Exhibit 99.2

FORTIS INC.

Audited Consolidated Financial Statements

As at and for the years ended December 31, 2020 and 2019

TABLE OF CONTENTS

Management's Report on Internal Control over Financial Reporting		i	NOTE 11	Intangible Assets	26
Report of Independent Registered Public Accounting Firm - Opinion on the Financial Statements		ii	NOTE 12	Goodwill	26
Report of Independent Registered Public Accounting Firm - Opinion on Internal Control over Financial Reporting		v	NOTE 13	Accounts Payable and Other Current Liabilities	26
Consolidated Balance Sheets		1	NOTE 14	Long-Term Debt	27
Consolidated Statements of Earnings		2	NOTE 15	Leases	30
Consolidated Statements of Comprehensive Income		2	NOTE 16	Other Liabilities	32
Consolidated Statements of Cash Flows		3	NOTE 17	Common Shares	33
Consolidated Statements of Changes in Equity		4	NOTE 18	Earnings Per Common Share	33
Notes to Consolidated Financial Statements			NOTE 19	Preference Shares	33
NOTE 1	Description of Business	5	NOTE 20	Accumulated Other Comprehensive Income	35
NOTE 2	Regulation	6	NOTE 21	Stock-Based Compensation Plans	35
NOTE 3	Summary of Significant Accounting Policies	10	NOTE 22	Disposition	38
NOTE 4	Segmented Information	18	NOTE 23	Other Income, Net	38
NOTE 5	Revenue	20	NOTE 24	Income Taxes	39
NOTE 6	Accounts Receivable and Other Current Assets	21	NOTE 25	Employee Future Benefits	41
NOTE 7	Inventories	22	NOTE 26	Supplementary Cash Flow Information	46
NOTE 8	Regulatory Assets and Liabilities	22	NOTE 27	Fair Value of Financial Instruments and Risk Management	46
NOTE 9	Other Assets	24	NOTE 28	Commitments and Contingencies	50
NOTE 10	Property, Plant and Equipment	24

Management's Report on Internal Control over Financial Reporting

Management of Fortis Inc. and its subsidiaries (the "Corporation") is responsible for establishing and maintaining adequate internal control over financial reporting ("ICFR"). The Corporation's ICFR is designed by, or under the supervision of, the Corporation's President and Chief Executive Officer ("CEO") and Executive Vice President, Chief Financial Officer ("CFO") and effected by the Corporation's board of directors, management and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, ICFR may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

The Corporation's management, including its CEO and CFO, assessed the effectiveness of the Corporation's ICFR as of December 31, 2020, based on the criteria set forth in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this assessment, management concluded that, as of December 31, 2020, the Corporation's ICFR was effective.

The Corporation's ICFR as of December 31, 2020 has been audited by Deloitte LLP, an Independent Registered Public Accounting Firm, which also audited the Corporation's consolidated financial statements for the year ended December 31, 2020. Deloitte LLP issued an unqualified opinion for both audits.

February 11, 2021

/s/ David G. Hutchens

David G. Hutchens

President and Chief Executive Officer, Fortis Inc.

/s/ Jocelyn H. Perry

Jocelyn H. Perry

Executive Vice President, Chief Financial Officer, Fortis Inc.

St. John's, Canada

i

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Fortis Inc.

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Fortis Inc. and subsidiaries (the "Corporation") as of December 31, 2020 and 2019, the related consolidated statements of earnings, comprehensive income, cash flows and changes in equity for each of the two years in the period ended December 31, 2020, and the related notes (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Corporation as of December 31, 2020 and 2019, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2020, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) ("PCAOB"), the Corporation’s internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 11, 2021, expressed an unqualified opinion on the Corporation’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Corporation's management. Our responsibility is to express an opinion on the Corporation's financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current-period audit of the financial statements that were communicated or required to be communicated to the audit committee and that (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Assessment for Impairment of Goodwill - Refer to Notes 3 and 12 to the financial statements

Critical Audit Matter Description

The Corporation assesses goodwill for impairment annually as well as whenever any event or other change indicates that the fair value of a reporting unit may be below its carrying value. Management has determined that there is no impairment based on its current annual assessment.

ii

Management's assessment utilizes the income approach which is based on underlying estimates and assumptions with varying degrees of uncertainty. Those with the highest degree of subjectivity and impact are the assumed growth rates and discount rates. Auditing these estimates and assumptions required a high degree of audit judgment and effort, including the need to involve a fair value specialist.

How the Critical Audit Matter was Addressed in the Audit

Our audit procedures related to the growth rate and discount rate used by management to estimate the fair value of more recently acquired reporting units included the following:

•    Evaluating the effectiveness of controls over the estimated fair value of the reporting units, including the review and approval of the growth rate and discount rate selected by management.

•    Evaluating management's ability to accurately forecast the growth rate by:

•    Assessing the methodology used in management's determination of the growth rate; and

•    Comparing management's assumptions to historical data and available market trends.

•    With the assistance of a fair value specialist, evaluating the reasonableness of the discount rate by:

•    Testing the source information underlying the determination of the discount rate; and

•    Developing a range of independent estimates and comparing those to the discount rate selected by management.

Impact of Rate Regulation on the financial statements - Refer to Notes 2, 3 and 8 to the financial statements

Critical Audit Matter Description

The Corporation's regulated utilities are subject to rate regulation and annual earnings oversight by various federal, state and provincial regulatory authorities who have jurisdiction in the United States and Canada. Rates and resultant earnings of the Corporation's regulated utilities are determined under cost of service regulation, with some using performance-based rate-setting mechanisms. The regulation of rates is premised on the full recovery of prudently incurred costs and a reasonable rate of return on asset value ("ROA") or common shareholders' equity ("ROE"). Regulatory decisions can have an impact on the timely recovery of costs and the regulator-approved ROE and/or ROA. Accounting for the economics of rate regulation impacts multiple financial statement line items and disclosures, such as property, plant, and equipment; regulatory assets and liabilities; operating revenues and expenses; income taxes; and depreciation expense.

We identified the impact of rate regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impacted account balances and disclosures and the high degree of subjectivity involved in assessing the potential impact of future regulatory orders on the financial statements. Management judgments include assessing the likelihood of recovery of costs incurred or a refund to customers through the rate-setting process. While the Corporation’s regulated utilities have indicated they expect to recover costs from customers through regulated rates, there is a risk that the respective regulatory authority will not approve full recovery of the costs incurred and a reasonable ROE and/or ROA. Auditing these matters required especially subjective judgment and specialized knowledge of accounting for rate regulation due to its inherent complexities across different jurisdictions.

iii

How the Critical Audit Matter was Addressed in the Audit

Our audit procedures related to the likelihood of recovery of costs incurred or a refund to customers through the rate-setting process, included the following, among others:

•Evaluating the effectiveness of controls over the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates or of a future reduction in rates.

•Assessing relevant regulatory orders, regulatory statutes and interpretations as well as procedural memorandums, utility and intervener filings, and other publicly available information to evaluate the likelihood of recovery in future rates or of a future reduction in rates and the ability to earn a reasonable ROA or ROE.

•For regulatory matters in progress, inspecting the regulated utilities’ filings for any evidence that might contradict management’s assertions. We obtained an analysis from management and letters from internal and external legal counsel, as appropriate, regarding cost recoveries or a future reduction in rates.

•Evaluating the Corporation's disclosures related to the impacts of rate regulation, including the balances recorded and regulatory developments.

/s/ Deloitte LLP

Chartered Professional Accountants

St. John's, Canada

February 11, 2021

We have served as the Corporation's auditor since 2017.

iv

Report of Independent Registered Public Accounting Firm

To the Shareholders and the Board of Directors of Fortis Inc.

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of Fortis Inc. and subsidiaries (the "Corporation") as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2020, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2020, of the Corporation and our report dated February 11, 2021, expressed an unqualified opinion on those financial statements.

Basis for Opinion

The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte LLP

Chartered Professional Accountants

St. John's, Canada

February 11, 2021

v

FORTIS INC.
Consolidated Balance Sheets
As at December 31
(in millions of Canadian dollars)
	2020		2019
ASSETS
Current assets
Cash and cash equivalents	$	249	$	370
Accounts receivable and other current assets (Note 6)	1,369		1,297
Prepaid expenses	102		88
Inventories (Note 7)	422		394
Regulatory assets (Note 8)	470		425
Total current assets	2,612		2,574
Other assets (Note 9)	670		620
Regulatory assets (Note 8)	3,118		2,958
Property, plant and equipment, net (Note 10)	35,998		33,988
Intangible assets, net (Note 11)	1,291		1,260
Goodwill (Note 12)	11,792		12,004
Total assets	$	55,481	$	53,404
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings (Note 14)	$	132	$	512
Accounts payable and other current liabilities (Note 13)	2,321		2,402
Regulatory liabilities (Note 8)	441		572
Current installments of long-term debt (Note 14)	1,254		690
Total current liabilities	4,148		4,176
Other liabilities (Note 16)	1,599		1,446
Regulatory liabilities (Note 8)	2,662		2,786
Deferred income taxes (Note 24)	3,344		2,969
Long-term debt (Note 14)	23,113		21,501
Finance leases (Note 15)	331		413
Total liabilities	35,197		33,291
Commitments and contingencies (Note 28)
Equity
Common shares (Note 17) (1)	13,819		13,645
Preference shares (Note 19)	1,623		1,623
Additional paid-in capital	11		11
Accumulated other comprehensive income (Note 20)	34		336
Retained earnings	3,210		2,916
Shareholders' equity	18,697		18,531
Non-controlling interests	1,587		1,582
Total equity	20,284		20,113
Total liabilities and equity	$	55,481	$	53,404
(1) No par value. Unlimited authorized shares. 466.8 million and 463.3 million issued and outstanding as at December 31, 2020 and 2019, respectively	Approved on Behalf of the Board
	/s/ Douglas J. Haughey		/s/ Tracey C. Ball
	Douglas J. Haughey,		Tracey C. Ball,
See accompanying Notes to Consolidated Financial Statements	Director		Director

1

FORTIS INC.
Consolidated Statements of Earnings
For the years ended December 31
(in millions of Canadian dollars, except per share amounts)
		2020		2019
Revenue (Note 5)		$	8,935	$	8,783
Expenses
Energy supply costs		2,562		2,520
Operating expenses		2,437		2,452
Depreciation and amortization		1,428		1,350
Total expenses		6,427		6,322
Gain on disposition (Note 22)		—		577
Operating income		2,508		3,038
Other income, net (Note 23)		154		138
Finance charges		1,042		1,035
Earnings before income tax expense		1,620		2,141
Income tax expense (Note 24)		231		289
Net earnings		$	1,389	$	1,852
Net earnings attributable to:
	Non-controlling interests	$	115	$	130
	Preference equity shareholders	65		67
	Common equity shareholders	1,209		1,655
		$	1,389	$	1,852
Earnings per common share (Note 18)
Basic		$	2.60	$	3.79
Diluted		$	2.60	$	3.78
See accompanying Notes to Consolidated Financial Statements

FORTIS INC.
Consolidated Statements of Comprehensive Income
For the years ended December 31
(in millions of Canadian dollars)
		2020		2019
Net earnings		$	1,389	$	1,852
Other comprehensive loss
Unrealized foreign currency translation losses, net of hedging activities and income tax expense of $3 million and $13 million, respectively		(311)		(660)
Other, net of income tax recovery of $9 million and $5 million, respectively		(27)		(7)
		(338)		(667)
Comprehensive income		$	1,051	$	1,185
Comprehensive income attributable to:
	Non-controlling interests	$	79	$	55
	Preference equity shareholders	65		67
	Common equity shareholders	907		1,063
		$	1,051	$	1,185
See accompanying Notes to Consolidated Financial Statements

2

FORTIS INC.
Consolidated Statements of Cash Flows
For the years ended December 31
(in millions of Canadian dollars)
			2020		2019
Operating activities
Net earnings			$	1,389	$	1,852
Adjustments to reconcile net earnings to net cash provided by
operating activities:
		Depreciation - property, plant and equipment	1,282		1,199
		Amortization - intangible assets	131		125
		Amortization - other	15		26
		Deferred income tax expense (Note 24)	226		247
		Equity component, allowance for funds used during construction (Note 23)	(78)		(74)
		Gain on disposition (Note 22)	—		(583)
		Other	165		145
Change in long-term regulatory assets and liabilities			5		(106)
Change in working capital (Note 26)			(434)		(168)
Cash from operating activities			2,701		2,663
Investing activities
Capital expenditures - property, plant and equipment			(3,857)		(3,499)
Capital expenditures - intangible assets			(182)		(221)
Contributions in aid of construction			68		102
Proceeds on disposition (Note 22)			—		995
Other			(161)		(145)
Cash used in investing activities			(4,132)		(2,768)
Financing activities
Proceeds from long-term debt, net of issuance costs (Note 14)			3,470		937
Repayments of long-term debt, net of extinguishment costs, and finance leases			(1,251)		(1,676)
Borrowings under committed credit facilities			5,648		5,892
Repayments under committed credit facilities			(5,299)		(6,290)
Net change in short-term borrowings			(413)		472
Issue of common shares, net of costs, and dividends reinvested (Note 17)			58		1,442
Dividends
	Common shares, net of dividends reinvested		(786)		(494)
	Preference shares		(65)		(67)
	Subsidiary dividends paid to non-controlling interests		(65)		(73)
Other			30		11
Cash from financing activities			1,327		154
Effect of exchange rate changes on cash and cash equivalents			(17)		(26)
Change in cash and cash equivalents			(121)		23
Cash and change in cash associated with assets held for sale			—		15
Cash and cash equivalents, beginning of year			370		332
Cash and cash equivalents, end of year			$	249	$	370
Supplementary Cash Flow Information (Note 26)
See accompanying Notes to Consolidated Financial Statements

3

FORTIS INC.
Consolidated Statements of Changes in Equity
For the years ended December 31, 2020 and 2019
(in millions of Canadian dollars, except share numbers)
	Common Shares (# millions)	Common Shares (Note 17)		Preference Shares (Note 19)		Additional Paid-In Capital		Accumulated Other Comprehensive Income (Loss) (Note 20)		Retained Earnings		Non-Controlling Interests		Total Equity
As at December 31, 2019	463.3	$	13,645	$	1,623	$	11	$	336	$	2,916	$	1,582	$	20,113
Net earnings	—	—		—		—		—		1,274		115		1,389
Other comprehensive loss	—	—		—		—		(302)		—		(36)		(338)
Common shares issued	3.5	174		—		(3)		—		—		—		171
Advances to non-controlling interests	—	—		—		—		—		—		(13)		(13)
Subsidiary dividends paid to non-controlling interests	—	—		—		—		—		—		(65)		(65)
Dividends declared on common shares ($1.965 per share)	—	—		—		—		—		(915)		—		(915)
Dividends on preference shares	—	—		—		—		—		(65)		—		(65)
Other	—	—		—		3		—		—		4		7
As at December 31, 2020	466.8	$	13,819	$	1,623	$	11	$	34	$	3,210	$	1,587	$	20,284
As at December 31, 2018	428.5	$	11,889	$	1,623	$	11	$	928	$	2,082	$	1,923	$	18,456
Net earnings	—	—		—		—		—		1,722		130		1,852
Other comprehensive loss	—	—		—		—		(592)		—		(75)		(667)
Common shares issued	34.8	1,756		—		(5)		—		—		—		1,751
Advances to non-controlling interests	—	—		—		—		—		—		(8)		(8)
Subsidiary dividends paid to non-controlling interests	—	—		—		—		—		—		(73)		(73)
Dividends declared on common shares ($1.855 per share)	—	—		—		—		—		(821)		—		(821)
Dividends on preference shares	—	—		—		—		—		(67)		—		(67)
Disposition (Note 22)	—	—		—		—		—		—		(318)		(318)
Other	—	—		—		5		—		—		3		8
As at December 31, 2019	463.3	$	13,645	$	1,623	$	11	$	336	$	2,916	$	1,582	$	20,113
See accompanying Notes to Consolidated Financial Statements

4

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

1. DESCRIPTION OF BUSINESS

Fortis Inc. ("Fortis" or the "Corporation") is a well-diversified North American regulated electric and gas utility holding company. Entities within the reporting segments that follow operate with substantial autonomy.

Regulated Utilities

ITC: ITC Investment Holdings Inc., ITC Holdings Corp. and the electric transmission operations of its regulated operating subsidiaries, which include International Transmission Company ("ITCTransmission"), Michigan Electric Transmission Company, LLC ("METC"), ITC Midwest LLC ("ITC Midwest"), and ITC Great Plains, LLC. Fortis owns 80.1% of ITC and an affiliate of GIC Private Limited owns a 19.9% minority interest.

ITC owns and operates high-voltage transmission lines in Michigan's lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma.

UNS Energy: UNS Energy Corporation, which primarily includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas").

UNS Energy's largest operating subsidiary, TEP, and UNS Electric are vertically integrated regulated electric utilities. They generate, transmit and distribute electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County and parts of Cochise County, as well as in Santa Cruz and Mohave counties. TEP also sells wholesale electricity to other entities in the western United States. Together they own generating capacity of 3,233 megawatts ("MW"), including 54 MW of solar capacity. Several generating assets in which they have an interest are jointly owned.

UNS Gas is a regulated gas distribution utility serving retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties.

Central Hudson: CH Energy Group, Inc., which includes primarily Central Hudson Gas & Electric Corporation. Central Hudson is a regulated electric and gas transmission and distribution utility that serves portions of New York State's Mid-Hudson River Valley and owns gas-fired and hydroelectric generating capacity totalling 65 MW.

FortisBC Energy: FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, provides transmission and distribution services in over 135 communities. FortisBC Energy obtains natural gas supplies primarily from northeastern British Columbia and Alberta on behalf of most customers.

FortisAlberta: FortisAlberta Inc. is a regulated electricity distribution utility operating in a substantial portion of southern and central Alberta. It is not involved in the direct sale of electricity.

FortisBC Electric: FortisBC Inc. is an integrated regulated electric utility operating in the southern interior of British Columbia. It owns four hydroelectric generating facilities with a combined capacity of 225 MW. It also provides operating, maintenance and management services relating to five hydroelectric generating facilities in British Columbia that are owned by third parties.

Other Electric: Eastern Canadian and Caribbean utilities, as follows: Newfoundland Power Inc. ("Newfoundland Power"); Maritime Electric Company, Limited ("Maritime Electric"); FortisOntario Inc. ("FortisOntario"); a 39% equity investment in Wataynikaneyap Power Limited Partnership ("Wataynikaneyap Partnership"); an approximate 60% controlling interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities"); FortisTCI Limited and Turks and Caicos Utilities Limited (collectively, "FortisTCI"); and a 33% equity investment in Belize Electricity Limited ("Belize Electricity").

5

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador with a generating capacity of 143 MW, of which 97 MW is hydroelectric. Maritime Electric is an integrated regulated electric utility and the principal distributor of electricity on Prince Edward Island ("PEI") with on-Island generating capacity of 130 MW. FortisOntario consists of three regulated electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario with a generating capacity of 5 MW. Wataynikaneyap Partnership is a partnership between 24 First Nations communities, Fortis and Algonquin Power & Utilities Corp. with a mandate to connect remote First Nations communities to the electricity grid in Ontario through the development of new transmission lines.

Caribbean Utilities is an integrated regulated electric utility and the sole electricity provider on Grand Cayman with a diesel-powered generating capacity of 161 MW. FortisTCI consists of two integrated regulated electric utilities that provide electricity to certain Turks and Caicos Islands and has a diesel-powered generating capacity of 91 MW. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize.

Non-Regulated

Energy Infrastructure: Long-term contracted generation assets in Belize and the Aitken Creek natural gas storage facility ("Aitken Creek") in British Columbia. Generation assets in Belize consist of three hydroelectric generating facilities with a combined generating capacity of 51 MW, held through the Corporation's indirectly wholly owned subsidiary Belize Electric Company Limited ("BECOL"). The output is sold to Belize Electricity under 50-year power purchase agreements ("PPAs"). Fortis indirectly owns 93.8% of Aitken Creek, with the remainder owned by BP Canada Energy Company. Aitken Creek is the only underground natural gas storage facility in British Columbia and has a working gas capacity of 77 billion cubic feet. The long-term contracted generation assets in British Columbia, the Waneta Expansion hydroelectric generating facility ("Waneta Expansion"), were sold on April 16, 2019.

Corporate and Other: Captures expenses and revenues not specifically related to any reportable segment and those business operations that are below the required threshold for segmented reporting, including net corporate expenses of Fortis.

2. REGULATION

General

The earnings of the Corporation's regulated utilities are determined under cost of service ("COS") regulation, with some using performance-based rate setting ("PBR") mechanisms.

Under COS regulation, the regulator sets customer rates to permit a reasonable opportunity for the timely recovery of the estimated costs of providing service, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). PBR mechanisms generally apply a formula that incorporates inflation and assumed productivity improvements for a set term.

The ability to recover prudently incurred costs of providing service and earn the regulator‑approved rate of return on common shareholders' equity ("ROE") and/or rate of return on rate base assets ("ROA") may depend on achieving the forecasts established in the rate-setting process. There can be varying degrees of regulatory lag between when costs are incurred and when they are reflected in customer rates.

The Corporation's regulated utilities, where applicable, are permitted by their respective regulators to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms (Note 8).

6

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Nature of Regulation
		Allowed Common Equity (%)	Allowed ROE (1) (%)
Regulated Utility	Regulatory Authority		2020	2019	Significant Features
ITC (2) (3)	Federal Energy Regulatory Commission ("FERC")	60.0	10.77	10.63	Cost-based formula rates, with annual true-up mechanism (4) Incentive adders
TEP	Arizona Corporation Commission ("ACC") (5) FERC (6)	50.0	9.75	9.75	COS regulation Historical test year Formula transmission rates
		54.0	10.40	10.40
UNS Electric	ACC	52.8	9.50	9.50
UNS Gas	ACC	50.8	9.75	9.75
Central Hudson (7)	New York State Public Service Commission ("PSC")	50.0	8.80	8.80	COS regulation Future test year
FortisBC Energy	British Columbia Utilities Commission ("BCUC")	38.5	8.75	8.75	COS regulation with formula components and incentives (8)
FortisBC Electric	BCUC	40.0	9.15	9.15	Future test year
FortisAlberta	Alberta Utilities Commission ("AUC")	37.0	8.50	8.50	PBR (9)
Newfoundland Power	Newfoundland and Labrador Board of Commissioners of Public Utilities	45.0	8.50	8.50	COS regulation Future test year
Maritime Electric	Island Regulatory and Appeals Commission	40.0	9.35	9.35	COS regulation Future test year
FortisOntario (10)	Ontario Energy Board	40.0	8.52-9.30	8.78-9.30	COS regulation with incentive mechanisms
Caribbean Utilities (11)	Utility Regulation and Competition Office	N/A	6.75-8.75	7.50-9.50	COS regulation Rate-cap adjustment mechanism based on published consumer price indices
FortisTCI (12)	Government of the Turks and Caicos Islands	N/A	15.00-17.50	15.00-17.50	COS regulation Historical test year

(1)    ROA for Caribbean Utilities and FortisTCI

(2)    Includes the allowed common equity and base ROE plus incentive adders for ITCTransmission, METC, and ITC Midwest

(3)    Including incentive adders, the May 2020 FERC decision implies an all-in ROE for ITC's subsidiaries operating in the Midcontinent Independent System Operator ("MISO") region of 10.77%, up from 10.63% as set in the November 2019 decision. See "Significant Regulatory Developments" below

(4)    Annual true-up reflected in rates within a two-year period

(5)    Effective January 1, 2021, 53% allowed common equity and 9.15% ROE with 0.20% return on the fair value increment. See "COVID-19 Pandemic Impacts - Delayed and Postponed Regulatory Proceedings" below

(6)    Approved effective August 1, 2019, subject to refund following hearing and settlement procedures. As at December 31, 2020, $19 million (2019 - $5 million) has been reserved as a regulatory liability

(7)    Pursuant to a three-year settlement agreement arising from a 2017 general rate application, Central Hudson's rates reflect a capital structure of 48%, 49% and 50% common equity as of July 1, 2018, 2019 and 2020, respectively. See "COVID-19 Pandemic Impacts - Delayed and Postponed Regulatory Proceedings" below

(8)    Formula and incentives have been set through 2024. See "Significant Regulatory Developments" below

(9)    FortisAlberta is subject to PBR including mechanisms for flow-through costs and capital expenditures not otherwise recovered through customer rates. FortisAlberta's current PBR term expires as of December 31, 2022

(10)    Two of FortisOntario's utilities follow COS regulation with incentive mechanisms, while the remaining utility is subject to a 35-year franchise agreement expiring in 2033

(11)    Operates under licences from the Government of the Cayman Islands. Its exclusive transmission and distribution licence is for an initial 20-year period, expiring in April 2028, with a provision for automatic renewal. Its non-exclusive generation licence is for a 25-year term, expiring in November 2039

(12)    Operates under 50-year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037

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Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

COVID-19 Pandemic Impacts

The novel coronavirus ("COVID-19") pandemic resulted in several customer relief initiatives as well as the delay and postponement of several regulatory proceedings in 2020, as described below. The Corporation's significant regulatory proceedings, including TEP's general rate application as well as FortisAlberta's 2021 generic cost of capital ("GCOC") and Alberta Electric System Operator ("AESO") customer contribution proceedings, were concluded by the end of 2020.

Customer Relief Initiatives

UNS Energy

Pursuant to the ACC's approval of the utility's customer relief initiatives, TEP refunded to customers approximately $11 million of collected demand side management funds in excess of program costs.

In December 2020, the ACC enacted a bill credit and payment program for residential electric customers who are behind on their electric bills as a result of the COVID-19 pandemic, including automatic enrollment into an eight-month payment plan for qualified customers. TEP voluntarily created payment arrangements for commercial customers.

Central Hudson

In March 2020, as agreed with the PSC, Central Hudson postponed the collection in customer rates of approximately $4 million of deferred costs related mainly to environmental remediation until July 1, 2021.

FortisBC Energy and FortisBC Electric

In April 2020, pursuant to the BCUC's approval of the utilities' customer relief initiatives, FortisBC Energy and FortisBC Electric implemented three-month bill deferrals for certain customer classes, the repayment of which commenced in the third quarter of 2020. The BCUC also authorized the deferral of otherwise uncollectible revenue from customers, the recovery of which will be determined through a future rate filing once the financial impact of the pandemic is known.

Delayed and Postponed Regulatory Proceedings

UNS Energy

General Rate Application: TEP filed a rate application in April 2019 based on a 2018 test year. In December 2020 the ACC issued a rate order including new customer rates effective January 1, 2021 ("2020 Rate Order"). Provisions of the 2020 Rate Order include: (i) an increase in non-fuel revenue of $77 million (US$58 million); (ii) an allowed ROE of 9.15%, with a 0.20% return on the fair value increment and a capital structure of 53% common equity; and (iii) a rate base of approximately $3.5 billion (US$2.7 billion) which includes post-test year investments in Gila River natural gas generation station Unit 2 and 10 natural gas reciprocating internal combustion engine units.

Central Hudson

2020 Rates: In June 2020, the PSC approved Central Hudson's request to postpone scheduled electric and gas delivery rate increases, reflecting an increase in the equity component of its capital structure from 49% to 50%, from July 1, 2020 to October 1, 2020. The deferred revenue associated with the delay is being collected over the nine-month period to June 30, 2021.

COVID-19 Proceeding: In June 2020, the PSC initiated a generic proceeding to identify and address the effects of the COVID-19 pandemic. The outcome of this proceeding and potential impacts, if any, are unknown at this time.

FortisAlberta

Generic Cost of Capital Proceeding: In December 2018, the AUC initiated a GCOC proceeding to consider a formula-based approach to setting the allowed ROE beginning in 2021 and whether any process changes were necessary for determining capital structure in years in which a ROE formula is in place. In October 2020, given the time that had passed since initiation of the proceeding and ongoing economic uncertainty, the AUC concluded the proceeding and set the ROE for 2021 at 8.5% using a capital structure of 37% common equity, consistent with 2020. In December 2020, the AUC initiated a new GCOC proceeding to establish the cost of capital parameters for 2022 and possibly one or more future years. This proceeding is expected to be ongoing throughout 2021.

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Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Other Electric

Caribbean Utilities: In August 2020, the Utility Regulation and Competition Office approved the postponement of Caribbean Utilities' scheduled June 1, 2020 annual rate adjustment to January 1, 2021 to provide customer relief from the economic effects of the COVID-19 pandemic. The deferred revenue associated with the delay is being collected over a two-year period beginning January 2021.

FortisTCI: In February 2020, the Government of the Turks and Caicos Islands approved a 6.8% average increase in FortisTCI's electricity rates, effective April 1, 2020, including the recovery of hurricane-related costs incurred in 2017. In March 2020, to provide customer relief from the economic effects of the COVID-19 pandemic, the effective date was postponed and new rates became effective July 22, 2020.

FortisTCI sought regulatory approval to defer its incremental operating expenses associated with the COVID-19 pandemic. Approval was granted in December 2020 to allow the deferral of approximately $1.5 million in costs, to be amortized over the remaining 15-year life of FortisTCI's licence.

Significant Regulatory Developments

ITC

ROE Complaints: In May 2020, FERC issued an order on the rehearing of its November 2019 decision on the MISO transmission owner ROE complaints and set the base ROE for the periods from November 2013 through February 2015 and from September 2016 onward at 10.02%, up to a maximum of 12.62% with incentive adders. This represents an increase from the base ROE of 9.88%, up to a maximum of 12.24% with incentive adders, determined in FERC's November 2019 decision. Including incentive adders, the May 2020 FERC decision implies an all-in ROE for ITC's subsidiaries operating in the MISO region of 10.77%, up from 10.63% as set in the November 2019 decision.

Net regulatory liabilities of $6 million and $91 million were recorded at December 31, 2020 and 2019, respectively, reflecting: (i) the terms of the May 2020 and November 2019 decisions; and (ii) $42 million refunded to customers in 2020. The May 2020 FERC decision resulted in an increase in Fortis' net earnings of $29 million in 2020, including $27 million related to the reversal of liabilities established in prior periods (2019 - November 2019 FERC decision increased Fortis' net earnings by $63 million, including $83 million related to the reversal of liabilities established in prior periods).

Review of Transmission Incentives Policy: In March 2020, FERC issued a notice of proposed rulemaking ("NOPR") that included a proposal to update its transmission incentives policy for transmission owners, including ITC, to grant incentives to projects based upon benefits to customers regarding reliability and cost savings through the reduction of transmission congestion. FERC proposed total ROE incentives of up to 250 basis points that would not be limited by the upper end of the base ROE zone of reasonableness. The NOPR also proposed, among other things, to eliminate the ROE adder for independent transmission ownership, and to increase the ROE adder for regional transmission owner participation. Comments from stakeholders, including ITC, were provided to FERC through July 2020. The outcome of these proceedings may impact future incentive adders that are included in transmission rates charged by transmission owners, including ITC.

Central Hudson

General Rate Application: In August 2020, Central Hudson filed a rate application with the PSC requesting an increase in electric and natural gas delivery revenue of $44 million and $19 million, respectively, effective July 1, 2021. An order from the PSC is expected in 2021.

FortisBC Energy and FortisBC Electric

Multi-Year Rate Plan Applications: In June 2020, the BCUC issued a decision on FortisBC Energy's and FortisBC Electric's multi-year rate plan applications for 2020 to 2024. The decision sets the rate-setting framework for the five-year period, including: (i) the level of operation and maintenance expense and growth capital to be included in customer rates, indexed for inflation less a fixed productivity adjustment factor; (ii) a forecast approach to sustainment capital; (iii) an innovation fund recognizing the need to accelerate investment in clean energy innovation; and (iv) a 50/50 sharing between customers and the utilities of variances from the allowed ROE. In the fourth quarter of 2020, the BCUC approved: (i) the January 1, 2020 delivery rate increase; and (ii) an increase in 2021 delivery rates, effective January 1, 2021, reflecting the terms of this decision.

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Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Generic Cost of Capital Proceeding: In January 2021, the BCUC issued a notice that a GCOC proceeding will be initiated in the second quarter of 2021 and will include a review of the common equity component of capital structure and the allowed ROE effective January 1, 2022.

FortisAlberta

2018 Independent System Operator Tariff Application: In September 2019, the AUC issued a decision that addressed, among other things, a proposal to change how the AESO customer contribution policy ("ACCP") is accounted for between distribution facility owners, such as FortisAlberta, and transmission facility owners ("TFOs"). The decision prevented any future investment by FortisAlberta under the policy and directed that unamortized customer contributions of approximately $400 million as at December 31, 2017, which form part of FortisAlberta's rate base, be transferred to the incumbent TFO in FortisAlberta's service area.

In November 2020, the AUC issued a decision: (i) reversing the proposed changes to the ACCP resulting in FortisAlberta retaining its unamortized customer contributions; and (ii) directing a change in the depreciation rate for AESO contributions to reflect the parameters of the underlying transmission facilities. FortisAlberta has adjusted the estimated service life and the associated depreciation rate of the unamortized AESO contributions resulting in a decrease in depreciation expense and an associated decrease in revenue in 2020.

The AUC initiated a new proceeding in November 2020 to consider whether the ACCP should be modified on a prospective basis. A decision is expected in the second quarter of 2021.

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

These consolidated financial statements have been prepared and presented in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for rate-regulated entities, and are in Canadian dollars unless otherwise indicated.

These consolidated financial statements include the accounts of the Corporation and its subsidiaries, and a controlled variable interest entity up to the date of its disposition on April 16, 2019 (Note 22). They reflect the equity method of accounting for entities in which Fortis has significant influence, but not control, and proportionate consolidation for assets that are jointly owned with non-affiliated entities. Intercompany transactions have been eliminated, except for transactions between non-regulated and regulated entities in accordance with US GAAP for rate-regulated entities.

Cash and Cash Equivalents

Cash and cash equivalents include cash, cash held in margin accounts, and short-term deposits with initial maturities of three months or less from the date of deposit.

Allowance for Credit Losses

Fortis and its subsidiaries recognize an allowance for credit losses (2019 - allowance for doubtful accounts) to reduce accounts receivable for amounts estimated to be uncollectible. The allowance for credit losses is estimated based on historical collection patterns, sales, and current and forecast economic and other conditions. Accounts receivable are written off in the period in which they are deemed uncollectible.

Inventories

Inventories, consisting of materials and supplies, gas, fuel and coal in storage, are measured at the lower of weighted average cost and net realizable value.

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Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Regulatory Assets and Liabilities

Regulatory assets and liabilities arise as a result of the utility rate-setting process and are subject to regulatory approval. Regulatory assets represent future revenues and/or receivables associated with certain costs incurred that will be, or are expected to be, recovered from customers in future periods through the rate-setting process. Regulatory liabilities represent: (i) future reductions or limitations of increases in revenue associated with amounts that will be, or are expected to be, refunded to customers through the rate-setting process; or (ii) obligations to provide future service that customers have paid for in advance.

Certain remaining recovery and settlement periods are those expected by management and the actual periods could differ based on regulatory approval.

Investments

Investments accounted for using the equity method are reviewed annually for potential impairment in value. Impairments are recognized when identified.

Property, Plant and Equipment

Property, plant and equipment ("PPE") are recognized at cost less accumulated depreciation. Contributions in aid of construction by customers and governments are recognized as a reduction in the cost of, and are amortized in a manner consistent with, the related PPE.

Depreciation rates of the Corporation's regulated utilities include a provision for estimated future asset removal costs not identified as a legal obligation. The provision is recognized as a long-term regulatory liability (Note 8) against which actual asset removal costs are netted when incurred.

Most of the Corporation's regulated utilities derecognize PPE on disposal or when no future economic benefits are expected from their use. Upon derecognition, any difference between cost and accumulated depreciation, net of salvage proceeds, is charged to accumulated depreciation. No gain or loss is recognized.

Through methodologies established by their respective regulators, the Corporation's regulated utilities capitalize: (i) overhead costs that are not directly attributable to specific PPE but relate to the overall capital expenditure plan; and (ii) an allowance for funds used during construction ("AFUDC"). The debt component of AFUDC for 2020 totalled $41 million (2019 - $40 million) and is reported as a reduction of finance charges and the equity component is reported as other income (Note 23). Both components are charged to earnings through depreciation expense over the estimated service lives of the applicable PPE.

At FortisAlberta the cost of PPE includes required contributions to AESO toward funding the construction of transmission facilities.

Excluding UNS Energy and Central Hudson, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulator, UNS Energy and Central Hudson recognize such items as inventory until used and reclassifies them to PPE once put into service.

Repairs and maintenance costs are charged to earnings in the period incurred. Replacements and betterments that extend the useful lives of PPE are capitalized.

PPE is depreciated using the straight-line method based on the estimated service lives of the assets. Depreciation rates for regulated PPE are approved by the respective regulators. Depreciation rates for 2020 ranged from 0.9% to 39.8% (2019 - 0.9% to 35.0%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.5% for 2020 (2019 – 2.6%).

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Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

The service life ranges and weighted average remaining service life of PPE as at December 31 were as follows.

		2020		2019
(years)		Service Life Ranges	Weighted Average Remaining Service Life	Service Life Ranges	Weighted Average Remaining Service Life
Distribution
	Electric	5-80	32	5-80	32
	Gas	18-95	38	15-95	36
Transmission
	Electric	20-90	43	20-90	43
	Gas	10-85	35	5-85	32
Generation		1-85	24	1-85	25
Other		2-70	14	3-70	14

Intangible Assets

Intangible assets are recorded at cost less accumulated amortization. Their useful lives are assessed to be either indefinite or finite.

Intangible assets with indefinite useful lives are not amortized and are tested for impairment annually, either individually or, where the particular entity also has goodwill, at the reporting unit level in conjunction with goodwill impairment testing. An annual review is completed to determine whether the indefinite life assessment continues to be supportable. If not, the resultant changes are made prospectively.

Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets. Amortization rates for regulated intangible assets are approved by the respective regulators and ranged from 1.0% to 33.0% for 2020 (2019 – 1.0% to 33.0%).

The service life ranges and weighted average remaining service life of finite-life intangible assets as at December 31 were as follows.

	2020		2019
(years)	Service Life Ranges	Weighted Average Remaining Service Life	Service Life Ranges	Weighted Average Remaining Service Life
Computer software	3-15	4	3-10	4
Land, transmission and water rights	43-90	56	43-90	58
Other	10-100	12	10-100	12

Most of the Corporation's regulated utilities derecognize intangible assets on disposal or when no future economic benefits are expected from their use. Upon derecognition any difference between the cost and accumulated amortization of the asset, net of salvage proceeds, is charged to accumulated amortization. No gain or loss is recognized.

Impairment of Long-Lived Assets

The Corporation reviews the valuation of PPE, intangible assets with finite lives, and other long-term assets when events or changes in circumstances indicate that the carrying value may not exceed the total undiscounted cash flows expected to be generated by the asset. If that is determined to be the case, the asset is written down to estimated fair value and an impairment loss is recognized.

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Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Goodwill

Goodwill represents the excess of the purchase price over the fair value of the identifiable net assets related to business acquisitions.

Goodwill at each of the Corporation's 11 reporting units is tested for impairment annually and whenever an event or change in circumstances indicates that fair value may be below carrying value. If so determined, goodwill is written down to estimated fair value and an impairment loss is recognized.

The Corporation performs a qualitative assessment on each reporting unit, and if it is determined that it is not likely that fair value is less than carrying value, then a quantitative estimate of fair value is not required. When a quantitative assessment is necessary, the primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections are discounted. Underlying estimates and assumptions, with varying degrees of uncertainty, include the amount and timing of expected future cash flows, growth rates, and discount rates. A secondary valuation, the market approach along with a reconciliation of the total estimated fair value of all the reporting units to the Corporation's market capitalization, is also performed and evaluated.

Deferred Financing Costs

Issue costs, discounts and premiums are recognized against, and amortized over the life of, the related long-term debt.

Employee Future Benefits

Fortis and each subsidiary maintain one or a combination of defined benefit pension plans and defined contribution pension plans, as well as other post-employment benefit ("OPEB") plans, including certain health and dental coverage and life insurance benefits, for qualifying members. The costs of defined contribution pension plans are expensed as incurred.

For defined benefit pension and OPEB plans, the projected or accumulated benefit obligation and net benefit costs are actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, retirement ages of employees and, for OPEB plans, expected health care costs. Discount rates reflect market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension or OPEB payments.

Defined benefit pension and OPEB plan assets are recognized at fair value. For the purpose of determining defined benefit pension cost, FortisBC Energy and Newfoundland Power use the market-related value whereby investment returns in excess of, or below, expected returns are recognized in the asset value over a period of three years.

The excess of any cumulative net actuarial gain or loss over 10% of the greater of: (i) the projected or accumulated benefit obligation; and (ii) the fair value or market-related value, as applicable, of plan assets at the beginning of the fiscal year, along with unamortized past service costs, are deferred and amortized over the average remaining service period of active employees.

The net funded or unfunded status of defined benefit pension and OPEB plans, measured as the difference between the fair value of the plan assets and the projected or accumulated benefit obligation, is recognized on the Corporation's consolidated balance sheets.

For most of the Corporation's regulated utilities, any difference between defined benefit pension or OPEB plan costs ordinarily recognized under US GAAP and those recovered from customers in current rates is subject to deferral account treatment and is expected to be recovered from, or refunded to, customers in future rates (Note 8).

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Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

For most of the Corporation's regulated utilities, any unamortized balances related to net actuarial gains and losses, past service costs and transitional obligations associated with defined benefit pension or OPEB plans, as applicable, which would otherwise be recognized in accumulated other comprehensive income, are subject to deferral account treatment (Note 8).

Leases

A right-of-use asset and lease liability is recognized for all leases with a lease term greater than 12 months. The right-of-use asset and liability are both measured at the present value of future lease payments, excluding variable payments that are based on usage or performance. Future lease payments include both lease components (e.g., rent, real estate taxes and insurance costs) and non-lease components (e.g., common area maintenance costs), which Fortis accounts for as a single lease component. The present value is calculated using the rate implicit in the lease or a lease-specific secured interest rate based on the remaining lease term. Renewal options are included in the lease term when it is reasonably certain that the option will be exercised.

Finance leases are depreciated over the lease term, except where: (i) ownership of the asset is transferred at the end of the lease term, in which case depreciation is over the estimated service life of the underlying asset; and (ii) the regulator has approved a different recovery methodology for rate-setting purposes, in which case the timing of the expense recognition will conform to the regulator's requirements.

Revenue Recognition

Most revenue is derived from energy sales and the provision of transmission services to customers based on regulator-approved tariff rates. Most contracts have a single performance obligation, being the delivery of energy or the provision of transmission services. No component of the transaction price is allocated to unsatisfied performance obligations. Energy sales are generally measured in kilowatt hours, gigajoules or transmission load delivered. The billing of energy sales is based on customer meter readings, which occur systematically throughout each month. The billing of transmission services at ITC is based on peak monthly load.

FortisAlberta is a distribution company and is required by its regulator to arrange and pay for transmission services with the AESO. This includes the collection of transmission revenue from its customers, which occurs through the transmission component of its regulator-approved rates. FortisAlberta reports transmission revenue and expenses on a net basis.

Electricity, gas and transmission service revenue includes an estimate for unbilled energy consumed or service provided since the last meter reading that has not been billed at the end of the reporting period. Sales estimates generally reflect an analysis of historical consumption in relation to key inputs, such as current energy prices, population growth, economic activity, weather conditions and system losses. Unbilled revenue accruals are adjusted in the periods actual consumption becomes known.

Generation revenue from non-regulated operations is recognized on delivery at contracted fixed or market rates.

Variable consideration is estimated at the most likely amount and reassessed at each reporting date until the amount is known. Variable consideration, including amounts subject to a future regulatory decision, is recognized as a refund liability until entitlement is certain.

Revenue excludes sales and municipal taxes collected from customers.

The Corporation has elected not to assess or account for any significant financing components associated with revenue billed in accordance with equal payment plans as the period between the transfer of energy to customers and the customers' payment is less than one year.

Revenue is disaggregated by geography, regulatory status, and substantially autonomous utility operations (Note 5). This represents the level of disaggregation used by the Corporation's President and Chief Executive Officer ("CEO") to allocate resources and evaluate performance.

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Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Stock-Based Compensation

Compensation expense related to stock options is measured at the grant date using the Black-Scholes fair value option-pricing model and each grant is amortized to compensation expense as a single award evenly over the four-year vesting period, with the offsetting entry to additional paid-in capital.

Fortis satisfies stock option exercises by issuing common shares from treasury. Upon exercise, proceeds are credited to capital stock at the option prices and the fair value of the options, as previously recognized, is reclassified from additional paid-in capital to capital stock.

Fortis recognizes liabilities associated with its directors' Deferred Share Unit ("DSU"), Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") Plans. DSUs, PSUs and RSUs issued pre-2020 represent cash-settled awards and RSUs issued in 2020 represent cash or share-settled awards, depending on settlement elections and share ownership requirements of the executive. The fair value of these liabilities is based on the five-day volume weighted average price ("VWAP") of the Corporation's common shares at the end of each reporting period. The VWAP as at December 31, 2020 was $52.36 (2019 - $53.97). The fair value of the PSU liability is also based on the expected payout probability, based on historical performance in accordance with the defined metrics of each grant and management's best estimate.

Compensation expense is recognized on a straight-line basis over the vesting period, which for the PSU and RSU Plans is over the lesser of three years or the period to retirement eligibility and for the DSU Plan is at the time of grant. Forfeitures are accounted for as they occur.

Foreign Currency Translation

Assets and liabilities of the Corporation's foreign operations, all of which have a US dollar functional currency, are translated at the exchange rate in effect at the balance sheet date and the resultant unrealized translation gains and losses are recognized in accumulated other comprehensive income. The exchange rate as at December 31, 2020 was US$1.00=CA$1.27 (2019 – US$1.00=CA$1.30).

Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which was US$1.00=CA$1.34 for 2020 (2019 - US$1.00=CA$1.33).

Monetary assets and liabilities denominated in foreign currencies are translated at the exchange rate prevailing at the balance sheet date. Revenue and expenses denominated in foreign currencies are translated at the exchange rate prevailing at the transaction date. Translation gains and losses are recognized in earnings.

Translation gains and losses on foreign currency-denominated debt that is designated as an effective hedge of foreign net investments are recognized in other comprehensive income.

Derivatives and Hedging

Derivatives Not Designated as Hedges

Derivatives not designated as hedges are used by: (i) Fortis, to manage cash flow risk associated with forecast US dollar cash inflows and forecast future cash settlements of DSU, PSU and RSU obligations; (ii) UNS Energy, to meet forecast load and reserve requirements; and (iii) Aitken Creek, to manage commodity price risk, capture natural gas price spreads, and manage the financial risk of physical transactions. These derivatives are measured at fair value with changes thereto recognized in earnings.

Derivatives not designated as hedges are also used by UNS Energy, Central Hudson and FortisBC Energy to reduce energy price risk associated with purchased power and gas requirements. The settled amounts of these derivatives are generally included in regulated rates, as permitted by the respective regulators. These derivatives are measured at fair value with changes recognized as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 8).

Derivatives that meet the normal purchase or normal sale scope exception are not measured at fair value and settled amounts are recognized in earnings as energy supply costs.

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Derivatives Designated as Hedges

Fortis, ITC and UNS Energy use cash flow hedges, from time to time, to manage interest rate risk. Unrealized gains and losses are initially recognized in accumulated other comprehensive income and reclassified to earnings when the underlying hedged transaction affects earnings. Any hedge ineffectiveness is immediately recognized in earnings.

The Corporation's earnings from, and net investments in, foreign subsidiaries and certain equity-accounted investments are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through US dollar-denominated debt at the corporate level. Exchange rate fluctuations associated with the translation of this debt and the foreign net investments are recognized in accumulated other comprehensive income.

Presentation of Derivatives

The fair values of derivatives are recognized as current or long-term assets and liabilities depending on the timing of settlements and resulting cash flows. Derivatives under master netting agreements and collateral positions are presented on a gross basis. Cash flows associated with the settlement of all derivatives are presented in operating activities in the consolidated statements of cash flows.

Income Taxes

The Corporation and its taxable subsidiaries follow the asset and liability method of accounting for income taxes. Current income tax expense or recovery is recognized for the estimated income taxes payable or receivable in the current year.

Deferred income tax assets and liabilities are recognized for temporary differences between the tax and accounting basis of assets and liabilities, as well as for the benefit of losses available to be carried forward to future years for tax purposes that are "more likely than not" to be realized. They are measured using enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. The effect of a change in income tax rates on deferred income tax assets and liabilities is recognized in earnings in the period when the change occurs. Valuation allowances are recognized when it is "more likely than not" that all of, or a portion of, a deferred income tax asset will not be realized.

Customer rates at ITC, UNS Energy, Central Hudson and Maritime Electric reflect current and deferred income tax. Customer rates at FortisAlberta reflect current income tax. Customer rates at FortisBC Energy, FortisBC Electric, Newfoundland Power and FortisOntario reflect current income tax and, for certain regulatory balances, deferred income tax. Caribbean Utilities, FortisTCI and BECOL are not subject to income tax.

Differences between the income tax expense or recovery recognized under US GAAP and reflected in current customer rates, which is expected to be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities (Note 8).

At FortisAlberta the capital cost allowance pool for certain PPE for rate-setting purposes is different from that prescribed for Canadian tax filing purposes. In a future reporting period yet to be determined, the difference may result in reported income tax expense exceeding that reflected in customer rates.

Fortis does not recognize deferred income taxes on temporary differences related to investments in foreign subsidiaries where it intends to indefinitely reinvest earnings. The difference between the carrying values of these foreign investments and their tax bases, resulting from unrepatriated earnings and currency translation adjustments, is approximately $3.4 billion as at December 31, 2020 (2019 - $2.8 billion). If such earnings are repatriated, the Corporation may be subject to income taxes and foreign withholding taxes. The determination of the amount of unrecognized deferred income tax liabilities on such amounts is impractical.

Tax benefits associated with actual or expected income tax positions are recognized when the "more likely than not" recognition threshold is met. The tax benefits are measured at the largest amount of benefit that is greater than 50% likely to be realized upon settlement.

Income tax interest and penalties are recognized as income tax expense when incurred.

16

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Asset Retirement Obligations

The Corporation's subsidiaries have asset retirement obligations ("AROs") associated with certain generation, transmission, distribution and interconnection assets, including land and environmental remediation and/or asset removal. These assets and related licences, permits, rights-of-way and agreements are reasonably expected to effectively exist and operate in perpetuity due to their nature. Consequently, where the final date and cost of remediation and/or removal of the noted assets cannot be reasonably determined, AROs have not been recognized.

Otherwise, AROs are recognized at fair value in the period incurred as an increase in PPE and long-term other liabilities (Note 16) if a reasonable estimate of fair value can be determined. Fair value is estimated as the present value of expected future cash outlays, discounted at a credit-adjusted risk-free interest rate. The increase in the liability due to the passage of time is recognized through accretion and the capitalized cost is depreciated over the useful life of the asset. Accretion and depreciation expense are deferred as a regulatory asset or liability based on regulatory recovery of these costs. Actual settlement costs are recognized as a reduction in the accrued liability.

Contingencies

Fortis and its subsidiaries are subject to various legal proceedings and claims that arise in the normal course of business. Management makes judgments regarding the future outcome of contingent events and recognizes a loss based on its best estimate when it is determined that such loss, or range of loss, is probable and can be reasonably estimated. Legal fees are expensed as incurred. When a loss is recoverable in future rates, a regulatory asset is also recognized.

Management regularly reviews current information to determine whether recognized provisions should be adjusted and new provisions are required. However, estimating probable losses requires considerable judgment about potential actions by third parties and matters are often resolved over long periods of time. Actual outcomes may differ materially from the amounts recognized.

New Accounting Policies

Financial Instruments

Effective January 1, 2020, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-13, Measurement of Credit Losses on Financial Instruments, which requires the use of reasonable and supportable forecasts in the estimation of credit losses and the recognition of expected losses upon initial recognition of a financial instrument, in addition to using past events and current conditions. The new guidance also requires quantitative and qualitative disclosures regarding the activity in the allowance for credit losses for financial assets within the scope of the guidance. Adoption did not have a material impact on the consolidated financial statements and related disclosures.

Use of Accounting Estimates

The preparation of these consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments, including those arising from matters dependent upon the finalization of regulatory proceedings, that affect the reported amounts of assets, liabilities, revenues, expenses, gains and losses. Management evaluates these estimates on an ongoing basis based upon historical experience, current conditions, and assumptions believed to be reasonable at the time they are made, with any adjustments being recognized in the period they become known. Actual results may differ significantly from these estimates.

Future Accounting Pronouncements

The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board. Any ASUs not included in these consolidated financial statements were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements.

17

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

4. SEGMENTED INFORMATION

General

Fortis segments its business based on regulatory jurisdiction and service territory, as well as the information used by its CEO in deciding how to allocate resources. Segment performance is evaluated principally on net earnings attributable to common equity shareholders.

Related-Party and Inter-Company Transactions

Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions in 2020 or 2019.

Inter-company balances, transactions and profit between non-regulated and regulated entities, which are not eliminated on consolidation, are summarized below.

(in millions)	2020		2019
Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy	$	25	$	23
Sale of capacity from the Waneta Expansion to FortisBC Electric (1)	—		17

(1)    Reflects amounts to the April 16, 2019 disposition of the Waneta Expansion (Note 22)

As at December 31, 2020, accounts receivable included approximately $28 million due from Belize Electricity (2019 - $8 million).

Fortis periodically provides short-term financing to its subsidiaries to support capital expenditures, acquisitions and seasonal working capital requirements. As at December 31, 2020, there were no material inter-segment loans outstanding (2019 - $279 million). The interest charged on inter-segment loans in 2020 and 2019 was not material.

18

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

	REGULATED																NON-REGULATED
Year ended																	Energy				Inter-
December 31, 2020			UNS		Central		FortisBC		Fortis		FortisBC		Other		Sub		Infra-		Corporate		segment
(in millions)	ITC		Energy		Hudson		Energy		Alberta		Electric		Electric		total		structure		and Other		eliminations		Total
Revenue	$	1,744	$	2,260	$	953	$	1,385	$	596	$	424	$	1,485	$	8,847	$	88	$	—	$	—	$	8,935
Energy supply costs	—		847		232		468		—		119		893		2,559		3		—		—		2,562
Operating expenses	438		627		503		341		148		117		194		2,368		30		39		—		2,437
Depreciation and amortization	295		330		90		237		212		61		183		1,408		16		4		—		1,428
Operating income	1,011		456		128		339		236		127		215		2,512		39		(43)		—		2,508
Other income, net	40		40		31		8		2		5		10		136		5		13		—		154
Finance charges	324		125		48		142		104		72		77		892		—		150		—		1,042
Income tax expense	179		69		20		29		1		4		21		323		5		(97)		—		231
Net earnings	548		302		91		176		133		56		127		1,433		39		(83)		—		1,389
Non-controlling interests	99		—		—		1		—		—		15		115		—		—		—		115
Preference share dividends	—		—		—		—		—		—		—		—		—		65		—		65
Net earnings attributable to common equity shareholders	$	449	$	302	$	91	$	175	$	133	$	56	$	112	$	1,318	$	39	$	(148)	$	—	$	1,209
Goodwill	$	7,810	$	1,758	$	574	$	913	$	228	$	235	$	247	$	11,765	$	27	$	—	$	—	$	11,792
Total assets	20,358		10,802		3,939		7,695		5,084		2,441		4,261		54,580		745		209		(53)		55,481
Capital expenditures	1,182		1,200		339		471		420		135		273		4,020		19		—		—		4,039
Year ended
December 31, 2019
(in millions)
Revenue	$	1,761	$	2,212	$	917	$	1,331	$	598	$	418	$	1,467	$	8,704	$	82	$	—	$	(3)	$	8,783
Energy supply costs	—		814		254		438		—		121		890		2,517		3		—		—		2,520
Operating expenses	489		650		451		333		145		107		188		2,363		36		56		(3)		2,452
Depreciation and amortization	270		297		79		235		214		62		171		1,328		20		2		—		1,350
Gain on disposition	—		—		—		—		—		—		—		—		—		577		—		577
Operating income	1,002		451		133		325		239		128		218		2,496		23		519		—		3,038
Other income, net	37		28		17		16		2		4		2		106		2		30		—		138
Finance charges	290		130		46		136		104		72		77		855		—		180		—		1,035
Income tax expense	174		57		19		39		6		6		20		321		(1)		(31)		—		289
Net earnings	575		292		85		166		131		54		123		1,426		26		400		—		1,852
Non-controlling interests	104		—		—		1		—		—		17		122		8		—		—		130
Preference share dividends	—		—		—		—		—		—		—		—		—		67		—		67
Net earnings attributable to common equity shareholders	$	471	$	292	$	85	$	165	$	131	$	54	$	106	$	1,304	$	18	$	333	$	—	$	1,655
Goodwill	$	7,970	$	1,794	$	586	$	913	$	228	$	235	$	251	$	11,977	$	27	$	—	$	—	$	12,004
Total assets	19,799		10,205		3,726		7,305		4,831		2,328		4,185		52,379		711		641		(327)		53,404
Capital expenditures	1,148		915		317		463		423		106		295		3,667		28		25		—		3,720

19

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

5. REVENUE

(in millions)	2020		2019
Electric and gas revenue
United States
ITC	$	1,726	$	1,697
UNS Energy	2,019		1,966
Central Hudson	941		894
Canada
FortisBC Energy	1,336		1,289
FortisAlberta	580		576
FortisBC Electric	358		362
Newfoundland Power	707		671
Maritime Electric	215		209
FortisOntario	222		206
Caribbean
Caribbean Utilities	238		270
FortisTCI	77		85
Total electric and gas revenue	8,419		8,225
Other services revenue (1)	325		374
Revenue from contracts with customers	8,744		8,599
Alternative revenue (2)	64		116
Other revenue	127		68
Total revenue	$	8,935	$	8,783

(1)    Includes $227 million and $273 million from regulated operations for 2020 and 2019, respectively

(2)    Includes a $40 million and $91 million base ROE adjustment associated with the May 2020 and November 2019 FERC decisions, respectively (Notes 2 and 8)

Revenue from Contracts with Customers

Electric and gas revenue includes revenue from the sale and/or delivery of electricity and gas, transmission revenue, and wholesale electric revenue, all based on regulator-approved tariff rates including the flow through of commodity costs.

Other services revenue includes: (i) management fee revenue at UNS Energy for the operation of Springerville Units 3 and 4; (ii) revenue from storage optimization activities at Aitken Creek; and (iii) revenue from other services that reflect the ordinary business activities of Fortis' utilities.

Alternative Revenue

Alternative revenue programs allow utilities to adjust future rates in response to past activities or completed events if certain criteria are met. Alternative revenue is recognized on an accrual basis with a corresponding regulatory asset or liability until the revenue is settled. Upon settlement, revenue is not recognized as revenue from contracts with customers but rather as settlement of the regulatory asset or liability. The significant alternative revenue programs of Fortis' utilities are summarized as follows.

ITC's formula rates include an annual true-up mechanism that compares actual revenue requirements to billed revenue, and any under- or over-collections are accrued as a regulatory asset or liability and reflected in future rates within a two-year period (Note 8). The formula rates do not require annual regulatory approvals, although inputs remain subject to legal challenge.

20

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

UNS Energy's lost fixed-cost recovery mechanism ("LFCR") surcharge recovers lost fixed costs, as measured by a reduction in non-fuel revenue, associated with energy efficiency savings and distributed generation. To recover the LFCR regulatory asset, UNS Energy is required to file an annual LFCR adjustment request with the ACC for the LFCR revenue recognized in the prior year. The recovery is subject to a year-over-year cap of 2% of total retail revenue. UNS Energy's demand side management surcharge, which is approved by the ACC annually, compensates for the costs to design and implement cost-effective energy efficiency and demand response programs until such costs, along with a performance incentive, are reflected in non-fuel base rates.

FortisBC Energy and FortisBC Electric have an earnings sharing mechanism that provides for a 50/50 sharing of variances from the allowed ROE in 2020 (2019 - variances from formula-driven operation and maintenance expenses and capital expenditures). This mechanism is in place until the expiry of the current multi-year rate plan for 2020 to 2024. Additionally, variances between forecast and actual customer-use rates and industrial and other customer revenue are captured in a revenue stabilization account and a flow-through deferral account to be refunded to, or received from, customers in rates within two years.

Other Revenue

Other revenue primarily includes gains or losses on energy contract derivatives and regulatory deferrals at FortisBC Energy and FortisBC Electric reflecting cost recovery variances from forecast.

6. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS

(in millions)	2020		2019
Trade accounts receivable	$	595	$	504
Unbilled accounts receivable	571		601
Allowance for credit losses (1)	(64)		(35)
	1,102		1,070
Income tax receivable	72		35
Other (2)	195		192
	$	1,369	$	1,297

(1)    Allowance for doubtful accounts for 2019

(2)    Consists mainly of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases, and the fair value of derivative instruments (Note 27)

Allowance for Credit Losses

The allowance for credit losses balance changed during 2020 as follows.

(in millions)	2020
Balance, beginning of year	$	(35)
Credit loss expensed	(36)
Credit loss deferred (Note 2)	(6)
Write-offs, net of recoveries	14
Foreign exchange	(1)
Balance, end of year	$	(64)

21

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

The allowance for doubtful accounts balance changed during 2019 as follows.

(in millions)	2019
Balance, beginning of year	$	(33)
Bad debt expensed	(21)
Write-offs, net of recoveries	18
Foreign exchange	1
Balance, end of year	$	(35)

7. INVENTORIES

(in millions)	2020		2019
Materials and supplies	$	297	$	294
Gas and fuel in storage	101		69
Coal inventory	24		31
	$	422	$	394

8. REGULATORY ASSETS AND LIABILITIES

(in millions)	2020		2019
Regulatory assets
Deferred income taxes (Notes 3 and 24)	$	1,697	$	1,556
Employee future benefits (Notes 3 and 25)	588		530
Deferred energy management costs (1)	334		279
Rate stabilization and related accounts (2)	213		208
Deferred lease costs (3)	122		116
Manufactured gas plant site remediation deferral (Note 16)	107		81
Derivatives (Notes 3 and 27)	73		119
Generation early retirement costs (4)	55		88
Other regulatory assets (5)	399		406
Total regulatory assets	3,588		3,383
Less: Current portion	(470)		(425)
Long-term regulatory assets	$	3,118	$	2,958
Regulatory liabilities
Deferred income taxes (Notes 3 and 24)	$	1,361	$	1,440
Asset removal cost provision (Note 3)	1,206		1,187
Rate stabilization and related accounts (2)	104		166
Renewable energy surcharge (6)	100		94
Energy efficiency liability (7)	83		101
Employee future benefits (Notes 3 and 25)	43		45
Electric and gas moderator account (8)	28		45
ROE complaints liability (Note 2)	16		91
Other regulatory liabilities (5)	162		189
Total regulatory liabilities	3,103		3,358
Less: Current portion	(441)		(572)
Long-term regulatory liabilities	$	2,662	$	2,786

22

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

(1)    Deferred Energy Management Costs: Certain regulated subsidiaries provide energy management services to facilitate customer energy efficiency programs where the related expenditures have been deferred as a regulatory asset and are being amortized, and recovered from customers through rates, on a straight-line basis over periods ranging from two to 10 years.

(2)    Rate Stabilization and Related Accounts: Rate stabilization accounts mitigate the earnings volatility otherwise caused by variability in the cost of fuel, purchased power and natural gas above or below a forecast or predetermined level, and by weather-driven volume variability. At certain utilities, revenue decoupling mechanisms minimize the earnings impact of reduced energy consumption as energy efficiency programs are implemented. Resultant deferrals are recovered from, or refunded to, customers in future rates as approved by the respective regulators.

Related accounts include the annual true-up mechanism at ITC (Note 5).

(3)    Deferred Lease Costs: Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") (Note 15). The depreciation of the asset under finance lease and interest expense on the finance lease obligation are not being fully recovered in current customer rates since these rates only reflect the cash payments required under the BPPA. The annual differences are being deferred as a regulatory asset, which is expected to be recovered from customers in future rates over the term of the lease, which expires in 2056.

(4)    Generation Early Retirement Costs: TEP and the co-owners of Navajo Generating Station ("Navajo") retired Navajo in 2019, with related decommissioning activities continuing through 2054. TEP also retired Sundt Generating Facility Units 1 and 2 ("Sundt") in 2019. The ACC approved the recovery of the retirement costs of Navajo and Sundt over a 10-year period as part of the 2020 Rate Order (Note 2).

(5)    Other Regulatory Assets and Liabilities: Comprised of regulatory assets and liabilities individually less than $40 million.

(6)    Renewable Energy Surcharge: Under the ACC's Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements by 2025. The cost of carrying out the plan is recovered from retail customers through a RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory liability or asset.

The ACC measures RES compliance through Renewable Energy Credits ("RECs"). Each REC represents one kilowatt hour generated from renewable resources. When UNS Energy purchases renewable energy, the premium paid above the market cost of conventional power equals the REC recoverable through the RES surcharge. When RECs are purchased, UNS Energy records their cost as long-term other assets (Note 9) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are utilized for RES compliance, energy supply costs and revenue are recognized in an equal amount.

(7)    Energy Efficiency Liability: The energy efficiency liability primarily relates to Central Hudson's Energy Efficiency Program, established to fund environmental policies associated with energy conservation programs as approved by its regulator.

(8)    Electric and Gas Moderator Account: Under Central Hudson's 2018 three-year rate order certain regulatory assets and liabilities were approved by the PSC for offset, and an electric and gas moderator account was established, which will be used for future customer rate moderation.

Regulatory assets not earning a return: (i) totalled $1,678 million and $1,510 million as at December 31, 2020 and 2019, respectively; (ii) are primarily related to deferred income taxes and employee future benefits; and (iii) generally do not represent a past cash outlay as they are offset by related liabilities that, likewise, do not incur a carrying cost for rate-making purposes. Recovery periods vary or are yet to be determined by the respective regulators.

23

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

9. OTHER ASSETS

(in millions)	2020		2019
Supplemental Executive Retirement Plan ("SERP")	$	155	$	145
Renewable Energy Credits (Note 8)	106		99
Equity investment - Belize Electricity	80		71
Employee future benefits (Note 25)	66		63
Other investments	66		43
Operating leases (Note 15)	40		46
Deferred compensation plan	36		30
Equity Investment - Wataynikaneyap Partnership	12		12
Other (1)	109		111
	$	670	$	620

(1)    Includes the fair value of derivatives (Note 27)

ITC, UNS Energy and Central Hudson provide additional post-employment benefits through SERPs and deferred compensation plans for directors and officers. The assets held to support these plans are reported separately from the related liabilities (Note 16). Most plan assets are held in trust and funded mainly through trust-owned life insurance policies and mutual funds. Assets in mutual and money market funds are recorded at fair value on a recurring basis (Note 27).

10. PROPERTY, PLANT AND EQUIPMENT

(in millions)		Cost		Accumulated Depreciation		Net Book Value
2020
Distribution
	Electric	$	11,921	$	(3,223)	$	8,698
	Gas	5,546		(1,422)		4,124
Transmission
	Electric	15,888		(3,413)		12,475
	Gas	2,360		(719)		1,641
Generation		6,441		(2,550)		3,891
Other		4,178		(1,347)		2,831
Assets under construction		2,012		—		2,012
Land		326		—		326
		$	48,672	$	(12,674)	$	35,998

2019
Distribution
	Electric	$	11,396	$	(3,125)	$	8,271
	Gas	5,277		(1,330)		3,947
Transmission
	Electric	15,207		(3,293)		11,914
	Gas	2,267		(681)		1,586
Generation		6,380		(2,472)		3,908
Other		4,042		(1,327)		2,715
Assets under construction		1,329		—		1,329
Land		318		—		318
		$	46,216	$	(12,228)	$	33,988

24

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Electric distribution assets are those used to distribute electricity at lower voltages (generally below 69 kilovolts ("kV")). These assets include poles, towers and fixtures, low-voltage wires, transformers, overhead and underground conductors, street lighting, meters, metering equipment and other related equipment. Gas distribution assets are those used to transport natural gas at low pressures (generally below 2,070 kilopascals ("kPa")) or a hoop stress of less than 20% of standard minimum yield strength. These assets include distribution stations, telemetry, distribution pipe for mains and services, meter sets and other related equipment.

Electric transmission assets are those used to transmit electricity at higher voltages (generally at 69 kV and higher). These assets include poles, wires, switching equipment, transformers, support structures and other related equipment. Gas transmission assets are those used to transport natural gas at higher pressures (generally at 2,070 kPa and higher) or a hoop stress of 20% or more of standard minimum yield strength. These assets include transmission stations, telemetry, transmission pipe and other related equipment.

Generation assets are those used to generate electricity. These assets include hydroelectric and thermal generation stations, gas and combustion turbines, coal-fired generating stations, dams, reservoirs, photovoltaic systems, wind resources and other related equipment.

Other assets include buildings, equipment, vehicles, inventory, information technology assets and Aitken Creek.

As at December 31, 2020, assets under construction were primarily associated with ongoing transmission projects at ITC and the addition of wind-powered electric generating capacity at UNS Energy.

The cost of PPE under finance lease as at December 31, 2020 was $322 million (2019 - $514 million) and related accumulated depreciation was $111 million (2019 - $206 million) (Note 15).

Jointly Owned Facilities

UNS Energy and ITC hold undivided interests in jointly owned generating facilities and transmission systems, are entitled to their pro rata share of the PPE, and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2020, interests in jointly owned facilities consisted of the following.

	Ownership			Accumulated		Net Book
(in millions, except as noted)	(%)	Cost		Depreciation		Value
Transmission Facilities	1.0-80.0	$	980	$	(381)	$	599
Springerville Common Facilities (1)	86.0	505		(251)		254
San Juan Unit 1 ("San Juan")	50.0	370		(304)		66
Springerville Coal Handling Facilities	83.0	268		(121)		147
Four Corners Units 4 and 5 ("Four Corners")	7.0	235		(97)		138
Gila River Common Facilities	50.0	108		(36)		72
Luna Energy Facility ("Luna")	33.3	74		(2)		72
		$	2,540	$	(1,192)	$	1,348

(1)    In December 2020 TEP purchased an additional 32.2% undivided interest in the Springerville Common Facilities, previously recorded as a finance lease (Note 15). Also in December 2020, TEP sold a 14% interest in the Springerville Common Facilities.

25

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

11. INTANGIBLE ASSETS

			Accumulated		Net Book
(in millions)	Cost		Amortization		Value
2020
Computer software	$	932	$	(524)	$	408
Land, transmission and water rights	898		(142)		756
Other	114		(64)		50
Assets under construction	77		—		77
	$	2,021	$	(730)	$	1,291

2019
Computer software	$	946	$	(576)	$	370
Land, transmission and water rights	890		(122)		768
Other	115		(61)		54
Assets under construction	68		—		68
	$	2,019	$	(759)	$	1,260

Included in the cost of land, transmission and water rights as at December 31, 2020 was $136 million (2019 - $133 million) not subject to amortization. Amortization expense was $131 million for 2020 (2019 - $125 million). Amortization is estimated to average approximately $81 million for each of the next five years.

12. GOODWILL

(in millions)	2020		2019
Balance, beginning of year	$	12,004	$	12,530
Foreign currency translation impacts (1)	(212)		(526)
Balance, end of year	$	11,792	$	12,004

(1)    Relates to the translation of goodwill associated with the acquisitions of ITC, UNS Energy, Central Hudson, Caribbean Utilities and FortisTCI, whose functional currency is the US dollar

No goodwill impairment was recognized by the Corporation in 2020 or 2019.

13. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES

(in millions)	2020		2019
Trade accounts payable	$	707	$	754
Employee compensation and benefits payable	248		229
Dividends payable	241		228
Accrued taxes other than income taxes	224		223
Interest payable	215		212
Customer and other deposits	214		226
Gas and fuel cost payable	188		225
Fair value of derivatives (Note 27)	56		83
Manufactured gas plant site remediation (Note 16)	31		31
Employee future benefits (Note 25)	26		24
Other	171		167
	$	2,321	$	2,402

26

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

14. LONG-TERM DEBT

(in millions)		Maturity Date	2020		2019
ITC
Secured US First Mortgage Bonds -
	4.31% weighted average fixed rate (2019 - 4.46%)	2024-2055	$	2,755	$	2,624
Secured US Senior Notes -
	4.00% weighted average fixed rate (2019 - 4.26%)	2040-2055	923		747
Unsecured US Senior Notes -
	3.61% weighted average fixed rate (2019 - 3.79%)	2022-2043	4,136		3,312
Unsecured US Shareholder Note -
	6.00% fixed rate (2019 - 6.00%)	2028	253		258
Unsecured US Term Loan Credit Agreement -
	2.35% weighted average fixed rate	n/a	—		260
UNS Energy
Unsecured US Tax-Exempt Bonds - 4.34% weighted
	average fixed and variable rate (2019 - 4.64%)	2029-2030	362		603
Unsecured US Fixed Rate Notes -
	3.86% weighted average fixed rate (2019 - 4.38%)	2021-2050	2,704		1,851
Central Hudson
Unsecured US Promissory Notes - 3.94% weighted
	average fixed and variable rate (2019 - 4.27%)	2021-2060	1,078		986
FortisBC Energy
Unsecured Debentures -
	4.72% weighted average fixed rate (2019 - 4.87%)	2026-2050	2,995		2,795
FortisAlberta
Unsecured Debentures -
	4.49% weighted average fixed rate (2019 - 4.64%)	2024-2052	2,360		2,185
FortisBC Electric
Secured Debentures -
	8.80% fixed rate (2019 - 8.80%)	2023	25		25
Unsecured Debentures -
	4.87% weighted average fixed rate (2019 - 5.05%)	2021-2050	785		710
Other Electric
Secured First Mortgage Sinking Fund Bonds -
	5.61% weighted average fixed rate (2019 - 6.14%)	2022-2060	634		571
Secured First Mortgage Bonds -
	5.66% weighted average fixed rate (2019 - 5.66%)	2025-2061	220		220
Unsecured Senior Notes -
	4.45% weighted average fixed rate (2019 - 4.45%)	2041-2048	152		152
Unsecured US Senior Loan Notes and Bonds - 4.41% weighted
	average fixed and variable rate (2019 - 4.53%)	2022-2049	648		645
Corporate and Other
Unsecured US Senior Notes and Promissory Notes -
	3.81% weighted average fixed rate (2019 - 3.80%)	2021-2044	2,685		2,903
Unsecured Debentures -
	6.50% fixed rate (2019 - 6.50%)	2039	200		200
Unsecured Senior Notes - 2.85% fixed rate (2019 - 2.85%)		2023	500		500
Long-term classification of credit facility borrowings			980		640
Fair value adjustment - ITC acquisition			119		133
Total long-term debt (Note 27)			24,514		22,320
Less: Deferred financing costs and debt discounts			(147)		(129)
Less: Current installments of long-term debt			(1,254)		(690)
			$	23,113	$	21,501

27

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Most long-term debt at the Corporation's regulated utilities is redeemable at the option of the respective utility at the greater of par or a specified price, together with accrued and unpaid interest. Security, if provided, is typically through a fixed or floating first charge on specific assets of the utility.

The Corporation's unsecured debentures and senior notes are redeemable at the option of Fortis at the greater of par or a specified price together with accrued and unpaid interest.

Certain long-term debt agreements have covenants that provide that the Corporation shall not declare, pay or make any dividends or any other restricted payments if, immediately thereafter, its consolidated debt to consolidated capitalization ratio would exceed 65%.

Long-Term Debt Issuances

(in millions, except as noted)		Month Issued	Interest Rate (%)	Maturity	Amount ($)		Use of Proceeds
ITC
Unsecured term loan credit agreement		January	(1)	2021	US	75	(2)(3)
Unsecured term loan credit agreement (4)		January	(5)	2021	US	200	(4)
Unsecured senior notes		May	2.95	2030	US	700	(2)(3)(6)
First mortgage bonds		July	3.13	2051	US	180	(2)(3)(7)
Secured senior notes		October	3.02	2055	US	150	(2)(3)(7)(8)
UNS Energy
Unsecured senior notes		April	4.00	2050	US	350	(2)(3)
Unsecured senior notes		August	1.50	2030	US	300	(7)
Unsecured senior notes		September	2.17	2032	US	50	(2)(3)
Central Hudson
Unsecured senior notes		May	3.42	2050	US	30	(3)
Unsecured senior notes		July	3.62	2060	US	30	(3)(7)
Unsecured senior notes		September	2.03	2030	US	40	(8)
Unsecured senior notes		November	2.03	2030	US	30	(3)(7)
FortisBC Energy
Unsecured debentures		July	2.54	2050	200		(7)
FortisAlberta
Unsecured senior debentures		December	2.63	2051	175		(2)
FortisBC Electric
Unsecured debentures		May	3.12	2050	75		(2)
Newfoundland Power
First mortgage sinking fund bonds		April	3.61	2060	100		(2)(3)
FortisTCI
Unsecured senior notes	June/October		5.30	2035	US	30	(7)(8)
Unsecured senior notes	October/December		3.25	2030	US	10	(3)

(1)    Floating rate of a one-month LIBOR plus a spread of 0.45%

(2)    Repay credit facility borrowings

(3)    General corporate purposes

(4)    Maximum amount of borrowings under this agreement of US$400 million has been drawn; current period borrowings were used to repay an outstanding commercial paper balance.

(5)    Floating rate of a two-month LIBOR plus a spread of 0.60%

(6)    Early redemption of unsecured term loan borrowing of US$400 million

(7)    Finance capital expenditures

(8)    Repay maturing long-term debt

28

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Long-Term Debt Repayments

The consolidated requirements to meet principal repayments and maturities in each of the next five years and thereafter are as follows.

(in millions)	Total
2021	$	1,254
2022	823
2023	1,786
2024	1,088
2025	484
Thereafter	19,079
	$	24,514

In December 2020 Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $2.0 billion. As at December 31, 2020, $2.0 billion remained available under the short-form base shelf prospectus.

Credit Facilities

(in millions)	Regulated Utilities		Corporate and Other		2020		2019
Total credit facilities	$	3,700	$	1,881	$	5,581	$	5,590
Credit facilities utilized:
Short-term borrowings (1)	(132)		—		(132)		(512)
Long-term debt (including current portion) (2)	(714)		(266)		(980)		(640)
Letters of credit outstanding	(77)		(53)		(130)		(114)
Credit facilities unutilized	$	2,777	$	1,562	$	4,339	$	4,324

(1)    The weighted average interest rate was approximately 0.8% (2019 - 3.2%).

(2)    The weighted average interest rate was approximately 0.9% (2019 - 2.4%). The current portion was $651 million (2019 - $252 million).

Credit facilities are syndicated primarily with large banks in Canada and the US, with no one bank holding more than approximately 25% of the total facilities. Approximately $5.3 billion of the total credit facilities are committed facilities with maturities ranging from 2021 through 2025.

29

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Consolidated credit facilities of approximately $5.6 billion as at December 31, 2020 are itemized below.

(in millions)	Amount ($)		Maturity
Unsecured committed revolving credit facilities
Regulated utilities
ITC (1)	US	900	October 2023
UNS Energy	US	500	October 2022
Central Hudson	US	200	March 2025
FortisBC Energy	700		August 2024
FortisAlberta	250		August 2024
FortisBC Electric	150		April 2024
Other Electric	190		(2)
Other Electric	US	70	January 2025
Corporate and Other	1,850		(3)
Other facilities
Regulated utilities
Central Hudson - uncommitted credit facility	US	30	n/a
FortisBC Energy - uncommitted credit facility	55		March 2022
FortisBC Electric - unsecured demand overdraft facility	10		n/a
Other Electric - unsecured demand facilities	20		n/a
Other Electric - unsecured demand facility and emergency standby loan	US	60	June 2021
Corporate and Other - unsecured non-revolving facility	30		n/a

(1)    ITC also has a US$400 million commercial paper program, under which US$67 million was outstanding as at December 31, 2020, as reported in short-term borrowings.

(2)    $40 million in June 2021, $50 million in February 2022 and $100 million in August 2024

(3)    $500 million in April 2021, $50 million in April 2022 and $1.3 billion in July 2024

15. LEASES

The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 21 years, with optional renewal terms. Certain lease agreements include rental payments adjusted periodically for inflation or require the payment of real estate taxes, insurance, maintenance, or other operating expenses associated with the leased premises.

The Corporation's subsidiaries also have finance leases related to generating facilities with remaining terms of up to 35 years.

30

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Leases were presented on the consolidated balance sheets as follows.

(in millions)	2020		2019
Operating leases
Other assets	$	40	$	46
Accounts payable and other current liabilities	(7)		(8)
Other liabilities	(33)		(38)
Finance leases (1) (2)
Regulatory assets	$	122	$	116
PPE, net	211		308
Accounts payable and other current liabilities	(2)		(24)
Finance leases	(331)		(413)

(1)    FortisBC Electric has a finance lease for the BPPA (Note 8), which relates to the sale of the output of the Brilliant hydroelectric plant, and for the Brilliant Terminal Station ("BTS"), which relates to the use of the station. Both agreements expire in 2056. In exchange for the specified take-or-pay amounts of power, the BPPA requires semi-annual payments based on a return on capital, which includes the original and ongoing capital cost, and related variable power purchase costs. The BTS requires semi-annual payments based on a charge related to the recovery of the capital cost of the BTS, and related variable operating costs.

(2)    In December 2020 TEP purchased a 32.2% undivided interest in the Springerville Common Facilities, which had previously been leased (Note 10).

The components of lease expense were as follows.
(in millions)	2020		2019
Operating lease cost	$	10	$	10
Finance lease cost:
Amortization	14		17
Interest	34		48
Variable lease cost	20		39
Total lease cost	$	78	$	114

As at December 31, 2020, the present value of minimum lease payments was as follows.

(in millions)	Operating Leases		Finance Leases		Total
2021	$	8	$	33	$	41
2022	7		34		41
2023	6		34		40
2024	4		34		38
2025	3		34		37
Thereafter	22		1,056		1,078
	50		1,225		1,275
Less: Imputed interest	(10)		(892)		(902)
Total lease obligations	40		333		373
Less: Current installments	(7)		(2)		(9)
	$	33	$	331	$	364

31

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Supplemental lease information was as follows.
(in millions, except as noted)	2020		2019
Weighted average remaining lease term (years)
Operating leases	10		10
Finance leases	35		27
Weighted average discount rate (%)
Operating leases	4.0		4.1
Finance leases	5.1		4.8
Cash payments related to lease liabilities
Operating cash flows used for operating leases	$	(10)	$	(10)
Operating cash flows used for finance leases	(2)		(47)
Financing cash flows used for finance leases	(25)		(16)
Investing cash flows used for finance leases	(87)		(212)

See Note 26 for non-cash transactions that resulted in right-of-use assets obtained in exchange for new lease liabilities.

16. OTHER LIABILITIES

(in millions)	2020		2019
Employee future benefits (Note 25)	$	905	$	832
Customer and other deposits	132		70
AROs (Note 3)	130		148
Stock-based compensation plans (Note 21)	86		83
Manufactured gas plant site remediation (1)	69		48
Fair value of derivatives (Note 27)	50		68
Mine reclamation obligations (2)	47		43
Retail energy contract (3)	46		—
Deferred compensation plan (Note 9)	43		33
Operating leases	33		38
Other	58		83
	$	1,599	$	1,446

(1)    Environmental regulations require Central Hudson to investigate sites at which it or its predecessors once owned and/or operated manufactured gas plants and, if necessary, remediate those sites. Costs are accrued based on the amounts that can be reasonably estimated. As at December 31, 2020, an obligation of $96 million was recognized, including a current portion of $27 million recognized in accounts payable and other current liabilities (Note 13). Central Hudson has notified its insurers that it intends to seek reimbursement where insurance coverage exists. Differences between actual costs and the associated rate allowances are deferred as a regulatory asset for future recovery (Note 8).

(2)    TEP pays ongoing reclamation costs related to two coal mines that supply generating facilities in which it has an ownership interest but does not operate. Costs are deferred as a regulatory asset and recovered from customers as permitted by the regulator. TEP's share of the reclamation costs is estimated to be $61 million upon expiry of the coal agreements between 2022 and 2031. The present value of the estimated future liability is shown in the table above.

(3)    FortisAlberta entered into an eight-year agreement with an existing retail energy provider to continue to act as its default retailer to eligible customers under the regulated retail option. As part of this agreement FortisAlberta received an upfront payment in 2020 which will be amortized to earnings over the life of the agreement.

32

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

17. COMMON SHARES

During 2019 the Corporation issued approximately 4.1 million common shares under its at-the-market common equity program at an average price of $52.16 per share. The gross proceeds of $212 million ($209 million net of commissions) were used primarily to fund capital expenditures.

Also during 2019 the Corporation issued approximately 22.8 million common shares representing gross proceeds of $1,190 million ($1,167 million net of commissions) at a price of $52.15 per share. The net proceeds were used to redeem US$500 million of its outstanding 2.10% unsecured notes due on October 4, 2021, to repay credit facility borrowings, and for general corporate purposes.

18. EARNINGS PER COMMON SHARE

Diluted earnings per common share ("EPS") was calculated using the treasury stock method for options.

	2020					2019
	Net Earnings		Weighted			Net Earnings		Weighted
	to Common		Average			to Common		Average
	Shareholders		Shares	EPS		Shareholders		Shares	EPS
	($ millions)		(# millions)	($)		($ millions)		(# millions)	($)
Basic EPS	$	1,209	464.8	$	2.60	$	1,655	436.8	$	3.79
Potential dilutive effect of stock options	—		0.6	—		—		0.7	—
Diluted EPS	$	1,209	465.4	$	2.60	$	1,655	437.5	$	3.78

19. PREFERENCE SHARES

Authorized

An unlimited number of first preference shares and second preference shares, without nominal or par value.

Issued and Outstanding	2020			2019
First Preference Shares	Number			Number
	of Shares	Amount		of Shares	Amount
	(in thousands)	(in millions)		(in thousands)	(in millions)
Series F	5,000	$	122	5,000	$	122
Series G	9,200	225		9,200	225
Series H	7,665	188		7,025	172
Series I	2,335	57		2,975	73
Series J	8,000	196		8,000	196
Series K	10,000	244		10,000	244
Series M	24,000	591		24,000	591
	66,200	$	1,623	66,200	$	1,623

33

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Characteristics of the first preference shares are as follows.

			Reset	Redemption		Right to
	Initial	Annual	Dividend	and/or	Redemption	Convert on
	Yield	Dividend	Yield	Conversion	Value	a One-For-
First Preference Shares (1) (2)	(%)	($)	(%)	Option Date	($)	One Basis
Perpetual fixed rate
Series F	4.90	1.2250	—	Currently Redeemable	25.00	—
Series J (3)	4.75	1.1875	—	Currently Redeemable	25.25	—
Fixed rate reset (4) (5)
Series G	5.25	1.0983	2.13	September 1, 2023	25.00	—
Series H (6)	4.25	0.4588	1.45	June 1, 2025	25.00	Series I
Series K	4.00	0.9823	2.05	March 1, 2024	25.00	Series L
Series M	4.10	0.9783	2.48	December 1, 2024	25.00	Series N
Floating rate reset (5) (7)
Series I	2.10	—	1.45	June 1, 2025	25.00	Series H
Series L	—	—	—	—	—	Series K
Series N	—	—	—	—	—	Series M

(1)    Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board of Directors of the Corporation, payable in equal installments on the first day of each quarter.

(2)    On or after the specified redemption dates, the Corporation has the option to redeem for cash the outstanding first preference shares, in whole or in part, at the specified per share redemption value plus all accrued and unpaid dividends up to but excluding the dates fixed for redemption, and in the case of the first preference shares that reset, on every fifth anniversary date thereafter.

(3)    First Preference Shares, Series J are redeemable as of December 1, 2021 and thereafter at $25.00 per share.

(4)    On the redemption and/or conversion option date, and on each five-year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield.

(5)    On each conversion option date, the holders have the option, subject to certain conditions, to convert any or all of their shares into an equal number of Cumulative Redeemable first preference shares of a specified series.

(6)     The annual dividend per share for the First Preference Shares, Series H was reset from $0.6250 to $0.4588 for the five-year period from June 1, 2020 up to but excluding June 1, 2025.

(7)    The floating quarterly dividend rate will be reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.

On June 1, 2020, 267,341 First Preference Shares, Series H were converted on a one-for-one basis into First Preference Shares, Series I, and 907,577 First Preference Shares, Series I were converted on a one-for-one basis into First Preference Shares, Series H.

On the liquidation, dissolution or winding-up of Fortis, holders of common shares are entitled to participate ratably in any distribution of assets of Fortis, subject to the rights of holders of first and second preference shares, and any other class of shares of the Corporation entitled to receive the assets of the Corporation on such a distribution, in priority to or ratably with the holders of the common shares.

34

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

20. ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)	Opening Balance		Net Change		Ending Balance
2020
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations	$	713	$	(336)	$	377
Hedges of net investments in foreign operations	(359)		60		(299)
Income tax expense	(3)		(3)		(6)
	351		(279)		72
Other
Cash flow hedges (Note 27)	17		(21)		(4)
Unrealized employee future benefits losses (Note 25)	(38)		(11)		(49)
Income tax recovery	6		9		15
	(15)		(23)		(38)
Accumulated other comprehensive income	$	336	$	(302)	$	34
2019
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations	$	1,470	$	(757)	$	713
Hedges of net investments in foreign operations	(544)		185		(359)
Income tax recovery (expense)	10		(13)		(3)
	936		(585)		351
Other
Cash flow hedges (Note 27)	11		6		17
Unrealized employee future benefits losses (Note 25)	(20)		(18)		(38)
Income tax recovery	1		5		6
	(8)		(7)		(15)
Accumulated other comprehensive income	$	928	$	(592)	$	336

21. STOCK-BASED COMPENSATION PLANS

Stock Options

Officers and certain key employees of Fortis and its subsidiaries are eligible for grants of options to purchase common shares of the Corporation. Options are exercisable for a period of 10 years from the grant date, expire no later than three years after the death or retirement of the optionee, and vest evenly over a four-year period on each anniversary of the grant date.

35

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

The following options were granted in 2020 and 2019.

	2020	2019
Options granted (in thousands)	686	852
Exercise price ($) (1)	58.40	47.57
Grant date fair value ($)	4.20	3.70
Valuation assumptions:
Dividend yield (%) (2)	3.7	3.8
Expected volatility (%) (3)	15.8	15.2
Risk-free interest rate (%) (4)	1.2	1.8
Weighted average expected life (years) (5)	5.2	5.6

(1)Five-day VWAP immediately preceding the grant date

(2)Reflects average annual dividend yield up to the grant date and the weighted average expected life of the options

(3)Reflects historical experience over a period equal to the weighted average expected life of the options

(4)Government of Canada benchmark bond yield at the grant date that covers the weighted average expected life of the options

(5)Reflects historical experience

The following table summarizes information related to stock options for 2020.

	Total Options			Non-vested Options (1)
(in thousands, except as noted)	Number of Options	Weighted Average Exercise Price		Number of Options	Weighted Average Grant Date Fair Value
Options outstanding, beginning of year	3,418	$	41.18	1,910	$	3.43
Granted	686	$	58.40	686	$	4.20
Exercised	(825)	$	39.21	n/a	n/a
Vested	n/a	n/a		(807)	$	3.25
Cancelled/Forfeited	(17)	$	50.02	(17)	$	3.79
Options outstanding, end of year	3,262	$	45.26	1,772	$	3.81
Options vested, end of year (2)	1,490	$	39.40

(1)As at December 31, 2020, there was $7 million of unrecognized compensation expense related to stock options not yet vested, which is expected to be recognized over a weighted average period of approximately three years.

(2)As at December 31, 2020, the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $19 million.

The following table summarizes additional stock option information.

(in millions)	2020		2019
Stock options exercised:
Cash received for exercise price	$	32	$	51
Intrinsic value realized by employees	15		22

DSU Plan

Directors of the Corporation who are not officers are eligible for grants of DSUs representing the equity portion of their annual compensation. Directors can further elect to receive credit for their quarterly cash retainer in a notional account of DSUs in lieu of cash. The Corporation may also determine that special circumstances justify the grant of additional DSUs to a director.

Each DSU vests at the grant date, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash.

36

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

The following table summarizes information related to DSUs.

	2020	2019
Number of units (in thousands)
Beginning of year	165	177
Granted	25	29
Notional dividends reinvested	6	6
Paid out	(49)	(47)
End of year	147	165

The accrued liability has been recognized at the respective December 31st VWAP (Note 3) and included in long-term other liabilities (Note 16). The accrued liability, compensation expense and cash payout were not material for 2020 or 2019.

PSU Plans

Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of PSUs representing a component of their long-term compensation.

Each PSU vests over a three-year period, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash. At the end of the three-year vesting period, cash payouts are the product of: (i) the numbers of units vested; (ii) the VWAP of the Corporation's common shares for the five trading days prior to the vesting date; and (iii) a payout percentage that may range from 0% to 200%.

The payout percentage is based on the Corporation's performance over the three-year vesting period, mainly determined by: (i) the Corporation's total shareholder return as compared to a predefined peer group of companies; and (ii) the Corporation's cumulative EPS, or for certain subsidiaries the Company's cumulative net income, as compared to the target established at the time of the grant.

The following table summarizes information related to PSUs.

	2020		2019
Number of units (in thousands)
Beginning of year	2,118		1,763
Granted	586		690
Notional dividends reinvested	71		73
Paid out	(735)		(357)
Cancelled/forfeited	(64)		(51)
End of year	1,976		2,118
Additional information (in millions)
Compensation expense recognized	$	58	$	74
Compensation expense unrecognized (1)	32		35
Cash payout	54		16
Accrued liability as at December 31 (2)	108		106
Aggregate intrinsic value as at December 31 (3)	140		141

(1)    Relates to unvested PSUs and is expected to be recognized over a weighted average period of two years

(2)    Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16)

(3)    Relates to outstanding PSUs and reflects a weighted average contractual life of one year

37

FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

RSU Plans

Senior management of the Corporation and its subsidiaries, and all ITC employees, are eligible for grants of RSUs representing a component of their long-term compensation.

Each RSU vests over a three-year period or immediately upon retirement eligibility of the holder, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash or, beginning with the 2020 grant, common shares of the Corporation. RSUs issued in 2020 may be settled in cash, common shares, or an equal proportion of cash and common shares depending on an executives' settlement election and whether their share ownership requirements have been met.

The following table summarizes information related to RSUs.

	2020		2019
Number of units (in thousands)
Beginning of year	1,050		717
Granted	356		429
Notional dividends reinvested	37		35
Paid out	(355)		(92)
Cancelled/forfeited	(40)		(39)
End of year	1,048		1,050
Additional information (in millions)
Compensation expense recognized	$	20	$	24
Compensation expense unrecognized (1)	15		17
Cash payout	19		4
Accrued liability as at December 31 (2)	39		39
Aggregate intrinsic value as at December 31 (3)	54		56

(1)    Relates to unvested RSUs and is expected to be recognized over a weighted average period of two years

(2)    Recognized at the respective December 31st VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16)

(3)    Relates to outstanding RSUs and reflects a weighted average contractual life of one year

22. DISPOSITION

On April 16, 2019, Fortis sold its 51% ownership interest in the 335 MW Waneta Expansion for proceeds of $995 million. A gain on disposition of $577 million ($484 million after tax), net of expenses, was recognized in the Corporate and Other segment, and the related non-controlling interest was removed from equity.

Up to the date of disposition, excluding the gain as noted above, the Waneta Expansion contributed $17 million to earnings before income tax expense, of which Fortis' share was 51%.

23. OTHER INCOME, NET

(in millions)	2020		2019
Equity component of AFUDC	$	78	$	74
Equity income	20		(1)
Derivative gains	13		17
Interest income	13		16
Gain on repayment of debt	—		11
Other	30		21
	$	154	$	138

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

24. INCOME TAXES

Deferred Income Tax Assets and Liabilities

The significant components of deferred income tax assets and liabilities consisted of the following.

(in millions)	2020		2019
Gross deferred income tax assets
Regulatory liabilities	$	527	$	588
Tax loss and credit carryforwards	494		532
Employee future benefits	175		165
Unrealized foreign exchange losses on long-term debt (1)	33		40
Other	83		88
	1,312		1,413
Valuation allowance (1)	(22)		(22)
Net deferred income tax asset	$	1,290	$	1,391
Gross deferred income tax liabilities
PPE	$	(4,253)	$	(3,986)
Regulatory assets	(263)		(269)
Intangible assets	(118)		(105)
	(4,634)		(4,360)
Net deferred income tax liability	$	(3,344)	$	(2,969)

(1)    These deferred income tax assets can be utilized only to the extent that the Corporation has capital gains to offset the underlying capital losses. Management believes that it is more likely than not that a $22 million shortfall exists in this regard and, therefore, the Corporation has recognized a $22 million valuation allowance. Management believes that, based on its historical pattern of taxable income, Fortis will generate the necessary income in the future to realize all other deferred income tax assets.

Unrecognized Tax Benefits

(in millions)	2020		2019
Beginning of year	$	36	$	38
Additions related to current year	3		5
Adjustments related to prior years	(6)		(7)
End of year	$	33	$	36

Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2020. Fortis has not recognized interest expense in 2020 and 2019 related to unrecognized tax benefits.

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Income Tax Expense

(in millions)	2020		2019
Canadian
Earnings before income tax expense	$	333	$	901
Current income tax	20		49
Deferred income tax	(16)		42
Total Canadian	$	4	$	91
Foreign
Earnings before income tax expense	$	1,287	$	1,240
Current income tax	(15)		(7)
Deferred income tax	242		205
Total Foreign	$	227	$	198
Income tax expense	$	231	$	289

Income tax expense differs from the amount that would be expected to be generated by applying the enacted combined Canadian federal and provincial statutory income tax rate to earnings before income tax expense.

The following is a reconciliation of consolidated statutory taxes to consolidated effective taxes.

(in millions, except as noted)	2020		2019
Earnings before income tax expense	$	1,620	$	2,141
Combined Canadian federal and provincial statutory income tax rate (%)	30.0		28.5
Expected federal and provincial taxes at statutory rate	$	486	$	610
Decrease resulting from:
Foreign and other statutory rate differentials	(145)		(124)
Difference between gain on sale for accounting and amounts calculated for tax purposes	—		(73)
Release of valuation allowance	—		(33)
AFUDC	(20)		(16)
Effects of rate-regulated accounting:
Difference between depreciation claimed for income tax and accounting purposes	(56)		(48)
Items capitalized for accounting purposes but expensed for income tax purposes	(26)		(17)
Other	(8)		(10)
Income tax expense	$	231	$	289
Effective tax rate (%)	14.3		13.5

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Income Tax Carryforwards

(in millions)	Expiring Year	2020
Canadian
Capital loss	n/a	$	27
Non-capital loss	2035-2040	200
Other tax credits	2026-2040	2
		229
Unrecognized		(26)
		203
Foreign
Federal and state net operating loss	2021-2040	2,971
Other tax credits	2022-2040	34
		3,005
Total income tax carryforwards recognized		$	3,208

The Corporation and certain of its subsidiaries are subject to taxation in Canada, the United States and other foreign jurisdictions. The material jurisdictions in which the Corporation is subject to potential income tax compliance examinations include the United States (Federal, Arizona, Kansas, Iowa, Michigan, Minnesota and New York) and Canada (Federal and British Columbia). The Corporation's 2013 to 2020 taxation years are still open for audit in Canadian jurisdictions, and its 2011 to 2020 taxation years are still open for audit in United States jurisdictions.

25. EMPLOYEE FUTURE BENEFITS

For defined benefit pension and OPEB plans, the benefit obligation and fair value of plan assets are measured as at December 31.

For the Corporation's Canadian and Caribbean subsidiaries, actuarial valuations to determine funding contributions for pension plans are required at least every three years. The most recent valuations were as of December 31, 2017 for the Corporation; December 31, 2018 for FortisBC Energy and FortisBC Electric (plan covering unionized employees); December 31, 2019 for the remaining FortisBC Electric plans, Newfoundland Power, FortisAlberta and FortisOntario; and December 31, 2020 for Caribbean Utilities.

ITC, UNS Energy and Central Hudson perform annual actuarial valuations as their funding requirements are based on maintaining minimum annual targets, all of which have been met.

The Corporation's investment policy is to ensure that the defined benefit pension and OPEB plan assets, together with expected contributions, are invested in a prudent and cost-effective manner to optimally meet the liabilities of the plans. The investment objective is to maximize returns in order to manage the funded status of the plans and minimize the Corporation's cost over the long term, as measured by both cash contributions and recognized expense.

Allocation of Plan Assets

	2020 Target Allocation
(weighted average %)		2020	2019
Equities	46	48	47
Fixed income	47	45	46
Real estate	6	6	6
Cash and other	1	1	1
	100	100	100

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Fair Value of Plan Assets

(in millions)	Level 1 (1)		Level 2 (1)		Level 3 (1)		Total
2020
Equities	$	713	$	1,163	$	—	$	1,876
Fixed income	197		1,580		—		1,777
Real estate	—		17		204		221
Private equities	—		—		20		20
Cash and other	8		17		—		25
	$	918	$	2,777	$	224	$	3,919
2019
Equities	$	622	$	1,050	$	—	$	1,672
Fixed income	171		1,445		—		1,616
Real estate	—		16		207		223
Private equities	—		—		22		22
Cash and other	8		10		—		18
	$	801	$	2,521	$	229	$	3,551

(1)    See Note 27 for a description of the fair value hierarchy.

The following table reconciles the changes in the fair value of plan assets that have been measured using Level 3 inputs.

(in millions)	2020		2019
Balance, beginning of year	$	229	$	215
(Loss) return on plan assets	(2)		19
Foreign currency translation	(1)		(2)
Purchases, sales and settlements	(2)		(3)
Balance, end of year	$	224	$	229

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Funded Status	Defined Benefit Pension Plans				OPEB Plans
(in millions)	2020		2019		2020		2019
Change in benefit obligation (1)
Balance, beginning of year	$	3,632	$	3,207	$	712	$	655
Service costs	98		77		32		27
Employee contributions	17		16		2		2
Interest costs	113		124		22		25
Benefits paid	(162)		(144)		(27)		(27)
Actuarial losses	350		439		62		46
Past service (credits) costs/plan amendments	—		1		(3)		4
Foreign currency translation	(53)		(88)		(11)		(20)
Balance, end of year (2) (3)	$	3,995	$	3,632	$	789	$	712
Change in value of plan assets
Balance, beginning of year	$	3,208	$	2,830	$	343	$	293
Actual return on plan assets	444		523		55		62
Benefits paid	(155)		(138)		(27)		(27)
Employee contributions	17		18		2		2
Employer contributions	62		53		28		28
Foreign currency translation	(48)		(78)		(10)		(15)
Balance, end of year (4)	$	3,528	$	3,208	$	391	$	343
Funded status	$	(467)	$	(424)	$	(398)	$	(369)
Balance sheet presentation
Long-term assets (Note 9)	$	58	$	46	$	8	$	17
Current liabilities (Note 13)	(13)		(12)		(13)		(12)
Long-term liabilities (Note 16)	(512)		(458)		(393)		(374)
	$	(467)	$	(424)	$	(398)	$	(369)

(1)Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans.

(2)The accumulated benefit obligation, which excludes assumptions about future salary levels, for defined benefit pension plans was $3,679 million as at December 31, 2020 (2019 - $3,352 million).

(3)The increases in the defined benefit pension and OPEB obligations were driven by the decrease in discount rates due to lower interest rates.

(4)The increases in the defined benefit pension and OPEB plan assets were driven by market returns.

For those defined benefit pension plans for which the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the obligation was $3,290 million compared to plan assets of $2,777 million (2019 - $2,971 million and $2,511 million, respectively).

For those defined benefit pension plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the obligation was $3,037 million compared to plan assets of $2,741 million (2019 - $2,752 million and $2,478 million, respectively).

For those OPEB plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2020, the obligation was $589 million compared to plan assets of $183 million (2019 - $537 million and $151 million, respectively).

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Net Benefit Cost (1)	Defined Benefit Pension Plans				OPEB Plans
(in millions)	2020		2019		2020		2019
Service costs	$	98	$	77	$	32	$	27
Interest costs	113		124		22		25
Expected return on plan assets	(176)		(161)		(19)		(16)
Amortization of actuarial losses (gains)	33		24		(5)		(4)
Amortization of past service credits/plan amendments	(1)		(1)		(2)		(7)
Regulatory adjustments	—		2		4		3
	$	67	$	65	$	32	$	28

(1)    The non-service cost components of net periodic benefit cost are included in other income, net in the consolidated statements of earnings.

The following table summarizes the accumulated amounts of net benefit cost that have not yet been recognized in earnings or comprehensive income and shows their classification on the consolidated balance sheets.

	Defined Benefit Pension Plans				OPEB Plans
(in millions)	2020		2019		2020		2019
Unamortized net actuarial losses (gains)	$	42	$	32	$	(1)	$	(2)
Unamortized past service costs	1		1		7		7
Income tax recovery	(10)		(8)		(1)		(1)
Accumulated other comprehensive income	$	33	$	25	$	5	$	4
Net actuarial losses (gains)	$	517	$	486	$	12	$	(18)
Past service credits	(7)		(9)		(8)		(8)
Other regulatory deferrals	13		15		18		19
	$	523	$	492	$	22	$	(7)
Regulatory assets (Note 8)	$	523	$	492	$	65	$	38
Regulatory liabilities (Note 8)	—		—		(43)		(45)
Net regulatory assets (liabilities)	$	523	$	492	$	22	$	(7)

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory assets.

	Defined Benefit Pension Plans				OPEB Plans
(in millions)	2020		2019		2020		2019
Current year net actuarial losses	$	9	$	11	$	1	$	—
Past service costs/plan amendments	—		—		—		5
Amortization of actuarial losses	1		1		—		—
Foreign currency translation	—		1		—		—
Income tax recovery	(2)		(5)		—		—
Total recognized in comprehensive income	$	8	$	8	$	1	$	5
Current year net actuarial losses	$	69	$	64	$	25	$	3
Past service costs (credits)/plan amendments	—		—		(3)		—
Amortization of actuarial (losses) gains	(31)		(23)		5		4
Amortization of past service (costs) credits	2		(1)		3		8
Foreign currency translation	(7)		(10)		—		—
Regulatory adjustments	(2)		—		(1)		(8)
Total recognized in regulatory assets	$	31	$	30	$	29	$	7

Significant Assumptions	Defined Benefit Pension Plans		OPEB Plans
(weighted average %)	2020	2019	2020	2019
Discount rate during the year (1)	3.16	4.05	3.22	4.10
Discount rate as at December 31	2.63	3.20	2.64	3.25
Expected long-term rate of return on plan assets (2)	5.52	5.78	5.28	5.50
Rate of compensation increase	3.34	3.33	—	—
Health care cost trend increase as at December 31 (3)	—	—	4.61	4.62

(1)ITC and UNS use the split discount rate methodology for determining current service and interest costs. All other subsidiaries use the single discount rate approach.

(2)Developed by management using best estimates of expected returns, volatilities and correlations for each class of asset. Best estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.

(3)The projected 2021 weighted average health care cost trend rate is 5.91% and is assumed to decrease over the next 11 years to the weighted average ultimate health care cost trend rate of 4.61% in 2031 and thereafter.

Expected Benefit Payments	Defined Benefit		OPEB
(in millions)	Pension Payments		Payments
2021	$	163	$	27
2022	165		28
2023	170		30
2024	174		31
2025	180		32
2026-2030	984		174

During 2021 the Corporation expects to contribute $49 million for defined benefit pension plans and $33 million for OPEB plans.

In 2020 the Corporation expensed $42 million (2019 - $39 million) related to defined contribution pension plans.

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

26. SUPPLEMENTARY CASH FLOW INFORMATION

(in millions)	2020		2019
Cash paid (received) for
Interest	$	1,027	$	1,007
Income taxes	(26)		(37)
Change in working capital
Accounts receivable and other current assets	$	(84)	$	1
Prepaid expenses	(15)		(8)
Inventories	(36)		(13)
Regulatory assets - current portion	(49)		(75)
Accounts payable and other current liabilities	(100)		(8)
Regulatory liabilities - current portion	(150)		(65)
	$	(434)	$	(168)
Non-cash investing and financing activities
Accrued capital expenditures	$	400	$	382
Common share dividends reinvested	114		299
Contributions in aid of construction	13		15
Right-of-use assets obtained in exchange for operating lease liabilities	3		55
Exercise of stock options into common shares	3		5
Finance leases	2		88

27. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Derivatives

The Corporation generally limits the use of derivatives to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery.

The Corporation records all derivatives at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. Fair values reflect estimates based on current market information about the derivatives as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future consolidated earnings or cash flow.

Cash flow associated with the settlement of all derivatives is included in operating activities on the consolidated statements of cash flows.

Energy Contracts Subject to Regulatory Deferral

UNS Energy holds electricity power purchase contracts, customer supply contracts and gas swap contracts to reduce its exposure to energy price risk. Fair values are measured primarily under the market approach using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission costs and line losses.

Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price. Fair values are measured using forward pricing provided by independent third-party information.

FortisBC Energy holds gas supply contracts to fix the effective purchase price of natural gas. Fair values reflect the present value of future cash flows based on published market prices and forward natural gas curves.

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Unrealized gains or losses associated with changes in the fair value of these energy contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. As at December 31, 2020, unrealized losses of $73 million (2019 - $119 million) were recognized as regulatory assets and unrealized gains of $17 million (2019 - $2 million) were recognized as regulatory liabilities.

Energy Contracts Not Subject to Regulatory Deferral

UNS Energy holds wholesale trading contracts to fix power prices and realize potential margin, of which 10% of any realized gains is shared with customers through rate stabilization accounts. Fair values are measured using a market approach incorporating, where possible, independent third-party information.

Aitken Creek holds gas swap contracts to manage its exposure to changes in natural gas prices, capture natural gas price spreads, and manage the financial risk posed by physical transactions. Fair values are measured using forward pricing from published market sources.

Unrealized gains or losses associated with changes in the fair value of these energy contracts are recognized in revenue and were not material for 2020 and 2019.

Total Return Swaps

The Corporation holds total return swaps to manage the cash flow risk associated with forecast future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $113 million and terms of one to three years expiring at varying dates through January 2023. Fair value is measured using an income valuation approach based on forward pricing curves. Unrealized gains and losses associated with changes in fair value are recognized in other income, net and were not material for 2020 and 2019.

Foreign Exchange Contracts

The Corporation holds US dollar-denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The contracts expire at varying dates through February 2022 and have a combined notional amount of $245 million. Fair value was measured using independent third-party information. Unrealized gains and losses associated with changes in fair value are recognized in other income, net and were not material for 2020 and 2019.

Interest Rate Swaps

ITC entered into forward-starting interest rate swaps to manage the interest rate risk associated with planned borrowings. The swaps, which had a combined notional value of $611 million, were terminated in May 2020 with the issuance of US$700 million senior notes. Realized losses of $31 million were recognized in other comprehensive income and are being reclassified to earnings as a component of interest expense over five years.

Other Investments

ITC, UNS Energy and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees. These investments consist of mutual funds and money market accounts, which are recorded at fair value based on quoted market prices in active markets. Gains and losses are recognized in other income, net and were not material for 2020 and 2019.

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

Recurring Fair Value Measures

The following table presents derivative assets and liabilities that are accounted for at fair value on a recurring basis.

(in millions)	Level 1 (1)		Level 2 (1)		Level 3 (1)		Total
As at December 31, 2020
Assets
Energy contracts subject to regulatory deferral (2) (3)	$	—	$	38	$	—	$	38
Energy contracts not subject to regulatory deferral (2)	—		6		—		6
Foreign exchange contracts and total return swaps (2)	16		—		—		16
Other investments (4)	126		—		—		126
	$	142	$	44	$	—	$	186
Liabilities
Energy contracts subject to regulatory deferral (3) (5)	$	—	$	(94)	$	—	$	(94)
Energy contracts not subject to regulatory deferral (5)	—		(12)		—		(12)
	$	—	$	(106)	$	—	$	(106)

As at December 31, 2019
Assets
Energy contracts subject to regulatory deferral (2) (3)	$	—	$	22	$	—	$	22
Energy contracts not subject to regulatory deferral (2)	—		8		—		8
Foreign exchange contracts, interest rate and total return swaps (2)	14		4		—		18
Other investments (4)	121		—		—		121
	$	135	$	34	$	—	$	169
Liabilities
Energy contracts subject to regulatory deferral (3) (5)	$	(1)	$	(138)	$	—	$	(139)
Energy contracts not subject to regulatory deferral (5)	—		(12)		—		(12)
	$	(1)	$	(150)	$	—	$	(151)

(1)Under the hierarchy, fair value is determined using: (i) Level 1 - unadjusted quoted prices in active markets; (ii) Level 2 - other pricing inputs directly or indirectly observable in the marketplace; and (iii) Level 3 - unobservable inputs, used when observable inputs are not available. Classifications reflect the lowest level of input that is significant to the fair value measurement.

(2)Included in accounts receivable and other current assets or other assets

(3)Unrealized gains and losses arising from changes in fair value of these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates as permitted by the regulators, with the exception of long-term wholesale trading contracts and certain gas swap contracts.

(4)Included in other assets

(5)Included in accounts payable and other current liabilities or other liabilities

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

The Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions, which apply only to its energy contracts. The following table presents the potential offset of counterparty netting.

(in millions)	Gross Amount Recognized in Balance Sheet		Counterparty Netting of Energy Contracts		Cash Collateral Received/Posted		Net Amount
As at December 31, 2020
Derivative assets	$	44	$	26	$	10	$	8
Derivative liabilities	(106)		(26)		(9)		(71)

As at December 31, 2019
Derivative assets	$	30	$	22	$	10	$	(2)
Derivative liabilities	(151)		(22)		(2)		(127)

Volume of Derivative Activity

As at December 31, 2020, the Corporation had various energy contracts that will settle on various dates through 2029. The volumes related to electricity and natural gas derivatives are outlined below.

	2020	2019
Energy contracts subject to regulatory deferral (1)
Electricity swap contracts (GWh)	522	628
Electricity power purchase contracts (GWh)	2,781	3,198
Gas swap contracts (PJ)	156	168
Gas supply contract premiums (PJ)	203	241
Energy contracts not subject to regulatory deferral (1)
Wholesale trading contracts (GWh)	1,588	1,855
Gas swap contracts (PJ)	36	43

(1)GWh means gigawatt hours and PJ means petajoules

Credit Risk

For cash equivalents, accounts receivable and other current assets, and long-term other receivables, credit risk is generally limited to the carrying value on the consolidated balance sheets. The Corporation's subsidiaries generally have a large and diversified customer base, which minimizes the concentration of credit risk. Policies in place to minimize credit risk include requiring customer deposits, prepayments and/or credit checks for certain customers, performing disconnections and/or using third-party collection agencies for overdue accounts. As a result of the impact of the COVID-19 pandemic, certain of the Corporation's utilities have temporarily suspended non-payment disconnects, delayed customer rate increases and deferred the recovery of costs (Note 2). The Corporation has seen an increase in accounts receivable and, accordingly, its allowance for credit losses during 2020 (Note 6).

ITC has a concentration of credit risk as approximately 70% of its revenue is derived from three customers. The customers have investment-grade credit ratings and credit risk is further managed by MISO by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors.

FortisAlberta has a concentration of credit risk as distribution service billings are to a relatively small group of retailers. Credit risk is managed by obtaining from the retailers either a cash deposit, letter of credit, an investment-grade credit rating, or a financial guarantee from an entity with an investment-grade credit rating.

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and the Corporation may be exposed to credit risk in the event of non‑performance by counterparties to derivatives. Credit risk is managed by net settling payments, when possible, and dealing only with counterparties that have investment-grade credit ratings. At UNS Energy and Central Hudson, certain contractual arrangements require counterparties to post collateral.

The value of derivatives in net liability positions under contracts with credit risk-related contingent features that, if triggered, could require the posting of a like amount of collateral was $88 million as at December 31, 2020 (2019 - $161 million).

Hedge of Foreign Net Investments

The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, Belize Electric Company Limited and Belize Electricity is, or is pegged to, the US dollar. The earnings and cash flow from, and net investments in, these entities are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has limited this exposure through hedging.

As at December 31, 2020, US$2.3 billion (2019 - US$2.2 billion) of corporately issued US dollar-denominated long-term debt has been designated as an effective hedge of net investments, leaving approximately US$10.2 billion (2019 - US$9.7 billion) unhedged. Exchange rate fluctuations associated with the hedged net investment in foreign subsidiaries and the debt serving as the hedge are recognized in accumulated other comprehensive income.

Financial Instruments Not Carried at Fair Value

Excluding long-term debt, the consolidated carrying value of the Corporation's remaining financial instruments approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature.

As at December 31, 2020, the carrying value of long-term debt, including current portion, was $24.5 billion (2019 - $22.3 billion) compared to an estimated fair value of $29.1 billion (2019 - $25.3 billion).

28. COMMITMENTS AND CONTINGENCIES

As at December 31, 2020, unconditional minimum purchase obligations were as follows.

(in millions)	Total		Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter
Waneta Expansion capacity agreement (1)	$	2,576	$	52	$	53	$	54	$	55	$	56	$	2,306
Gas and fuel purchase obligations (2)	2,355		679		453		312		192		124		595
Power purchase obligations (3)	1,867		249		208		188		191		180		851
Renewable PPAs (4)	1,380		102		102		101		101		101		873
ITC easement agreement (5)	381		13		13		13		13		13		316
Debt collection agreement (6)	112		3		3		3		3		3		97
Renewable energy credit purchase agreements (7)	97		15		14		16		9		7		36
Other (8)	116		48		5		4		4		3		52
	$	8,884	$	1,161	$	851	$	691	$	568	$	487	$	5,126

(1)    FortisBC Electric is a party to an agreement to purchase capacity from the Waneta Expansion for forty-years, beginning April 2015.

(2)    FortisBC Energy ($1,482 million): includes contracts for the purchase of gas, gas transportation and storage services, expiring in 2062. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2020.

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

UNS Energy ($747 million): includes long-term contracts for the purchase and delivery of coal to fuel generating facilities, the purchase of gas transportation services to meet load requirements, and the purchase of transmission services for purchased power. Amounts paid for coal depend on actual quantities purchased and delivered. Certain contracts have price adjustment clauses that will affect future costs. These contracts have various expiry dates through 2040.

(3)    Maritime Electric ($910 million): includes an agreement entitling Maritime Electric to approximately 4.55% of the output of New Brunswick Power's Point Lepreau nuclear generating station and requiring Maritime Electric to pay its share of the station's capital operating costs for the life of the unit. Maritime Electric also has two take-or-pay contracts for the purchase of either capacity or energy, expiring in December 2026.

FortisOntario ($599 million): an agreement with Hydro-Québec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated energy annually through December 2030.

FortisBC Electric ($295 million): an agreement with BC Hydro to purchase up to 200 MW of capacity and 1,752 GWh of associated energy annually for a 20-year term beginning October 1, 2013.

(4)    TEP and UNS Electric are party to renewable PPAs, with expiry dates from 2027 through 2043, that require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities and RECs associated with the output delivered once commercial operation is achieved. Amounts are the estimated future payments.

(5)    ITC is party to an agreement with Consumers Energy, the primary customer of METC, which provides METC with an easement for transmission purposes and rights-of-way, leasehold interests, fee interests and licences associated with the land over which its transmission lines cross. The agreement expires in December 2050, subject to 10 potential 50-year renewals thereafter unless METC gives notice of non-renewal at least one year in advance.

(6)    Maritime Electric is party to a debt collection agreement with PEI Energy Corporation for the initial capital cost of the submarine cables and associated parts of the New Brunswick transmission system interconnection. Payments under the agreement, which expires in February 2056, will be collected from customers in future rates.

(7)    UNS Energy and Central Hudson are party to renewable energy credit purchase agreements, mainly for the purchase of environmental attributions from retail customers with solar installations or other renewable generation. Payments are primarily made at contractually agreed-upon intervals based on metered energy production.

(8)    Includes a $24 million payment to be made in 2021 under the Oso Grande Wind Project build-transfer agreement by UNS Energy, as well as AROs and joint-use asset and shared service agreements.

Other Commitments

Under a funding framework with the Governments of Ontario and Canada, Fortis will contribute a minimum of approximately $155 million of equity capital to the Wataynikaneyap Partnership, based on Fortis' proportionate 39% ownership interest and the final regulatory-approved capital cost of the related project. In October 2019 the Wataynikaneyap Partnership entered into loan agreements to finance the project during construction. In the event a lender under the loan agreements realizes security on the loans, Fortis may be required to accelerate its equity capital contributions, which may be in excess of the amount otherwise required of Fortis under the funding framework, to a maximum total funding of $235 million.

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FORTIS INC.

Notes to Consolidated Financial Statements

For the years ended December 31, 2020 and 2019

UNS Energy has joint generation performance guarantees with participants at San Juan, Four Corners, and Luna, with agreements expiring in 2022 through 2046, and at Navajo through decommissioning. The participants have guaranteed that in the event of payment default, each non-defaulting participant will bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. In the case of Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of $318 million for Four Corners. As at December 31, 2020, there was no obligation under these guarantees.

Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York State. Central Hudson's maximum commitment is $94 million, for which it has issued a parental guarantee. As at December 31, 2020, there was no obligation under this guarantee.

As at December 31, 2020, FortisBC Holdings Inc. ("FHI") had $69 million of parental guarantees outstanding to support storage optimization activities at Aitken Creek.

Contingency

In April 2013 FHI and Fortis were named as defendants in an action in the British Columbia Supreme Court by the Coldwater Indian Band ("Band") regarding interests in a pipeline right-of-way on reserve lands. The pipeline was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in 2007. The Band seeks cancellation of the right-of-way and damages for wrongful interference with the Band's use and enjoyment of reserve lands. In May 2016 the Federal Court dismissed the Band's application for judicial review of the ministerial consent. In September 2017 the Federal Court of Appeal set aside the Minister's consent and returned the matter to the Minister for redetermination. No amount has been accrued as the outcome cannot yet be reasonably determined.

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