to Enbridge's voluntary workforce reduction program. For the year ended December 31, 2019, we incurred $39 mil ion in severance costs related to the amalgamation of EGD and Union Gas. Severance costs are presented in Operating and administrative expense in the Consolidated Statements of Earnings.
18. CHANGES IN OPERATING ASSETS AND LIABILITIES
Year ended December 31,	2020	2019
(mil ions of Canadian dol ars)Accounts receivable and other
			65	(17)
Accounts receivable from affiliates			(46)	(24)
Regulatory assets			156	29
Gas inventory			(39)	48
Deferred amounts and other assets			10	(2)
Accounts payable and other			(55)	(45)
Accounts payable to affiliates			(40)	18
Regulatory liabilities			54	105
Other long-term liabilities			(12)	(8)
Assets held for sale			—	12
			93	116

				35

19. RELATED PARTY TRANSACTIONS
Al related party transactions are provided 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 toby the related parties. Affiliates refer to Enbridge and companies that are either directly or indirectly owned by Enbridge.
Enbridge and its affiliates perform centralized corporate functions for us pursuant to applicable agreements, including legal, accounting, compliance, treasury, information technology and other areas, as wel as certain engineering and other services. We reimburse Enbridge for the expenses incurred to provide these services, as wel as for other expenses incurred on our behalf. In addition, we perform services and incur expenses on behalf of our affiliates, which are subsequently reimbursed. Our expenses and recoveries for these services are recorded in Operating and administrative expense in the Consolidated Statements of Earnings, and are based on the cost of actual services provided or using various al ocation methodologies. Our transactions with entities related through common or joint control and significantly influenced investees are as fol ows:
		Gas commodity		Operating and			Interest
	Operating	and distribution		administrative		Other	income/
Year ended December 31, 2020	revenues		costs		expense	Income	(expense)
(mil ions of Canadian dol ars)Enbridge Inc.
		—	—					131	6			14
Westcoast Energy Inc.		—	—					—	—			(6)
Tidal Energy Marketing Inc.		11	13					—	—			—
Tidal Energy Marketing (U.S.) LLC		—	18					—	—			—
Gazifère Inc.		26	—					—	—			—
Énergir, L.P.		37	—					—	—			—
Vector Pipeline, LLC (U.S.)		—	19					—	—			—
NEXUS Gas Transmission, LLC		—	116					—	—			—
Other affiliates, net		2	3					7	—			—
		Gas commodity		Operating and			Interest
	Operating	and distribution		administrative		Other	income/
Year ended December 31, 2019	revenues		costs		expense	Income	(expense)
(mil ions of Canadian dol ars)Enbridge Inc.
		—	—					99	—			7
Westcoast Energy Inc.		—	—					—	—	(24)
Tidal Energy Marketing Inc.										11	38		—	—	—
Tidal Energy Marketing (U.S.) LLC		—	37					—	—			—
Gazifère Inc.										30	—		—	—	—
Énergir, L.P.										10	—		—	—	—
Vector Pipeline, LLC (U.S.)		—	19					—	—			—
NEXUS Gas Transmission, LLC		—	114					—	—			—
Other affiliates, net		2	8					6	—			(1)
		36

Amounts due from/(to) related parties are as fol ows:
December 31,	2020	2019
(mil ions of Canadian dol ars)Westcoast Energy Inc.1
			—	(656)
Enbridge Inc.2			(68)	(39)
Enbridge Employee Services Canada Inc.			(38)	(46)
NEXUS Gas Transmission, LLC (U.S.)			(10)	(10)
Enbridge Pipelines Inc.			45	—
Union Energy Solutions Limited Partnership			29	23
Other affiliates, net3			7	(2)
			(35)	(730)
1 Included a $650 mil ion subordinated promissory note from Westcoast, which was repaid in the second quarter of 2020.2 Includes net derivative payable balances to affiliate.3 Includes current portion of operating lease liabilities to affiliates.
SHARE CAPITALDuring the year ended December 31, 2020, common share dividends declared on our Class A and Class B common shares were $243 mil ion (2019 - $506 mil ion) and $207 mil ion (2019 - $431 mil ion), respectively. During 2020, we also completed the return of capital transactions, and received capital contributions, as described in Note 11. Share Capital.
FINANCING TRANSACTIONOn April 1, 2020, we repaid the outstanding $650 mil ion subordinated promissory note, as wel as the related interest payable, due to Westcoast
GAS METER SERVICESWe purchase gas meter services from Lakeside Performance Gas Services Ltd. (Lakeside), such as ongoing meter exchanges and inspections for customers in our franchise area. As of December 1, 2020, Lakeside became an affiliate. In the month of December 2020, we purchased gas meter services from Lakeside totaling $3 mil ion, of which a portion of these costs was expensed to Operating and administrative expense and the remainder capitalized in Property, plant and equipment. We wil continue purchasing these services at prevailing market prices under normal trade terms.
WHOLESALE SERVICESWe provide gas procurement and transportation services to Gazifère Inc., an affiliate, pursuant to a contract negotiated between us and approved by the OEB and Régie de l’énergie.
LEASESWe incur operating lease payments related to natural gas transportation and storage services from various affiliates. Total affiliate right-of-use assets and lease liabilities as at December 31, 2020 were $51 mil ion (2019 - $43 mil ion) and $51 mil ion (2019 - $43 mil ion), respectively. See Note 14 for further discussion.
DERIVATIVE INSTRUMENTSAs at December 31, 2020, we had a net payable balance of $36 mil ion (2019 - $22 mil ion) due to Enbridge in respect of derivative instruments that they have entered into on our behalf. See Note 13. Risk Management and Financial Instruments for further discussion.
OTHEROur cash balances are subject to a concentration banking arrangement with Enbridge. Interest is received or paid at market rates.
			37

20. 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 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 in 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 typical y 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, historical y, 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, 2020, 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.
	38

21. COMMITMENTS AND CONTINGENCIES
COMMITMENTSAt December 31, 2020, we have commitments as detailed below:
		Less
		than
	Total	1 year	2 years	3 years	4 years	5 years Thereafter

(mil ions of Canadian dol ars)
Annual debt maturities1								8,695	375	125	350	300	745		6,800
Interest obligations2								5,521	359	345	342	327	311		3,837
Purchase of services, pipe
and other materials,
including transportation3,4	5,922	1,436	691	536	487	466		2,306
Right-of-way commitments5	527	9							9	9	9	9	482
Total							20,665	2,179	1,170	1,237	1,123	1,531		13,425
1 Includes debentures and term notes, and excludes short-term borrowings, debt discounts, debt issue costs, finance lease
obligations and fair value adjustment from push down accounting. Changes to the planned funding requirements are dependent on the terms of any debt refinancing agreements. Therefore, the actual timing of future cash repayments could be material y different than presented above.
2 Includes debentures and term notes bearing interest at fixed rates.3 Includes firm capacity payments that provide us with uninterrupted firm access to natural gas transportation and storage;
contractual obligations to purchase physical quantities of natural gas; contracts for software, consulting or advisory services, as wel as customer care services.
4 Includes capital and operating commitments.5 Right-of-way payments related to cancel able gas storage payments that are reasonably likely to occur for the remaining life of al
storage reservoirs.
ENVIRONMENTALWe are subject to various federal, provincial 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 natural gas pipeline operations, and we are, at times, subject to environmental remediation at various contaminated sites. We manage this environmental risk through appropriate environmental policies 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 potential y responsible parties, we wil be responsible for payment of liabilities arising from environmental incidents associated with our operating activities.
Former Manufactured Coal Gas Plant SitesThe remediation of discontinued manufactured gas plant (MGP) sites may result in future costs. We were named as a defendant in ten lawsuits issued in 1991 and 1993 in the Ontario Court of Justice (General Division), commenced by the Corporation of the City of Toronto (the City). Two additional actions were commenced by the Toronto Board of Education (the School Board) in 1991. In these actions, the City and the School Board claimed damages totaling approximately $79 mil ion for al eged contamination of lands acquired by the City for the purposes of its Ataratiri housing project. The City al eges that these lands are contaminated by coal tar deposited on the properties during a time when al or a portion of such lands were utilized by us for the operation of our MGP.
While these Statements of Claim were filed by the City and the School Board, they were never formal y served on us. It was and remains our understanding that these lawsuits were initiated, at least in part, because of concerns that the passage of time might give rise to limitation period defences. Rather than litigate, Enbridge Gas and the City entered into an agreement (known as a Tol ing Agreement) pursuant to which the City and the School Board agreed to forbear from serving the Statements of Claim pending further discussions with us. To our knowledge, neither the City nor the School Board has taken any steps to advance the lawsuits.
			39

Given the novel nature of such environmental claims, the law as it relates to such claims is not settled. Should remediation of former MGP sites be required, it may result in future costs, the quantum of which cannot be determined at this time for several reasons. First, there is no certainty about the presence of and the extent of al eged coal tar contamination at or near former MGP sites. Second, there are a number of potential alternative remediation, isolation and containment approaches, which could vary widely in cost.
Although there are no known regulatory precedents in Canada, there are precedents in the U.S. for the recovery in rates of costs relating to the remediation of former MGP sites. From 2006 to 2018, the OEB approved the establishment of deferral accounts to record the costs of investigating, defending and dealing with ongoing MGP-related claims. We expect that if it is found that we must contribute to any remediation costs, either as a result of a lawsuit or government order, we would be general y al owed to recover in rates those costs not recovered through insurance or by other means. Accordingly, we believe that the ultimate outcome of these matters wil not have a significant impact on our financial position.
Hamilton Contaminated SiteIn April 2016, the Ontario Ministry of the Environment, Conservation and Parks (MECP), formerly the Ministry of the Environment and Climate Change, issued a Director’s Order (the Order) naming us, along with other parties, as an impacted property owner in connection with a contaminated site adjacent to a property of Enbridge Gas in Hamilton. In May 2016, we appealed the Order, and in June 2016, the Environmental Review Tribunal (the Tribunal), on consent of the MECP’s Director, stayed the application of parts of the Order. The Tribunal extended the stay of the Order several times, which has al owed the owner of the property, with the cooperation of the adjacent owners, to prepare a plan of action, including discussions with the MECP and other neighbors. On February 4, 2021, the MECP determined that we and other parties have complied with the Order and no further obligations are outstanding. Accordingly, we withdrew our appeal and the Tribunal has accepted the withdrawal and is closing its file.
OTHER LITIGATIONWe are subject to various other legal and regulatory actions and proceedings which arise in the normal course of business, including interventions in regulatory proceedings and chal enges 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 wil not have a material impact on our financial position or results of operations.
TAX MATTERSWe maintain tax liabilities related to uncertain tax positions. While ful y supportable in our view, these tax positions, if chal enged by tax authorities, may not be ful y sustained on review.
	40