40-F

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_______________________

FORM 40-F

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

☒ ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

Commission file number: 001-37915

_______________________

FORTIS INC.

(Exact name of Registrant as specified in its charter)	Newfoundland and Labrador, Canada	4911	98-0352146
(Province of other jurisdiction of<br><br>incorporation or organization)	(Primary Standard Industrial Classification<br><br>Code Number)	(I.R.S. Employer Identification Number)

Fortis Place, Suite 1100

5 Springdale Street

St. John's, Newfoundland and Labrador

Canada A1E 0E4

James R. Reid

(709) 737-2800

(Address and telephone number of Registrant's principal executive offices)

_______________________

CT Corporation System

111 Eighth Avenue

New York, New York 10011

(212) 590‑9070

(Name, address (including zip code) and telephone number (including area code) of agent for service in the United States)

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Common Shares, without par value	FTS	New York Stock Exchange
(Title of each class)	(Trading Symbol(s)	(Name of exchange on which registered)

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

(Title of Class)

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

None

(Title of Class)

For annual reports, indicate by check mark the information filed with this Form:

☒ Annual information form ☒ Audited annual financial statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report.

463,274,945 Common Shares as of December 31, 2019

Indicate by check mark whether the Registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the Registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the Registrant was required to submit such files).

Yes ☒ No ☐

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company ☐

If an emerging growth company that prepares its financial statements in accordance with accounting principles generally accepted in the United States ("U.S. GAAP"), indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐

† The term "new or revised financial accounting standard" refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012.

EXPLANATORY NOTE

Fortis Inc. (the "Corporation" or "Fortis") is a Canadian issuer eligible to file its annual report pursuant to Section 13 of the Securities Exchange Act of 1934, as amended (the "Exchange Act"), on Form 40-F pursuant to the multi-jurisdictional disclosure system of the Exchange Act. The Corporation is a "foreign private issuer" as defined in Rule 405 under the Securities Act of 1933, as amended. Equity securities of the Corporation are accordingly exempt from Sections 14(a), 14(b), 14(c), 14(f) and 16 of the Exchange Act pursuant to Rule 3a12-3.

FORWARD LOOKING INFORMATION

The Corporation includes forward-looking information in this Annual Report on Form 40-F and the exhibits attached hereto (the "Form 40-F") within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of the Corporation's management regarding future growth, results of operations, performance, business prospects and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates, expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would and the negative of these terms and other similar expressions have been used to identify the forward-looking information, which includes, without limitation: forecast capital expenditures for 2020 and the period 2020 to 2024 and potential funding sources for the capital plan; forecast rate base for 2022 and 2024; the expectation that long-term sustainable growth in rate base will support continuing growth in earnings and dividends; target average annual dividend growth through 2024; the expectation that Tucson Electric Power and UNS Energy Corporation have sufficient generating capacity, together with existing power purchase agreements and expected generation plant additions, to satisfy the requirements of its customer base and meet future peak demand requirements; and the expectation that future increases in energy supply costs will increase Newfoundland Power Inc.'s electricity rates; the expectation that Fortis will remain at the forefront of the industry by leveraging its strengths and partnerships; expected timing, outcome and impact of regulatory decisions; expected or potential funding sources for operating expenses, interest costs and capital expenditure plans; the expectation that maintaining the targeted capital structure of the regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will continue to have access to long-term capital and will remain compliant with debt covenants throughout 2020; the nature, timing, benefits and expected costs of certain capital projects including the Multi-Value Regional Transmission Projects, 34.5 to 69 kilovolt Transmission Conversion Project, Southline Transmission Project, Oso Grande Wind Project, Transmission Integrity Management Capabilities Project, Inland Gas Upgrades Project, Wataynikaneyap Transmission Power Project and additional opportunities beyond the base plan, including the Lake Erie Connector Project; and the expectation that the adoption of future accounting pronouncements will not have a material adverse impact.

Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: reasonable regulatory decisions and the expectation of regulatory stability; the implementation of the five-year capital plan; no material capital project or financing cost overruns; sufficient human resources to deliver service and execute the capital plan; the realization of additional opportunities; the Board exercising its discretion to declare dividends, taking into account the financial performance and condition of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability or upset; the continued ability to maintain the performance of the electricity and gas systems; no severe and prolonged economic downturn; sufficient liquidity and capital resources; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; the continued availability of natural gas, fuel, coal and electricity supply; continuation of power supply and capacity purchase contracts; no significant changes in government energy plans, environmental laws and regulations that could have a material negative impact; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; no significant changes in tax laws and the continued tax deferred treatment of earnings from the Corporation's foreign operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with Indigenous Peoples; and favourable labour relations.

Forward-looking information involves significant risks, uncertainties and assumptions. The Corporation cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. For additional information with respect to certain of these risks or factors, reference should be made to the information detailed under the heading "Business Risks" on page 25 of management's discussion and analysis for the year ended December 31, 2019, which is filed as Exhibit 99.3 to this Form 40-F and incorporated by reference herein (the "Annual MD&A"), and to continuous disclosure materials filed from time to time by the Corporation with Canadian securities regulatory authorities and the U.S. Securities and Exchange Commission (the "SEC"). Key risk factors for 2020 include, but are not limited to:

•	uncertainty regarding the outcome of regulatory proceedings at the Corporation's utilities;
•	risks associated with climate change, physical risks and service disruption;
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•	the impact of fluctuations in interest rates;
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•	the impact of weather variability and seasonality on heating and cooling loads, gas distribution volumes and hydroelectric generation; and
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•	risks associated with acquisitions and capital projects.
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All forward-looking information in this Form 40-F is given as of the date of this Form 40-F and the Corporation disclaims any intention or obligation to revise or update any forward-looking information as a result of new information, future events or otherwise.

CURRENCY

The Corporation presents its consolidated financial statements in Canadian dollars unless otherwise specified. All dollar amounts in this Form 40-F are stated in Canadian dollars ("$" or "C$"), except where otherwise indicated. On February 12, 2020, the daily average exchange rate (as reported by the Bank of Canada) of United States dollars ("US$") into Canadian dollars was US$1.00 equals C$1.33.

CERTIFICATIONS

See Exhibits 99.4, 99.5, 99.6 and 99.7 to this Form 40-F.

DISCLOSURE CONTROLS AND PROCEDURES

Disclosure controls and procedures are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and United States securities laws. As of December 31, 2019, an evaluation was carried out under the supervision of, and with the participation of, the Corporation's management, including the President and Chief Executive Officer and the Executive Vice President, Chief Financial Officer, of the effectiveness of the Corporation's disclosure controls and procedures, as defined in the applicable Canadian and United States securities laws. Based on that evaluation, the President and Chief Executive Officer and the Executive Vice President, Chief Financial Officer concluded that such disclosure controls and procedures are effective as of December 31, 2019.

MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management of the Corporation is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is designed by, or under the supervision of, the Corporation's President and Chief Executive Officer and the Executive Vice President, Chief Financial Officer 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 US GAAP. 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.

The Corporation's management, including the Corporation's President and Chief Executive Officer and the Executive Vice President, Chief Financial Officer, assessed the effectiveness of the Corporation's internal control over financial reporting as of December 31, 2019, 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, 2019, the Corporation's internal control over financial reporting was effective.

Deloitte LLP, an independent registered public accounting firm, has audited the Corporation's Audited Consolidated Financial Statements for the fiscal year ended December 31, 2019 filed as Exhibit 99.2 to this Form 40-F (the "Annual Financial Statements"), and has included its attestation report on management’s assessment of the Corporation’s internal control over financial reporting, which is found on page v of the Annual Financial Statements.

ATTESTATION REPORT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Deloitte LLP's attestation report on management’s assessment of the Corporation's internal control over financial reporting is found on page v of the Annual Financial Statements.

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

Management regularly reviews its system of internal control over financial reporting and makes changes to the Corporation's processes and systems to improve controls and increase efficiency, while ensuring that the Corporation maintains an effective internal control environment. Changes may include such activities as implementing new, more efficient systems, consolidating activities, and migrating processes.

During the year ended December 31, 2019, there have been no changes in the Corporation's internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, the Corporation's internal control over financial reporting.

NOTICES PURSUANT TO REGULATION BTR

The Corporation did not send any notices required by Rule 104 of Regulation BTR during the year ended December 31, 2019 concerning any equity security subject to a blackout period under Rule 101 of Regulation BTR.

IDENTIFICATION OF THE AUDIT COMMITTEE

The Corporation has a separately designated standing Audit Committee established in accordance with section 3(a)(58)(A) of the Exchange Act. The Audit Committee is composed of Tracey C. Ball (Chair), Lawrence T. Borgard, Maura J. Clark, Margarita K. Dilley, Julie A. Dobson, Douglas J. Haughey and Jo Mark Zurel, as described under "Audit Committee - Members" on page 33 of the Corporation's annual information form for the year ended December 31, 2019, which is filed as Exhibit 99.1 to this Form 40-F and incorporated by reference herein (the "AIF").

AUDIT COMMITTEE FINANCIAL EXPERT

The Board has determined that the Corporation has at least one "audit committee financial expert" (as defined in paragraph (8) of General Instruction B to Form 40-F) and that Tracey C. Ball, Maura J. Clark, Margarita K. Dilley and Jo Mark Zurel are the Corporation's "audit committee financial experts" serving on the Audit Committee of the Board. Each of the Audit Committee financial experts is "independent" under applicable listing standards.

PRINCIPAL ACCOUNTANT FEES AND SERVICES

Deloitte LLP served as the Corporation's independent public accountant for the fiscal years ended December 31, 2019 and 2018. For a description of the total amount billed to the Corporation by Deloitte LLP for services performed in the last two fiscal years by category of service (audit fees, audit-related fees, tax fees and all other fees), see "Audit Committee - External Auditor Service Fees" on page 36 of the AIF.

No audit-related fees, tax fees or other non-audit fees were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S‑X.

AUDIT COMMITTEE PRE‑APPROVAL POLICIES AND PROCEDURES

For a description of the pre-approval policies and procedures of the Corporation's Audit Committee, see "Audit Committee - Pre-Approval Policies and Procedures" on page 36 of the AIF.

CODE OF ETHICS

The Corporation has a "code of ethics" (as defined in paragraph (9) of General Instruction B to Form 40-F) that applies to its Chief Executive Officer, Chief Financial Officer, principal accounting officer, controller and persons performing similar functions. The Corporation's code of ethics is available on the Corporation's website at https://www.fortisinc.com/ or, without charge, upon request from the Corporate Secretary, Fortis Inc., Fortis Place, Suite 1100, 5 Springdale Street, St. John's, Newfoundland and Labrador, Canada A1E 0E4 (telephone (709) 737-2800).

During the fiscal year ended December 31, 2019, the Corporation amended its code of ethics and such amendments became effective as of January 1, 2020. The amended code of ethics, now entitled "code of conduct", has been significantly reformatted from a plain, legalistic document with numbered sections to a more user-friendly and engaging format which uses, among other things, simple language, color photographs and graphics, side notes, and question and answer sections addressing hypothetical issues that could arise in the workplace. The amended code of ethics is filed as an Exhibit 99.9, and the key amendments are described below:

•	Message from the President and Chief Executive Officer - The code includes an introductory message from the Corporation's President and Chief Executive Officer, which reinforces the key principles of honesty, integrity, and professionalism; encourages speaking up regarding things of concern; and notes the requirement that those subject to the code complete an annual certification.
•	Being Your Best - The code includes a list of general behaviors expected of all who are subject to the code, as well as the general principles that guide the actions and decisions of leaders in applying the code.
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•	Respect, Inclusion and Diversity - The code contains new and expanded treatment of respect, inclusion and diversity in the workplace, and references the Corporation’s Respectful Workplace Policy and new Inclusion and Diversity Commitment.
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•	Social Responsibility, the Environment and Sustainability - The code includes expanded discussion of the Corporation's commitment to social responsibility and sustainability.
•	Fitness for Duty - The code addresses an employee's responsibility regarding fitness for duty and refers to the Corporation's Drugs and Alcohol in the Workplace Policy.
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•	Federal Energy Regulatory Commission, or FERC - The code references the Corporation's FERC Compliance Manual, which reinforces the Corporation's expectation that its operating utilities strictly comply with all applicable regulatory obligations.
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•	Anti-Corruption - The code references the Corporation's Anti-Corruption Policy and Anti-Corruption Procedures which were adopted since the previous version of the code.
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•	Political Engagement and Lobbying - The code references the Corporation's revised Political Engagement Policy and related obligations regarding compliance with lobbying regulations in accordance with the Corporation's Anti-Corruption Policy.
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•	Records Management - The code includes a section on records management which references the Corporation's Records Management Policy and Records Retention Schedule.
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•	Where to Go for Help - The code references the new position of "Administrator" under the Corporation's Whistleblower Policy and reinforces the availability of reporting and issue resolution processes that exist under other specific-purpose policies, such as the Corporation's Respectful Workplace Policy.
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•	Other Policies and Related Materials - The code includes a summary list of all other referenced Corporation policies and related materials.
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During the fiscal year ended December 31, 2019, the Corporation has not granted a waiver from a provision of its code of ethics to its Chief Executive Officer, Chief Financial Officer, principal accounting officer, controller, or persons performing similar functions.

OFF‑BALANCE SHEET ARRANGEMENTS

Except for letters of credit outstanding of $114 million as at December 31, 2019 and certain unrecorded commitments disclosed under the heading "Liquidity and Capital Resources - Contractual Obligations" on page 20 of the Annual MD&A, the Corporation has not entered into any "off-balance sheet arrangements", as defined in General Instruction B(11) to Form 40-F, that have or are reasonably likely to have a current or future effect on the Corporation's financial condition, changes in financial condition, revenues, expenses, results of operations, liquidity, capital expenditures or capital resources that are material to investors.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

For tabular disclosure of the Corporation's contractual obligations, see page 20 of the Annual MD&A, under the heading "Liquidity and Capital Resources - Contractual Obligations".

COMPARISON OF NYSE CORPORATE GOVERNANCE RULES

The Corporation is subject to a variety of corporate governance guidelines and requirements enacted by the Toronto Stock Exchange (the "TSX"), the Canadian securities regulatory authorities, the New York Stock Exchange (the "NYSE") and the SEC. The Corporation is listed on the NYSE and, although the Corporation is not required to comply with most of the NYSE corporate governance requirements to which the Corporation would be subject if it were a U.S. corporation, the Corporation's governance practices differ from those required of U.S. domestic issuers in only the following respects. The NYSE rules for U.S. domestic issuers require shareholder approval of all equity compensation plans (as defined in the NYSE rules) regardless of whether new issuances, treasury shares or shares that the Corporation has purchased in the open market are used. The TSX rules require shareholder approval of share compensation arrangements involving new issuances of shares, and of certain amendments to such arrangements, but do not require such approval if the compensation arrangements involve only shares purchased in the open market. The NYSE rules for U.S. domestic issuers also require shareholder approval of certain transactions or series of related transactions that result in the issuance of common shares, or securities convertible into or exercisable for common shares, that have, or will have upon issuance, voting power equal to or in excess of 20% of the voting power outstanding prior to the transaction or if the issuance of common shares, or securities convertible into or exercisable for common shares, are, or will be upon issuance, equal to or in excess of 20% of the number of common shares outstanding prior to the transaction. The TSX rules require shareholder approval of acquisition transactions resulting in dilution in excess of 25%. The TSX also has broad general discretion to require shareholder approval in connection with any issuances of listed securities. The Corporation complies with the TSX rules described in this paragraph.

UNDERTAKING

The Corporation undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the SEC staff, and to furnish promptly, when requested to do so by the SEC staff, information relating to: the securities in relation to which the obligation to file an annual report on Form 40-F arises; or transactions in said securities.

DISCLOSURE PURSUANT TO SECTION 13(r) OF THE EXCHANGE ACT

In accordance with Section 13(r) of the Exchange Act, the Corporation is required to include certain disclosures in its periodic reports if it or any of its affiliates knowingly engaged in certain specified activities during the period covered by the report. Neither the Corporation nor its affiliates have knowingly engaged in any transaction or dealing reportable under Section 13(r) of the Exchange Act during the year ended December 31, 2019.

INCORPORATION BY REFERENCE

Fortis' Annual Report on Form 40-F (other than the section entitled "Credit Ratings" in Exhibit 99.1 to this Form 40-F) is incorporated by reference into Fortis' Registration Statements on Form S-8 (File No. 333-215777), Form F-3D (File No. 333-218032), Form S-8 (File No. 333-226663), Form F-10 (File No. 333-228593) and Form S-8 (File No. 333-236213).

EXHIBIT INDEX

Exhibit	Description
99.1	Annual Information Form of the Corporation dated February 12, 2020
99.2	Audited Consolidated Financial Statements for the fiscal year ended December 31, 2019
99.3	Management's Discussion and Analysis for the fiscal year ended December 31, 2019
99.4	Chief Executive Officer certification required by Rule 13a-14(a)
99.5	Chief Financial Officer certification required by Rule 13a-14(a)
99.6	Chief Executive Officer certification required by Rule 13a-14(b)
99.7	Chief Financial Officer certification required by Rule 13a-14(b)
99.8	Consent of Deloitte LLP
99.9	Code of Conduct of the Corporation, amended as of January 1, 2020
101.INS	XBRL Instance
101.SCH	XBRL Taxonomy Extension Schema
101.CAL	XBRL Taxonomy Extension Calculation Linkbase
101.DEF	XBRL Taxonomy Extension Definition Linkbase
101.LAB	XBRL Taxonomy Extension Label Linkbase
101.PRE	XBRL Taxonomy Extension Presentation Linkbase

SIGNATURES

Pursuant to the requirements of the Exchange Act, the Corporation certifies that it meets all of the requirements for filing on Form 40‑F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.

FORTIS INC.
/s/ Jocelyn H. Perry
Jocelyn H. Perry<br><br>Executive Vice President, Chief Financial Officer
Date: February 13, 2020

		Exhibit

Exhibit 99.1

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2019

February 12, 2020

ANNUAL INFORMATION FORM

For the year ended December 31, 2019

Dated February 12, 2020

TABLE OF CONTENTS
Forward-Looking Information	2	Sustainability	25
Glossary	3	Social and Environmental Policies	26
Corporate Structure	5	Sustainability Regulation and Environmental
Name and Incorporation	5	Contingencies	27
Inter-Corporate Relationships	5	Capital Structure and Dividends	27
General Development of the Business	6	Description of Capital Structure	27
Overview	6	Dividends and Distributions	28
Three-Year History	6	Debt Covenant Restrictions on Dividend Distributions	29
Outlook	7	Credit Ratings	29
Description of the Business	7	Directors and Officers	32
Regulated Utilities	9	Audit Committee	34
ITC	9	Members	34
UNS Energy	11	Education and Experience	34
Central Hudson	15	Pre-Approval Policies and Procedures	35
FortisBC Energy	16	External Auditor Service Fees	35
FortisAlberta	18	Transfer Agent and Registrar	35
FortisBC Electric	19	Interests of Experts	36
Other Electric	20	Additional Information	36
Non-Regulated	23
Energy Infrastructure	23	Exhibit A: Summary of Terms and Conditions of Authorized Securities	37
Corporate and Other	23
Human Resources	24	Exhibit B: Market for Securities	40
Legal Proceedings and Regulatory Actions	25	Exhibit C: Audit Committee Mandate	42
Risk Factors	25	Exhibit D: Material Contracts	50

Financial information in this AIF has been prepared in accordance with US GAAP and is presented in Canadian dollars ($) based, as applicable, on the following US-to-Canadian dollar exchange rates: (i) average of 1.33 and 1.30 for the years ended December 31, 2019 and 2018, respectively; (ii) 1.30 and 1.36 as at December 31, 2019 and 2018, respectively; and (iii) 1.32 for all forecast periods.

Except as otherwise expressly noted, the information in this AIF is given as of December 31, 2019.

ANNUAL INFORMATION FORM	1	December 31, 2019

FORWARD-LOOKING INFORMATION

Fortis includes forward-looking information in this AIF within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995 (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance, business prospects and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates, expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which includes, without limitation: forecast capital expenditures for the period 2020 to 2024; forecast rate base for 2022 and 2024; the expectation that long-term sustainable growth in rate base will support continuing growth in earnings and dividends; target average annual dividend growth through 2024; the expectation that UNS Energy has sufficient generating capacity, together with existing PPAs and expected generation plant additions, to satisfy the requirements of its customer base and meet future peak demand requirements; and the expectation that future increases in energy supply costs will increase Newfoundland Power's electricity rates.

Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: reasonable regulatory decisions and the expectation of regulatory stability; no material capital project or financing cost overruns; sufficient human resources to deliver service and execute the capital plan; the Board exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset; the continued ability to maintain the electricity and gas systems; no severe and prolonged downturn in economic conditions; sufficient liquidity and capital resources; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; the continued availability of natural gas, fuel, coal and electricity supply; continuation of power supply and capacity purchase contracts; no significant changes in government energy plans, environmental laws and regulations that could have a material negative impact; the ability to obtain and maintain licences and permits; retention of existing service areas; no significant changes in tax laws and the continued tax deferred treatment of earnings from the Corporation's foreign operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with Indigenous Peoples; and favourable labour relations.

Forward‑looking information involves significant risks, uncertainties and assumptions. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. For additional information with respect to certain of these risks or factors, reference should be made to the MD&A under the heading "Business Risks" and to the continuous disclosure materials filed from time to time by Fortis with Canadian securities regulatory authorities and the Securities and Exchange Commission.

All forward-looking information in this AIF is given as of the date of this AIF and the Corporation disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.

ANNUAL INFORMATION FORM	2	December 31, 2019

GLOSSARY

Certain terms used in this 2019 Annual Information Form are defined below:

2019 Annual Information Form or AIF: this annual information form of the Corporation in respect of the year ended December 31, 2019

ACGS: Aitken Creek Gas Storage ULC

Aitken Creek: Aitken Creek natural gas storage facility

Algoma Power: Algoma Power Inc.

APS: Arizona Public Service Company

AUC: Alberta Utilities Commission

BC Hydro: BC Hydro and Power Authority

BCUC: British Columbia Utilities Commission

BECOL: Belize Electric Company Limited

Belize Electricity: Belize Electricity Limited

Board: Board of Directors of the Corporation

Canadian Niagara Power: Canadian Niagara Power Inc.

CUPE: Canadian Union of Public Employees

Caribbean Utilities: Caribbean Utilities Company, Ltd.

CBT: Columbia Basin Trust

Central Hudson: Central Hudson Gas & Electric Corporation

CMS: Consumers Energy Company

Cornwall Electric: Cornwall Street Railway, Light and Power Company, Limited

Corporation: Fortis Inc.

CPA: Canal Plant Agreement

CPC: Columbia Power Corporation

DBRS Morningstar: DBRS Limited

DTE: DTE Electric Company

EDGAR: SEC's system for Electronic Data Gathering, Analysis and Retrieval available at www.sec.gov

FERC: Federal Energy Regulatory Commission

FHI: FortisBC Holdings Inc.

Financial Statements: the Corporation's Audited Consolidated Financial Statements in respect of the year ended December 31, 2019

Fitch: Fitch Ratings Inc.

Fortis: Fortis Inc.

FortisAlberta: FortisAlberta Inc.

FortisBC Electric: collectively, the operations of FortisBC Inc. and its parent company, FortisBC Pacific Holdings Inc.

FortisBC Energy: FortisBC Energy Inc.

FortisOntario: FortisOntario Inc.

FortisTCI: collectively, FortisTCI Limited and Turks and Caicos Utilities Limited

FortisUS: FortisUS Inc.

FortisUS Holdings: FortisUS Holdings Nova Scotia Limited

FortisWest: FortisWest Inc.

GHG: greenhouse gas

GIC: GIC Private Limited

GSMIP: Gas Supply Mitigation Incentive Plan of FortisBC Energy

IBEW: International Brotherhood of Electrical Workers

IESO: Independent Electricity System Operator of Ontario

IPL: Interstate Power and Light Company

ITC: ITC Holdings together with all of its subsidiaries

ITC Great Plains: ITC Great Plains, LLC

ITC Holdings: ITC Holdings Corp.

ITC Interconnection: ITC Interconnection LLC

ANNUAL INFORMATION FORM	3	December 31, 2019

ITC Investment Holdings: ITC Investment Holdings Inc.

ITC Midwest: ITC Midwest LLC

ITC's MISO Regulated Operating Subsidiaries: collectively ITCTransmission, METC and ITC Midwest

ITC's Regulated Operating Subsidiaries: collectively, ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection

ITCTransmission: International Transmission Company

LNG: liquefied natural gas

Maritime Electric: Maritime Electric Company, Limited

MD&A: the Corporation's Management Discussion and Analysis in respect of the year ended December 31, 2019

METC: Michigan Electric Transmission Company

MISO: Midcontinent Independent System Operator, Inc.

Moody's: Moody's Investors Service, Inc.

MoveUP: Movement of United Professionals

NB Power: New Brunswick Power Corporation

Newfoundland Power: Newfoundland Power Inc.

NL Hydro: Newfoundland and Labrador Hydro Corporation

NYPSC: New York Public Service Commission

NYSE: New York Stock Exchange

PEI: the province of Prince Edward Island, Canada

PNM: Public Service Company of New Mexico

PPA: power purchase agreement

PUB: Newfoundland and Labrador Board of Commissioners of Public Utilities

PWU: Power Workers' Union

ROE: return on common equity

S&P: Standard & Poor's Financial Services LLC

SEC: United States Securities and Exchange Commission

SEDAR: the System for Electronic Document Analysis and Retrieval of the Canadian Securities Administrators available at www.sedar.com

SPP: Southwest Power Pool, Inc.

SRP: Salt River Project Agricultural Improvement and Power District

T&D: transmission and distribution

TEP: Tucson Electric Power Company

TransCanada: TransCanada Pipelines Limited

TSX: Toronto Stock Exchange

UNS Electric and UNSE: UNS Electric, Inc.

UNS Energy: UNS Energy Corporation

UNS Gas: UNS Gas, Inc.

US: United States

US GAAP: accounting principles general accepted in the US

UUWA: United Utility Workers' Association of Canada

Waneta Expansion: 335-MW Waneta Expansion hydroelectric generating facility

Wataynikaneyap Partnership: Wataynikaneyap Power Limited Partnership

Measurements:

GW	Gigawatt(s)
GWh	Gigawatt hour(s)
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km	Kilometre(s)
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MW	Megawatt(s)
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TJ	Terajoule(s)
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PJ	Petajoule(s)
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Conversions:

1 litre = 0.22 imperial gallons

1 kilometre = 0.62 miles

Conversion using the above factors on rounded numbers appearing in this AIF may produce small differences from reported amounts as a result.

ANNUAL INFORMATION FORM	4	December 31, 2019

CORPORATE STRUCTURE

Name and Incorporation

Fortis Inc. is a holding company that was incorporated as 81800 Canada Ltd. under the Canada Business Corporations Act on June 28, 1977 and continued under the Corporations Act (Newfoundland and Labrador) on August 28, 1987. The corporate head office and registered office of Fortis is located at Fortis Place, Suite 1100, 5 Springdale Street, P.O. Box 8837, St. John's, Newfoundland and Labrador, Canada, A1B 3T2.

The articles of continuance of the Corporation were amended to: (i) change its name to Fortis on October 13, 1987; (ii) set out the rights, privileges, restrictions and conditions attached to the common shares on October 15, 1987; (iii) designate 2,000,000 First Preference Shares, Series A on September 11, 1990; (iv) replace the class rights, privileges, restrictions and conditions attaching to the First Preference Shares and the Second Preference Shares on July 22, 1991; (v) designate 2,000,000 First Preference Shares, Series B on December 13, 1995; (vi) designate 5,000,000 First Preference Shares, Series C on May 27, 2003; (vii) designate 8,000,000 First Preference Shares, Series D and First Preference Shares, Series E on January 23, 2004; (viii) amend the redemption provisions attaching to the First Preference Shares, Series D on July 15, 2005; (ix) designate 5,000,000 First Preference Shares, Series F on September 22, 2006; (x) designate 9,200,000 First Preference Shares, Series G on May 20, 2008; (xi) designate 10,000,000 First Preference Shares, Series H and 10,000,000 First Preference Shares, Series I on January 20, 2010; (xii) designate 8,000,000 First Preference Shares, Series J on November 8, 2012; (xiii) designate 12,000,000 First Preference Shares, Series K and 12,000,000 First Preference Shares, Series L on July 11, 2013; and; (xiv) designate 24,000,000 First Preference Shares, Series M and 24,000,000 First Preference Shares, Series N on September 16, 2014.

Inter-Corporate Relationships

The following table lists the principal subsidiaries of the Corporation, their jurisdictions of incorporation and the percentage of votes attaching to voting securities held directly or indirectly by the Corporation as at February 12, 2020. The principal subsidiaries together comprise approximately 89% of the Corporation's consolidated assets as at December 31, 2019 and approximately 85% of the Corporation's 2019 consolidated revenue. This table excludes certain subsidiaries, the assets and revenues of which did not individually exceed 10%, or in the aggregate exceed 20%, of the total consolidated assets or total consolidated revenues of the Corporation as at December 31, 2019.

Subsidiary	Jurisdiction of Incorporation	Votes attaching to voting securities beneficially owned, controlled or directed by the Corporation (%)
ITC^(1)^	Michigan, United States	80.1
UNS Energy ^(2)^	Arizona, United States	100
Central Hudson ^(3)^	New York, United States	100
FortisBC Energy ^(4)^	British Columbia, Canada	100
FortisAlberta ^(5)^	Alberta, Canada	100
Newfoundland Power ^(6)^	Newfoundland and Labrador, Canada	100
^(1)^	ITC Holdings, a Michigan corporation, owns all of the shares of ITC Great Plains, ITC Interconnection, ITC Midwest, ITCTransmission and METC. ITC Investment Holdings, a Michigan corporation, owns all of the shares of ITC Holdings. FortisUS, a Delaware corporation, owns 80.1% of the voting securities of ITC Investment Holdings. FortisUS Holdings, a Canadian corporation, owns all of the shares of FortisUS. Fortis owns all of the shares of FortisUS Holdings. 19.9% of the voting securities of ITC Investment Holdings are owned by an affiliate of GIC.
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^(2)^	UNS Energy owns all of the shares of TEP, UNS Electric and UNS Gas. FortisUS owns all of the shares of UNS Energy.
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^(3)^	CH Energy Group, Inc., a New York corporation, owns all of the shares of Central Hudson. FortisUS owns all of the shares of CH Energy Group, Inc.
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^(4)^	FHI, a British Columbia corporation, owns all of the shares of FortisBC Energy. Fortis owns all of the shares of FHI.
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^(5)^	FortisAlberta Holdings Inc., an Alberta corporation, owns all of the shares of FortisAlberta. FortisWest, a Canadian corporation, owns all of the shares of FortisAlberta Holdings Inc. Fortis owns all of the shares of FortisWest.
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^(6)^	Fortis owns all of the shares of Newfoundland Power.
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ANNUAL INFORMATION FORM	5	December 31, 2019
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GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Fortis is a well-diversified leader in the North American regulated electric and gas utility industry, with revenue of $8.8 billion and total assets of $53.4 billion as at December 31, 2019.

Regulated utilities account for 99% of the Corporation's assets. The Corporation's 9,000 employees serve 3.3 million utility customers in five Canadian provinces, nine US states and three Caribbean countries. As at December 31, 2019, 66% of the Corporation's assets were located outside Canada and 60% of 2019 revenue was derived from foreign operations.

Three-Year History

Over the past three years, Fortis has experienced significant growth in its business operations. Total assets have increased from $47.9 billion as at December 31, 2016 to $53.4 billion as at December 31, 2019. The Corporation's shareholders' equity has also grown from $16.5 billion as at December 31, 2016 to $20.1 billion as at December 31, 2019. Net earnings attributable to common equity shareholders have increased significantly from $963 million in 2017 to $1,655 million in 2019.

The growth in business operations reflects the Corporation's profitable organic growth strategy for its principal regulated utilities.

In 2017 the Corporation delivered strong operational and financial performance, driven by contributions from its US utilities, and surpassed $1 billion in adjusted net earnings for the first time. This marked the culmination of a successful five-year period in which Fortis more than doubled its size with the completion of three successful utility acquisitions in the US.

In 2018 the Corporation deployed capital expenditures of $3.2 billion at its utilities and announced an ambitious utility capital plan of $17.3 billion for the period 2019 to 2023, an increase of 20% over the prior year's plan. The increase in annual earnings for 2018 was driven by growth at both the regulated and non-regulated businesses, as well as lower income tax expense primarily related to a one-time expense in 2017 associated with US tax reform, along with the positive tax impacts of electing to file a consolidated state tax return and designating assets as "held for sale" in 2018.

In January 2019 Fortis announced that it entered into a definitive agreement with CBT and CPC to sell its 51% interest in the Waneta Expansion for approximately $1 billion. The transaction closed in April 2019. The sale of the Corporation's interest in the Waneta Expansion completed the asset sale portion of the Corporation's capital funding strategy. In 2019 Fortis announced its five-year capital plan of $18.8 billion for the period 2020 to 2024.

Net earnings attributable to common equity shareholders for 2019 were $1,655 million compared to $1,100 million for 2018. The increase reflected a one-time after-tax gain on sale of the Waneta Expansion of $484 million and a one-time after-tax favourable adjustment of $83 million associated with prior period impacts of a regulatory decision reducing ITC's base ROE.

The Corporation's consolidated capital expenditures for 2019 were $3.8 billion. Over the past three years, including 2019, consolidated capital expenditures totalled $10.1 billion. Organic asset growth has been driven by the capital expenditures at the Corporation's regulated utilities.

ANNUAL INFORMATION FORM	6	December 31, 2019

Outlook

Over the long term, Fortis is well positioned to enhance shareholder value through the execution of its capital plan, the balance and strength of its diversified portfolio of utility businesses, and growth opportunities within its service territories.

The Corporation's $18.8 billion five-year capital plan is expected to increase rate base from $28.0 billion in 2019 to $34.5 billion by 2022 and $38.4 billion by 2024, translating into three- and five-year compound average growth rates of 7.2% and 6.5%, respectively. The five-year capital plan reflects the continuation of key industry trends including grid modernization and the delivery of cleaner energy. Beyond the base capital plan, Fortis continues to pursue additional energy infrastructure opportunities. Key opportunities not yet included in the five-year capital plan include: further expansion of LNG infrastructure in British Columbia; the fully permitted, cross-border, Lake Erie connector electric transmission project in Ontario; and the acceleration of cleaner energy goals in Arizona.

Fortis expects long-term growth in rate base to support continuing growth in earnings and dividends. Fortis is targeting average annual dividend growth of approximately 6% through 2024. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence.

DESCRIPTION OF THE BUSINESS

Fortis is principally an energy delivery company, with only 7% of its assets related to generation. The business is characterized by low-risk, stable and predictable earnings and cash flows.

The Corporation's regulated utility businesses are: ITC (electric transmission - Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma); UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas distribution - New York); FortisBC Energy (natural gas distribution - British Columbia); FortisBC Electric (integrated electric - British Columbia); FortisAlberta (electric distribution - Alberta); Newfoundland Power (integrated electric - Newfoundland and Labrador); Maritime Electric (integrated electric - Prince Edward Island); FortisOntario (integrated electric - Ontario); Caribbean Utilities (integrated electric - Grand Cayman); and FortisTCI (integrated electric - Turks and Caicos Islands). Fortis also holds equity investments in the Wataynikaneyap Partnership (electric transmission - Ontario) and Belize Electricity (integrated electric - Belize).

Non-regulated energy infrastructure is comprised of Aitken Creek (natural gas storage facility - British Columbia) and BECOL (three hydroelectric generation facilities with a combined capacity of 51 MW - Belize). In April 2019 Fortis sold its 51% ownership interest in long-term contracted generation assets in British Columbia, the Waneta Expansion.

Fortis has a unique operating model with a small head office in St. John's, Newfoundland and Labrador and business units that operate on a substantially autonomous basis. Each utility has its own management team and most have oversight by a board of directors having a majority of independent members. Given that regulatory oversight is usually state or provincially based, Fortis believes this model provides superior transparency, best serves the interests of customers and positions the Corporation well for future investment opportunities.

Fortis strives to provide safe, reliable and cost-effective energy service to customers using sustainable practices while delivering long-term profitable growth to shareholders. Management is focused on achieving growth through the execution of the consolidated capital plan and the pursuit of additional investment opportunities within and proximate to existing service territories.

ANNUAL INFORMATION FORM	7	December 31, 2019

Competition

Most of the Corporation's regulated utilities operate as the sole supplier of electricity and/or gas within their respective service territories. Competition in the regulated electric business is primarily from alternative energy sources and on-site generation by industrial customers. The Corporation faces competition in its transmission business which may restrict its ability to grow this business outside of its established service territories.

At the Corporation's regulated gas utilities, natural gas primarily competes with electricity for space and hot water heating load. In addition to other price comparisons, upfront capital cost differences between electric and natural gas equipment for hot water and space heating applications continue to present challenges for the competitiveness of natural gas on a fully-costed basis.

Seasonality

As the Corporation's subsidiaries operate in various jurisdictions throughout North America, seasonality impacts each utility differently. Most of the annual earnings of the Corporation's gas utilities are realized in the first and fourth quarters due to space‑heating requirements in colder weather. Earnings for electric utilities in the US are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment in the summer.

Summary of Operations

The following table summarizes the Corporation's operations and the sections that follow describe the operations of the Corporation's reportable segments.

		Customers	Peak<br><br>Demand ^(1)^		Electric T&D Lines (km) ^(2)^	Gas T&D Lines (km)	Generating Capacity (MW)	Revenue<br><br>($ millions)	GWh Sales	Gas Volumes (PJ)	Employees
Regulated Utilities
ITC		—	22,815	MW	25,500	—	—	1,761	—	—	707
UNS Energy		686,000	3,179<br><br>118	MW<br><br>TJ	22,500	5,000	3,143	2,212	18,354	16	2,103
Central Hudson		380,000	1,109<br><br>148	MW<br><br>TJ	15,100	2,350	65	917	4,963	22	1,065
FortisBC Energy		1,041,000	1,352	TJ	—	49,500	—	1,331	—	227	1,873
FortisAlberta		568,000	2,642	MW	90,800	—	—	598	16,887	—	1,111
FortisBC Electric		179,000	696	MW	7,300	—	225	418	3,326	—	538
Other Electric
	Newfoundland Power	269,000	1,458	MW	12,500	—	143	682	5,847	—	641
	Maritime Electric	82,000	276	MW	6,200	—	140	211	1,287	—	181
	FortisOntario	66,000	255	MW	3,500	—	5	210	1,313	—	211
	Caribbean Utilities	31,000	106	MW	800	—	161	274	668	—	248
	FortisTCI	15,000	43	MW	650	—	91	90	251	—	172
Non-Regulated
Energy Infrastructure ^(3)^		—	—		—	—	51	82	144	—	69
Corporate and Other		—	—		—	—	—	—	—	—	51
Total		3,317,000	32,579 1,618	MW<br><br>TJ	184,850	56,850	4,023	8,786	53,040	265	8,970
^(1)^	Electric (MW) or gas (TJ)
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^(2)^	Circuit km
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^(3)^	The Corporation sold its 51% controlling ownership interest in the 335-MW Waneta Expansion in 2019.
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ANNUAL INFORMATION FORM	8	December 31, 2019
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Regulated Utilities

ITC

ITC's business consists mainly of the electric transmission operations of ITC's Regulated Operating Subsidiaries. Through ITC's Regulated Operating Subsidiaries, it owns and operates high-voltage electric transmission systems in Michigan's Lower Peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma that transmit electricity from generating stations to local distribution facilities connected to ITC's transmission systems. ITC's business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to ITC's transmission system. ITC owns and operates more than 25,000 circuit km of transmission lines.

ITC's Regulated Operating Subsidiaries earn revenues from the use of their transmission systems by customers, including investor-owned utilities, municipalities, cooperatives, power marketers and alternative energy suppliers. As independent transmission companies, ITC's Regulated Operating Subsidiaries are subject to rate regulation only by FERC. The rates charged are established using cost-based formula rates.

ITC's principal transmission service customers are DTE, CMS and IPL. One or more of these customers together have consistently represented a significant percentage of ITC's operating revenue. Nearly all of ITC's revenues are from transmission customers in the US.

Market and Sales

Revenues

Revenue was $1,761 million in 2019, compared to $1,504 million in 2018.

ITC derives nearly all of its revenues from transmission, scheduling, control and dispatch services and other related services to DTE, CMS, IPL and other entities, such as alternative energy suppliers, power marketers and other wholesale customers, as well as from transaction-based capacity reservations on ITC's transmission systems. MISO and SPP are responsible for billing and collecting the majority of ITC's transmission service revenues. As the billing agent for ITC's MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP, respectively, collect fees for the use of ITC's transmission systems, invoicing customers on a monthly basis.

The following table compares the composition of ITC's 2019 and 2018 revenue by customer class.

	Revenue (%)
	2019	2018
Network revenues	63.0	66.7
Regional cost-sharing revenues	27.9	28.9
Point-to-point	1.0	1.2
Scheduling, control and dispatch	1.3	1.3
Other	1.6	1.8
Recognition of ROE complaint liabilities ^(1)^	5.2	0.1
Total	100.0	100.0
^(1)^	Adjustments have been made to the refund liability recorded related to the complaint proceedings on the MISO base rate of return on equity, which resulted in net increases in operating revenues for the periods presented.
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Network revenues are generated from network customers for their use of ITC's electric transmission systems and are based on the actual revenue requirements as a result of ITC's accounting under its cost-based formula rates that contain a true-up mechanism.

Network revenues at ITC Great Plains include the annual revenue requirements specific to projects that are charged exclusively within one pricing zone within SPP or are classified as direct assigned network upgrades under the SPP tariff and contain a true-up mechanism.

ANNUAL INFORMATION FORM	9	December 31, 2019

Regional cost-sharing revenues are generated from transmission customers for their use of ITC's MISO Regulated Operating Subsidiaries' network upgrade projects that are eligible for regional cost-sharing under provisions of the MISO tariff, including multi-value projects such as ITCTransmission's Thumb Loop Project. Regional cost-sharing revenues also include revenues collected by transmission customers from other regional transmission organizations outside of MISO to allocate costs of certain transmission plant investments. Additionally, certain projects at ITC Great Plains are eligible for cost recovery through a region-wide charge under provisions of the SPP tariff. A portion of regional cost-sharing revenues is credited to regional or network customers when calculating the net revenue requirement under ITC's cost-based formula rates.

Point-to-point revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO and SPP tariffs. Point-to-point revenues are treated as a revenue credit to network or regional customers and are a reduction to the gross revenue requirement when calculating the net revenue requirement under ITC's cost-based formula rates.

Scheduling, control and dispatch revenues are allocated by MISO to ITC's MISO Regulated Operating Subsidiaries as compensation for the services performed in operating the transmission system. Such services include monitoring of reliability data, current and next-day analysis, implementation of emergency procedures and outage coordination and switching.

Other revenues consist of rental revenues, easement revenues, revenues relating to use of jointly-owned assets under ITC's transmission ownership and operating agreements and amounts from providing ancillary services to customers. The majority of other revenues are treated as a credit when calculating the net revenue requirement under ITC's cost-based formula rates.

Contracts

ITCTransmission

DTE operates the electric distribution system to which ITCTransmission's transmission system connects. A set of three operating contracts sets forth the terms and conditions related to DTE's and ITCTransmission's ongoing working relationship. These contracts include:

Master Operating Agreement - governs the primary day-to-day operational responsibilities and identifies the control area coordination services that ITCTransmission is obligated to provide to DTE and certain generation-based support services that DTE is required to provide to ITCTransmission.

Generator Interconnection and Operation Agreement - established, re-established and maintains the interconnection of DTE's electricity generating assets with ITCTransmission's transmission system.

Coordination and Interconnection Agreement - governs the rights, obligations and responsibilities regarding, among other things, the operation and interconnection of DTE's distribution system and ITCTransmission's transmission system, and the construction of new facilities or modification of existing facilities. Additionally, this agreement allocates costs for operation of supervisory, communications and metering equipment.

METC

CMS operates the electric distribution system to which METC's transmission system connects. METC is a party to a number of operating contracts with CMS that govern the operations and maintenance of its transmission system. These contracts include:

Amended and Restated Easement Agreement - CMS provides METC with an easement to the land on which a majority of METC's transmission towers, poles, lines and other transmission facilities, used to transmit electricity for CMS and others, are located. METC pays CMS a nominal annual rent for the easement and also pays for any rentals, property taxes and other fees related to the property covered by the agreement.

ANNUAL INFORMATION FORM	10	December 31, 2019

Amended and Restated Operating Agreement - METC is responsible for maintaining and operating its transmission system, providing CMS with information and access to its transmission system and related books and records, administering and performing the duties of control area operator (that is, the entity exercising operational control over the transmission system) and, if requested by CMS, building connection facilities necessary to permit interaction with new distribution facilities built by CMS.

Amended and Restated Purchase and Sale Agreement for Ancillary Services - Since METC does not own any generating facilities, it must procure ancillary services from third-party suppliers, such as CMS. Currently, under this agreement, METC pays CMS for providing certain generation-based services necessary to support the reliable operation of the bulk power grid, such as voltage support and generation capability and capacity to balance loads and generation.

Amended and Restated Distribution-Transmission Interconnection Agreement - provides for the interconnection of CMS's distribution system with METC's transmission system and defines the continuing rights, responsibilities and obligations of the parties with respect to the use of certain of their own and the other parties' property, assets and facilities.

Amended and Restated Generator Interconnection Agreement - specifies the terms and conditions under which CMS and METC maintain the interconnection of CMS's generation resources and METC's transmission assets.

ITC Midwest

IPL operates the electric distribution system to which ITC Midwest's transmission system connects. ITC Midwest is a party to a number of operating contracts with IPL that govern the operations and maintenance of ITC Midwest's transmission system. These contracts include:

Distribution-Transmission Interconnection Agreement - governs the rights, responsibilities and obligations of ITC Midwest and IPL, with respect to the use of certain of their own and the other party's property, assets and facilities and the construction of new facilities or modification of existing facilities.

Large Generator Interconnection Agreement - ITC Midwest, IPL and MISO entered into this agreement to establish, re-establish and maintain the direct electricity interconnection of IPL's electricity generating assets with ITC Midwest's transmission system.

UNS Energy

UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona. It is engaged through its subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving approximately 686,000 electricity and gas customers. UNS Energy is primarily comprised of three wholly-owned regulated utilities: TEP, UNS Electric and UNS Gas.

TEP, UNS Energy's largest operating subsidiary, is a vertically integrated regulated electric utility that generates, transmits and distributes electricity. TEP serves approximately 429,000 retail customers in a territory comprising approximately 2,991 square km in southeastern Arizona, including the greater Tucson metropolitan area in Pima County, as well as parts of Cochise County. TEP's service area covers a population of over one million people. TEP also sells wholesale electricity to other entities in the western US.

UNS Electric is a vertically integrated regulated electric utility that generates, transmits and distributes electricity to approximately 97,000 retail customers in Arizona's Mohave and Santa Cruz counties.

TEP and UNS Electric currently own generation resources with an aggregate capacity of 3,143 MW, including 59 MW of solar capacity. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. TEP and UNS Electric have sufficient generation capacity that, together with existing PPAs and expected generation plant additions, are expected to satisfy the requirements of its customer base and meet future peak demand requirements. As at December 31, 2019, approximately 34% of the generating capacity was fuelled by coal.

UNS Gas is a regulated gas distribution utility that serves approximately 160,000 retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties.

ANNUAL INFORMATION FORM	11	December 31, 2019

Market and Sales

UNS Energy's electricity sales were 18,354 GWh in 2019, compared to 17,406 GWh in 2018. Gas volumes were 16 PJ in 2019 compared to 13 PJ in 2018. Revenue was $2,212 million in 2019, compared to $2,202 million in 2018.

The following table provides the composition of UNS Energy's 2019 and 2018 revenue, electricity sales, and gas volumes by customer class.

	Revenue (%)		GWh Sales (%)		PJ Volumes (%)
	2019	2018	2019	2018	2019	2018
Residential	36.5	37.6	25.0	26.9	57.9	58.8
Commercial	21.2	22.1	15.1	16.2	23.4	24.5
Industrial	13.8	14.4	16.6	17.7	2.0	2.0
Other ^(1)^	28.5	25.9	43.3	39.2	16.7	14.7
Total	100.0	100.0	100.0	100.0	100.0	100.0
^(1)^	Includes electricity sales and gas volumes to other entities for resale and revenue from sources other than from the sale of electricity and gas
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Power Supply

TEP meets the electricity supply requirements of its retail and wholesale customers with its owned electrical generating capacity of 2,841 MW and its T&D system consisting of approximately 16,000 km of line. In 2019 TEP met a peak demand of 2,726 MW, which includes firm sales to wholesale customers. TEP is a member of a regional reserve-sharing organization and has reliability and power sharing relationships with other utilities.

TEP's generating capacity is set forth in the following table.

Generation Source	Unit No.	Location	Date in <br>Service	Total Capacity (MW)	Operating Agent	TEP's Share (%)	TEP's Share (MW)
Coal
Springerville Station	1	Springerville, AZ	1985	387	TEP	100.0	387
Springerville Station ^(1)^	2	Springerville, AZ	1990	406	TEP	100.0	406
San Juan Station	1	Farmington, NM	1976	340	PNM	50.0	170
Four Corners Station	4	Farmington, NM	1969	785	APS	7.0	55
Four Corners Station	5	Farmington, NM	1970	785	APS	7.0	55
Natural Gas
Gila River Power Station ^(2)^	2	Gila Bend, AZ	2003	550	SRP	100.0	550
Gila River Power Station	3	Gila Bend, AZ	2003	550	SRP	75.0	413
Luna Generating Station	1	Deming, NM	2006	555	PNM	33.3	185
Sundt Station	3	Tucson, AZ	1962	104	TEP	100.0	104
Sundt Station	4	Tucson, AZ	1967	156	TEP	100.0	156
Sundt Internal Combustion Turbines		Tucson, AZ	1972-1973	50	TEP	100.0	50
Sundt Reciprocating Internal Combustion Engine	6-10	Tucson, AZ	2019	94	TEP	100.0	94
DeMoss Petrie		Tucson, AZ	2001	75	TEP	100.0	75
North Loop		Tucson, AZ	2001	94	TEP	100.0	94
Solar
Utility-Scale Renewables		Various	2002-2017	47	TEP	100.0	47
Total Capacity ^(3)^							2,841
^(1)^	Springerville Generating Station Unit 2 is owned by San Carlos Resources Inc., a wholly owned subsidiary of TEP.
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^(2)^	TEP exercised its option to purchase Gila River Unit 2 in December 2019. The purchase option was part of TEP's tolling PPA which had been in effect since 2017.
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^(3)^	In November 2019, Navajo Generating Station was removed from service. TEP held a 7.5% share in Units 1, 2 and 3 (total nominal capacity of 168 MW). In December 2019, H. Wilson Sundt Generating Station Units 1 and 2 (total nominal capacity of 162 MW) were removed from service.
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ANNUAL INFORMATION FORM	12	December 31, 2019
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UNS Electric meets the electricity supply requirements of its retail customers through a mix of its own generation and PPAs. UNS Electric owns and operates several gas and diesel‑fuelled generating plants, with a collective electrical generation capacity of 301 MW. In 2019 UNS Electric met a peak demand of 453 MW by utilizing its generation capacity and purchasing power on the wholesale market.

UNS Electric's generating capacity is set forth in the following table.

Generation Source	Unit No.	Location	Date In<br><br>Service	Resource Type	Total Capacity (MW)	Operating Agent	UNSE's Share (%)	UNSE's Share (MW)
Black Mountain	1	Kingman, AZ	2011	Gas	45	UNSE	100.0	45
Black Mountain	2	Kingman, AZ	2011	Gas	45	UNSE	100.0	45
Valencia	1	Nogales, AZ	1989	Gas/Oil	14	UNSE	100.0	14
Valencia	2	Nogales, AZ	1989	Gas/Oil	14	UNSE	100.0	14
Valencia	3	Nogales, AZ	1989	Gas/Oil	14	UNSE	100.0	14
Valencia	4	Nogales, AZ	2006	Gas/Oil	21	UNSE	100.0	21
Gila River Power Station	3	Gila Bend, AZ	2003	Gas	550	SRP	25.0	137
Utility-Scale Renewables		Various	2011<br><br>-2017	Solar	11	UNSE	100.0	11
Total Capacity								301

Owned Utility-Scale Renewable Resources

TEP owns 47 MW of photovoltaic solar generation capacity as set forth in the following table.

Generation Source	Location	Date/Projected Date In Service	In Service Capacity (MW)	Developing Capacity (MW)
Solar
Fort Huachuca Phase I & II ^(1)^	Sierra Vista, AZ	2014-2017	18	—
Springerville	Springerville, AZ	2004-2014	14	—
UASTP Phase I & II ^(2)^	Tucson, AZ	2010-2011	6	—
Sundt Areva Solar Thermal	Tucson, AZ	2014	5	—
Solon Prairie Fire ^(2)^	Tucson, AZ	2012	4	—
Raptor Ridge	Tucson, AZ	2021	—	10
Wind
Oso Grande Wind Project	Chaves Country, NM	2020	—	250
Total Capacity			47	260
^(1)^	TEP has a 30-year easement agreement to facilitate operations on behalf of the US Department of the Army.
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^(2)^	The University of Arizona Science and Technology Park I & II and Solon Prairie Fire are located on properties held under land easements and leases.
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UNS Electric owns 11 MW of photovoltaic solar generation capacity as set forth in the following table.

Generation Source	Location	Date/Projected Date In Service	Resource Type	In Service Capacity (MW)
Rio Rico	Rio Rico, AZ	2014	Solar	6
Jacobson	Kingman, AZ	2017	Solar	4
La Senita	Kingman, AZ	2011	Solar	1
Total Owned Solar Capacity				11
ANNUAL INFORMATION FORM	13	December 31, 2019
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Renewable Power Purchase Agreements

TEP has renewable PPAs for 156 MW from solar resources and 80 MW from wind resources as presented in the following table. The solar PPAs contain options that allow TEP to purchase all or part of the related project at a future date.

Generation Source	Location	Date/Projected Date In Service	In Service Capacity (MW)	Under Development Capacity (MW)
Solar
Red Horse	Willcox, AZ	2015	41	—
Avalon I	Sahuarita, AZ	2014	29	—
Avra Valley	Marana, AZ	2012	25	—
Picture Rocks	Marana, AZ	2012	20	—
Avalon II	Sahuarita, AZ	2016	16	—
Valencia	Tucson, AZ	2013	10	—
E.On Tech Park	Tucson, AZ	2012	5	—
Gato Montes	Tucson, AZ	2012	5	—
Small PPAs, Solar (<5MW)	Various	Various	5	—
Wilmot Solar	Sahuarita, AZ	2020	—	100
Wind
Macho Springs	Deming, NM	2011	50	—
Red Horse Wind	Willcox, AZ	2015	30	—
Borderlands Wind	Catron County, NM	2021	—	99
Total Capacity			236	199

UNS Electric has renewable PPAs for 83 MW from solar resources and 10 MW from wind resources as set forth in the following table.

Generation Source	Location	Date/Projected Date In Service	Resource Type	In Service Capacity (MW)
GrayHawk Solar	Kingman, AZ	2018	Solar	46
Red Horse Solar	Willcox, AZ	2016	Solar	30
Kingman Wind Farm	Kingman, AZ	2011	Wind	10
Black Mountain Solar	Kingman, AZ	2012	Solar	7
Total PPA Renewable Capacity				93

Gas Purchases

TEP and UNS Gas directly manage their gas supply and transportation contracts. The price for gas varies based on market conditions, which include weather, supply balance, economic growth rates, and other factors. TEP and UNS Gas hedge their gas supply prices by entering into fixed-price forward contracts, collars, and financial swaps from time to time, up to three years in advance, with a view to hedging at least 70-90% of expected monthly energy volumes prior to the beginning of each month.

ANNUAL INFORMATION FORM	14	December 31, 2019

The following table provides information on the natural gas transportation agreements that deliver natural gas to the generation stations.

Station	Natural Gas Transportation Counterparty	Contract Expiration Date(s)
Gila	Transwestern Pipeline Co./El Paso Natural Gas Company, LLC	2022-2040
Luna	El Paso Natural Gas Company, LLC	2022
Sundt/RICE	El Paso Natural Gas Company, LLC	2023-2040
DeMoss Petrie	Southwest Gas Corporation	Retail Tariff
North Loop	Southwest Gas Corporation	Retail Tariff

Central Hudson

Central Hudson is a regulated electric and gas T&D utility serving approximately 300,000 electricity customers and 80,000 natural gas customers in portions of New York State's Mid-Hudson River Valley.

Central Hudson serves a territory comprising approximately 6,700 square km in the Hudson Valley. Electric service is available throughout the territory, and natural gas service is provided in and around the cities of Poughkeepsie, Beacon, Newburgh, and Kingston, New York, and in certain outlying and intervening territories.

Central Hudson's electric T&D system consists of more than 15,000 circuit km of line and met a peak demand of 1,109 MW in 2019.

Central Hudson's natural gas system consists of approximately 2,350 km of T&D pipelines and met a peak day demand of 148 TJ in 2019.

Market and Sales

Central Hudson's electricity sales were 4,963 GWh in 2019, compared to 5,118 GWh in 2018. Natural gas sales volumes in 2019 were 22 PJ, compared to 24 PJ in 2018. Revenue was $917 million in 2019, compared to $924 million in 2018.

The following table compares the composition of Central Hudson's 2019 and 2018 revenue, electricity sales and gas volumes by customer class.

	Revenue (%)		GWh Sales (%)		PJ Volumes (%)
	2019	2018	2019	2018	2019	2018
Residential	62.6	65.4	41.4	42.4	28.8	26.9
Commercial	27.8	29.2	38.9	38.5	38.8	35.6
Industrial	3.9	3.8	18.1	17.9	16.9	21.6
Other	4.5	0.2	0.5	0.5	6.9	7.2
Sales for Resale	1.2	1.4	1.1	0.7	8.6	8.7
Total	100.0	100.0	100.0	100.0	100.0	100.0

Power Supply

Central Hudson relies on purchased capacity and energy from third-party providers, together with its own minimal generating capacity, to meet the demands of its full-service customers.

ANNUAL INFORMATION FORM	15	December 31, 2019

Central Hudson is obligated to supply electricity to its retail electric customers. Central Hudson, the staff of the NYPSC and others entered into a settlement agreement in 1998 with respect to the auction of fossil fuel generation plants owned by Central Hudson. Under the settlement agreement, Central Hudson's retail customers may elect to procure electricity from third‑party suppliers or may continue to rely on Central Hudson. As part of its requirement to supply customers who continue to rely on Central Hudson for their energy supply, Central Hudson entered into a 10-year revenue sharing agreement with Constellation Energy Group, Inc. in 2011, pursuant to which Central Hudson shares in a portion of the power sales revenue attributable to Unit No. 2 of the Nine Mile Point Nuclear Generating Station.

Costs of electric and natural gas commodity purchases are recovered from customers, without earning a profit on these costs. Rates are reset monthly based on Central Hudson's actual costs to purchase the electricity and natural gas needed to serve its full-service customers.

FortisBC Energy

FortisBC Energy is the largest distributor of natural gas in British Columbia, serving approximately 1,041,000 residential, commercial and industrial and transportation customers in more than 135 communities. FortisBC Energy provides T&D services to customers, and obtains natural gas supplies on behalf of most residential, commercial and industrial customers.

FortisBC Energy owns and operates approximately 49,500 km of natural gas pipelines and met a peak day demand of 1,352 TJ in 2019.

Market and Sales

FortisBC Energy's natural gas sales volumes were 227 PJ in 2019, compared to 212 PJ in 2018. Revenue was $1,331 million in 2019 compared to $1,187 million in 2018.

The following table compares the composition of FortisBC Energy's 2019 and 2018 revenue and natural gas volumes by customer class.

	Revenue (%)		PJ Volumes (%)
	2019	2018	2019	2018
Residential	57.7	57.7	35.7	36.3
Commercial	28.6	27.7	22.9	23.1
Industrial	4.3	3.2	4.4	2.8
Transportation	9.4	11.4	37.0	37.8
Total	100.0	100.0	100.0	100.0

Gas Purchase Agreements

To ensure supply of adequate resources for reliable natural gas deliveries to its customers, FortisBC Energy purchases natural gas supply from counterparties, including producers, aggregators and marketers. FortisBC Energy contracts for approximately 184 PJ of baseload and seasonal supply, of which the majority is sourced in northeast British Columbia and transported on Westcoast Energy Inc.'s T‑South pipeline system. The remainder is sourced in Alberta and transported on TransCanada's pipeline transportation system.

FortisBC Energy procures and delivers natural gas directly to core market customers. Transportation customers are responsible to procure and deliver their own natural gas to the FortisBC Energy system and FortisBC Energy then delivers the gas to the operating premises of these customers. FortisBC Energy contracts for transportation capacity on third-party pipelines, such as the T‑South pipeline and the TransCanada pipeline, to transport gas supply from various market hubs to FortisBC Energy's system. These third-party pipelines are regulated by the National Energy Board. FortisBC Energy pays both fixed and variable charges for the use of transportation capacity on these pipelines, which are recovered through rates paid by FortisBC Energy's core market customers. FortisBC Energy contracts for firm transportation capacity to ensure it is able to meet its obligation to supply customers within its broad operating region under all reasonable demand scenarios.

ANNUAL INFORMATION FORM	16	December 31, 2019

Gas Storage and Peak Shaving Arrangements

FortisBC Energy incorporates peak shaving and gas storage facilities into its portfolio to: (i) supplement contracted baseload and seasonal gas supply in the winter months, while injecting excess baseload supply to refill storage in the summer months; (ii) mitigate the risk of supply shortages during cooler weather and peak days; (iii) manage the cost of gas during the winter months; and (iv) balance daily supply and demand on the distribution system during periods of peak use that occur during the winter months.

FortisBC Energy holds approximately 36 PJs of total storage capacity. FortisBC Energy owns Tilbury and Mount Hayes LNG peak shaving facilities, which provide on-system storage capacity and deliverability. FortisBC Energy also contracts for underground storage capacity and deliverability from third parties in northeast British Columbia, Alberta and the Pacific Northwest of the US. On a combined basis, FortisBC Energy's Tilbury and Mount Hayes facilities, the contracted storage facilities, and other peaking arrangements can deliver up to 0.73 PJs per day of supply to FortisBC Energy on the coldest days of the heating season. The heating season typically occurs from December to February.

Mitigation Activities

FortisBC Energy engages in off-system sales activities that allow for the recovery or mitigation of costs of any unutilized supply and/or pipeline and storage capacity that is available once customers' daily load requirements are met.

Under the GSMIP revenue sharing model, which is approved by the BCUC, FortisBC Energy can earn an incentive payment for mitigation activities. Historically, FortisBC Energy has earned approximately $1.8 million annually through GSMIP, while the remaining savings are credited back to customers through reduced rates. Subject to the BCUC's approval, FortisBC Energy earned an incentive payment of approximately $3.1 million for the gas contract 12 months ended October 31, 2019.

The current GSMIP program was approved by the BCUC following a comprehensive review in 2011. The BCUC has approved extensions of the program through October 31, 2022.

Price-Risk Management Plan

FortisBC Energy engages in price-risk management activities to mitigate the impact on customer rates of fluctuations in natural gas prices. These activities include: (i) physical gas purchasing and storage strategies; (ii) current quarterly commodity rate-setting and a deferral account mechanism; and (iii) the use of derivative instruments, which were implemented pursuant to a price-risk management plan approved by the BCUC, as discussed below.

In May 2019 FortisBC Energy filed its Winter 2019-2020 Sumas Risk Mitigation Application with the BCUC to implement Sumas hedging strategies for the 2019-2020 winter season to mitigate the impact of price spikes and sustained elevated prices at the Sumas market hub. The BCUC approved the application in June 2019 and the hedging strategies were implemented in July 2019.

Unbundling

A Customer Choice program at FortisBC Energy allows eligible commercial and residential customers to buy their natural gas commodity supply from FortisBC Energy or from third-party marketers. FortisBC Energy continues to provide the delivery service of the natural gas to all its customers. For the year ended December 31, 2019, approximately 4% of eligible commercial customers and 3% of eligible residential customers purchased their commodity supply from alternate providers.

ANNUAL INFORMATION FORM	17	December 31, 2019

FortisAlberta

FortisAlberta is a regulated electricity distribution utility operating in Alberta. Its business is the ownership and operation of regulated electricity distribution facilities that distribute electricity, generated by other market participants, from high-voltage transmission substations to end-use customers. FortisAlberta is not involved in the generation, transmission or direct retail sale of electricity. FortisAlberta operates the electricity distribution system in a substantial portion of southern and central Alberta, totalling approximately 91,000 circuit km of distribution lines. Many of FortisAlberta's customers are located in rural and suburban areas around and between the cities of Edmonton and Calgary. FortisAlberta's distribution network serves approximately 568,000 residential, commercial, farm, oil and gas and industrial customers and met a peak demand of 2,642 MW in 2019.

Market and Sales

FortisAlberta's annual energy deliveries were 16,887 GWh in 2019 compared to 17,154 GWh in 2018. Revenue was $598 million in 2019 compared to $579 million in 2018.

The following table compares the composition of FortisAlberta's 2019 and 2018 revenue and energy deliveries by customer class.

	Revenue (%)		GWh Deliveries (%) ^(1)^
	2019	2018	2019	2018
Residential	30.4	30.9	18.7	18.5
Large commercial, industrial and oil field	21.0	21.2	58.9	59.0
Farms	12.2	12.3	8.6	8.6
Small commercial	12.2	12.2	8.5	8.4
Small oil field	8.1	8.4	5.0	5.2
Other ^(2)^	16.1	15.0	0.3	0.3
Total	100.0	100.0	100.0	100.0
^(1)^	GWh percentages exclude FortisAlberta's GWh deliveries to "transmission-connected" customers. These deliveries were 6,940 GWh in 2019 and 7,024 GWh in 2018, based on an interim settlement that is expected to be finalized in May 2020, and consisted primarily of energy deliveries to large-scale industrial customers directly connected to the transmission grid.
---	---
^(2)^	Includes revenue from sources other than the delivery of energy, including revenues resulting from street-lighting services, rate riders, deferrals and adjustments
---	---

Franchise Agreements

FortisAlberta serves customers in various municipalities throughout its service area. From time to time, municipal governments in Alberta consider creating their own electric distribution utilities by purchasing the assets of FortisAlberta located within their municipal boundaries. Upon the termination, or in the absence, of a franchise agreement, a municipality has the right, subject to AUC approval, to purchase FortisAlberta's assets within its municipal boundaries pursuant to the Municipal Government Act (Alberta), with the price to be as agreed by FortisAlberta and the municipality, failing which it is to be determined by the AUC. Additionally, under the Hydro and Electric Energy Act (Alberta), if a municipality that owns an electric distribution system expands its boundaries, it can acquire FortisAlberta's assets in the annexed area. In such circumstances, the Hydro and Electric Energy Act (Alberta) provides that the AUC may determine that the municipality should compensate FortisAlberta for any facilities transferred on the basis of replacement cost less depreciation. Given the historical population and economic growth of Alberta and its municipalities, FortisAlberta is affected by transactions of this type from time to time.

FortisAlberta holds franchise agreements with 160 municipalities within its service area. The franchise agreements include 10‑year terms with an option to renew for up to two subsequent five-year terms. Over 99% of FortisAlberta's franchise agreements are on the 2012 franchise agreement template, pursuant to which the initial terms will not expire until the end of 2022 and beyond.

ANNUAL INFORMATION FORM	18	December 31, 2019

FortisBC Electric

FortisBC Electric is an integrated regulated electric utility that owns hydroelectric generating plants, high voltage transmission lines and a large network of distribution assets, all of which are located in the southern interior of British Columbia. FortisBC Electric serves approximately 179,000 customers and met a peak demand of 696 MW in 2019. FortisBC Electric's T&D assets include approximately 7,300 circuit km of T&D lines.

FortisBC Electric is also responsible for operation, maintenance and management services at the 493‑MW Waneta hydroelectric generating facility owned by BC Hydro and the 335‑MW Waneta Expansion, the 149-MW Brilliant hydroelectric plant, the 120‑MW Brilliant hydroelectric expansion plant and the 185-MW Arrow Lakes generating station, all owned by CBT and CPC.

Market and Sales

Electricity sales were 3,326 GWh in 2019, compared to 3,250 GWh in 2018. Revenue was $418 million in 2019, compared to $408 million in 2018.

The following table compares the composition of FortisBC Electric's 2019 and 2018 revenue and electricity sales by customer class.

	Revenue (%)		GWh Sales (%)
	2019	2018	2019	2018
Residential	48.9	51.1	38.8	40.8
Commercial	27.1	27.1	29.4	30.1
Wholesale	13.2	13.3	17.6	17.6
Industrial	10.8	8.5	14.2	11.5
Total	100.0	100.0	100.0	100.0

Generation and Power Supply

FortisBC Electric meets the electricity supply requirements of its customers through a mix of its own generation and PPAs. FortisBC Electric owns four regulated hydroelectric generating plants on the Kootenay River with an aggregate capacity of 225 MW, which provide approximately 45% of its energy needs and 30% of its peak capacity needs. FortisBC Electric meets the balance of its requirements through a portfolio of long-term and short-term PPAs.

FortisBC Electric's four hydroelectric generating facilities are governed by the multi‑party CPA that enables the five separate owners of nine major hydroelectric generating plants, with a combined capacity of approximately 1,900 MW and located in relatively close proximity to each other, to coordinate the operation and dispatch of their generating plants.

The following table lists the plants and their respective capacity and owner.

Plant	Capacity<br><br>(MW)	Owners
Canal Plant	580	BC Hydro
Waneta Dam	493	BC Hydro
Waneta Expansion	335	Waneta Expansion Power Corporation
Kootenay River System	225	FortisBC Electric
Brilliant Dam	149	Brilliant Power Corporation
Brilliant Expansion	120	Brilliant Expansion Power Corporation
Total	1,902
ANNUAL INFORMATION FORM	19	December 31, 2019
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Brilliant Power Corporation, Brilliant Expansion Power Corporation, Teck Metals Ltd., Waneta Expansion Power Corporation and FortisBC Electric are collectively defined in the CPA as the entitlement parties. The CPA enables BC Hydro and the entitlement parties to generate more power from their respective generating plants than they could if they operated independently through coordinated use of water flows, subject to the 1961 Columbia River Treaty between Canada and the US, and coordinated operation of storage reservoirs and generating plants. Under the CPA, BC Hydro takes into its system all power actually generated by the plants listed in the table above. In exchange for permitting BC Hydro to determine the output of these facilities, each of the entitlement parties is contractually entitled to a fixed annual entitlement of capacity and energy from BC Hydro, which is based on 50-year historical water flows and the plants' generating capabilities. The entitlement parties receive their defined entitlements irrespective of actual water flows to the entitlement parties' generating plants. BC Hydro enjoys the benefits of the additional power generated through coordinated operation and optimal use of water flows. The entitlement parties benefit by knowing years in advance the amount of power that they will receive from their generating plants and, therefore, do not face hydrology variability in generation supply planning. However, FortisBC Electric retains rights to its original water licences and flows in perpetuity. Should the CPA be terminated, the output of FortisBC Electric's Kootenay River system plants would, with the water and storage authorized under its existing licences and on a long‑term average, be approximately the same power output as FortisBC Electric receives under the CPA. The CPA does not affect FortisBC Electric's ownership of its physical generation assets. The CPA continues in force until terminated by any of the parties by giving no less than five years' notice at any time on or after December 31, 2030.

FortisBC Electric's remaining electricity supply is acquired through short and long-term PPAs with a number of counterparties. During 2019 FortisBC Electric purchased capacity and energy from the market to meet its peak energy requirements and optimize its overall power supply portfolio. Spot market and contracted purchases provided approximately 12% of FortisBC Electric's energy supply requirements in 2019. FortisBC Electric's PPAs and market purchases have been accepted by the BCUC and prudently incurred costs thereunder flow through to customers through FortisBC Electric's electricity rates.

Other Electric

Other Electric consists of utilities in eastern Canada and the Caribbean as follows: Newfoundland Power; Maritime Electric; FortisOntario; a 39% equity investment in Wataynikaneyap Partnership; an approximate 60% controlling interest in Caribbean Utilities; FortisTCI; and a 33% equity investment in Belize Electricity.

Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador. Maritime Electric is an integrated regulated electric utility and the principal distributor of electricity on PEI. FortisOntario primarily provides integrated electric utility service through its three regulated operating utilities in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario.

Caribbean Utilities is an integrated regulated electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands. FortisTCI is an integrated regulated electric utility on the Turks and Caicos Islands. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize. The results of Belize Electricity are not included in the description of this segment.

Wataynikaneyap Partnership has a mandate of connecting 17 remote First Nations Communities in Northwestern Ontario to the electricity grid. The partnership is equally owned by 24 First Nations communities (51%), in partnership with FortisOntario (39%) and Algonquin Power & Utilities Corp. (10%). In January 2019 Fortis reduced its equity investment in Wataynikaneyap Partnership from 49% to 39% to facilitate the inclusion of two additional First Nations communities into the partnership. FortisOntario is responsible for construction management and operation of the transmission line. In 2019 the engineering, procurement and construction contract for the project was awarded, the project achieved financial close and the notice to proceed was issued.

ANNUAL INFORMATION FORM	20	December 31, 2019

The following table sets out the customers, installed generating capacity, peak demand and kilometers of T&D lines for the segment.

	Customers	Peak Demand (MW)	T&D Lines (km) ^(1)^	Generating Capacity (MW)	Resource Type(s)
Newfoundland Power	269,000	1,458	12,500	143	Hydroelectric, Gas, Diesel
Maritime Electric	82,000	276	6,200	140	Thermal, Diesel
FortisOntario ^(2)^	66,000	255	3,500	5	Natural Gas Cogeneration
Caribbean Utilities ^(3)^	31,000	106	800	161	Diesel
FortisTCI	15,000	43	650	91	Diesel
Total	463,000	2,138	23,650	540
^(1)^	Circuit km
---	---
^(2)^	FortisOntario also owns a 10% interest in certain regional electric distribution companies serving approximately 40,000 customers.
---	---
^(3)^	Includes 24 km of high-voltage submarine cable
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Market and Sales

Electricity sales attributable to Other Electric were 9,366 GWh in 2019, compared to 9,314 GWh in 2018. Revenue was $1,467 million in 2019, compared to $1,412 million in 2018.

The following table compares the composition of revenue and electricity sales by customer class for Other Electric in 2019 and 2018.

	Revenue (%)		GWh Sales (%)
	2019	2018	2019	2018
Residential	56.0	54.3	55.5	55.6
Commercial and Industrial	42.9	43.5	44.4	44.3
Other ^(1)^	1.1	2.2	0.1	0.1
Total	100.0	100.0	100.0	100.0

^(1)^ Includes revenue from sources other than from the sale of electricity

Power Supply

Newfoundland Power

Approximately 93% of Newfoundland Power's energy requirements are purchased from NL Hydro with the remaining 7% generated by Newfoundland Power generating facilities. The principal terms of the supply arrangements with NL Hydro are regulated by the PUB on a basis similar to that upon which Newfoundland Power's service to its customers is regulated.

NL Hydro charges Newfoundland Power for purchased power and includes charges for both demand and energy purchased. The demand charge is based on applying a rate to the peak‑billing demand for the most recent winter season. The energy charge is a two-block charge with a higher second‑block charge set to reflect NL Hydro's marginal cost of generating electricity.

Nalcor Energy's Muskrat Falls hydroelectric generation development and associated transmission assets are scheduled to be commissioned by the end of 2020. Energy from the Muskrat Falls project is expected to supply a significant portion of NL Hydro's, and in turn, Newfoundland Power's, electricity requirements. Significant uncertainty remains regarding supply adequacy and reliability of the province of Newfoundland and Labrador's electrical system after commissioning. The amount and timing of future wholesale electricity rate changes, including those associated with the Muskrat Falls project, are uncertain; however, future increases in supply costs from NL Hydro are expected to increase electricity rates that Newfoundland Power charges to its customers.

ANNUAL INFORMATION FORM	21	December 31, 2019

Maritime Electric

Maritime Electric purchases approximately 84% of the electricity required to meet its customers' needs from NB Power, a New Brunswick Crown corporation. The balance is met through the purchase of wind energy produced on PEI by facilities owned by the PEI Energy Corporation and from company‑owned on-Island generation, used primarily for peaking, managing through submarine-cable loading issues and emergency purposes.

Maritime Electric has contracts with NB Power for the purchase of either energy or capacity: (i) covering the periods March 1, 2011 to February 28, 2019 and March 1, 2019 to February 29, 2024; and (ii) a transmission capacity contract allowing Maritime Electric to reserve 30 MW of capacity to PEI expiring November 2032.

Maritime Electric has entitlement to approximately 4.55% of the output from NB Power's Point Lepreau Nuclear Generating Station for the life of the unit and as part of its entitlement is required to pay its share of the capital and operating costs of the unit.

FortisOntario

The power requirements of FortisOntario's service territories are met through various sources. Canadian Niagara Power purchases its power requirements for Fort Erie and Port Colborne from IESO and purchases approximately 90% of energy requirements for Gananoque through monthly energy purchases from Hydro One Networks Inc. and 10% from the five hydroelectric generating plants of EO Generation LP. Algoma Power purchases 100% of its energy from IESO.

Under the Standard Supply Code of the Ontario Energy Board, Canadian Niagara Power and Algoma Power are obliged to provide Standard Service Supply to all its customers who do not choose to contract with an electricity retailer. This energy is provided to customers at either regulated or market prices.

Cornwall Electric purchases substantially all of its power requirements from Hydro-Québec Energy Marketing under two fixed‑term contracts, the first providing approximately 237 GWh of energy per year and up to 45 MW of capacity at any one time, and the second contract providing 100 MW of capacity and energy and a minimum of 300 GWh of energy per year. Both contracts expired in December 2019. In 2016 Cornwall Electric successfully negotiated a new contract that commenced January 2020 and expires December 2030. The new contract provides a minimum of 537 GWh of energy per year and up to 145 MW of capacity at any one time.

Caribbean Utilities

Caribbean Utilities relies upon in-house diesel-powered generation to produce electricity for its customers. Caribbean Utilities is party to primary and secondary fuel supply contracts with two different suppliers from whom it is committed to purchasing 60% and 40%, respectively, of its diesel fuel requirements for its diesel-powered generating plant. Caribbean Utilities executed two 24-month fuel supply contracts in June 2018 with the option to renew for two additional terms of 18 months at the end of each term.

FortisTCI

FortisTCI relies upon in-house diesel-powered generation to produce electricity for its customers. In 2019 FortisTCI installed and commissioned an additional 0.5 MW of photovoltaic energy generation, connected to FortisTCI's electricity grid following the commissioning of three rooftop installations from commercial customers under its Utility Owned Renewable Energy Program. To date, FortisTCI has installed 1 MW of rooftop solar in partnership with nine customers through this program.

FortisTCI has a renewable contract with a major supplier for all of its diesel fuel requirements associated with the generation of electricity. The approximate fuel requirements under this contract are 64 million litres per annum.

ANNUAL INFORMATION FORM	22	December 31, 2019

Non-Regulated

Energy Infrastructure

The Corporation's Energy Infrastructure segment is comprised of a natural gas storage facility in British Columbia (Aitken Creek) and three hydroelectric generation facilities in Belize with a combined capacity of 51 MW held through the Corporation's subsidiary BECOL. In April 2019 Fortis sold its 51% ownership interest in long-term contracted generation assets in British Columbia, the Waneta Expansion.

Aitken Creek is the only underground natural gas storage facility in British Columbia with a total working gas capacity of 77 billion cubic feet. Fortis holds a 93.8% ownership interest in Aitken Creek through its subsidiary ACGS, acquired in 2016. ACGS contracts with third parties for both lease and park transactions and also holds its own proprietary capacity.

Generation assets in Belize are comprised of three hydroelectric generating facilities. All of the output of these facilities is sold to Belize Electricity under 50-year PPAs expiring in 2055 and 2060.

Market and Sales

Energy sales were 144 GWh in 2019, compared to 853 GWh in 2018. Revenue was $82 million in 2019, compared to $184 million in 2018.

Corporate and Other

The Corporate and Other segment captures expense and revenue items 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.

ANNUAL INFORMATION FORM	23	December 31, 2019

HUMAN RESOURCES

Fortis and its subsidiaries have 8,970 employees, with 52% in Canada, 43% in the US and 5% in other countries. The following table provides the breakdown of employees by reportable segment.

	Employees	Participation in a Collective Agreement		Union(s)	Collective Agreement(s) Expiry Date(s)
Regulated Utilities
ITC	707	None		—	—
UNS Energy	2,103	51	%	IBEW	February 2020 – July 2022
Central Hudson	1,065	57	%	IBEW	March 2021 – April 2022
FortisBC Energy ^(1)^	1,873	63	%	IBEW, MoveUP	March 2019 ^(2)^– June 2023
FortisAlberta	1,111	79	%	UUWA	December 2020
FortisBC Electric	538	69	%	IBEW, MoveUP	December 2019 ^(3)^– March 2022
Other Electric ^(4)^	1,453	38	%	IBEW, CUPE, PWU	January 2022 – December 2023
Non-Regulated
Energy Infrastructure ^(5)^	69	None		—	—
Corporate and Other ^(6)^	51	None		—	—
Total	8,970	52	%
^(1)^	Includes employees at FHI
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^(2)^	The collective agreement between FortisBC Energy and IBEW covering 577 FortisBC Energy employees expired on March 31, 2019 and is currently under negotiations.
---	---
^(3)^	The collective agreement between FortisBC Electric and MoveUP covering 133 FortisBC Electric employees expired on December 31, 2019.
---	---
^(4)^	Includes employees at Newfoundland Power, Maritime Electric, FortisOntario, Caribbean Utilities and FortisTCI. Excludes Belize Electricity.
---	---
^(5)^	Includes employees at Aitken Creek (staffed by FortisBC Midstream Inc.), BECOL and FortisBC Alternative Energy Services Inc.
---	---
^(6)^	Employees at Fortis Inc.
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The Corporation's culture is built on safety, diversity and integrity. Fortis employees are driven to make good decisions, work hard and work safely. Fortis and its utilities respect their employees' freedom to associate and strive to maintain positive and constructive relationships with labour associations and unions. Approximately 52% of the Corporation's employees are covered by collective bargaining agreements.

The Corporation's subsidiaries are required to develop and retain skilled workforces for their operations. Many of the employees of the Corporation's utilities possess specialized skills and training and Fortis must compete in the marketplace for these workers. The Corporation's significant consolidated capital plan may present challenges to ensure its utilities have the qualified workforce necessary to complete the capital work initiatives.

ANNUAL INFORMATION FORM	24	December 31, 2019

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings that involve a claim for damages exceeding 10% of the Corporation's current assets in respect of which the Corporation is or was a party, or in respect of which any of the Corporation's property is or was the subject during the year ended December 31, 2019, nor are there any such proceedings known to the Corporation to be contemplated.

Information related to the Corporation's legal proceedings can be found in Note 29 of the Financial Statements, which are incorporated by reference in this AIF and available on SEDAR and EDGAR.

The Corporation's utilities operate under a cost of service regulation, in combination with performance-based rate-setting mechanisms in certain jurisdictions, and are regulated by the regulatory body in their respective operating jurisdiction. There have not been any: (a) penalties or sanctions imposed against the Corporation by a court relating to securities legislation or by a securities regulatory authority during the year ended December 31, 2019; (b) other penalties or sanctions imposed by a court or regulatory body against the Corporation that would likely be considered important to a reasonable investor in making an investment decision; or (c) settlement agreements entered into by the Corporation before a court relating to securities legislation or with a securities regulatory authority during the year ended December 31, 2019.

For information with respect to the nature of regulation and material regulatory decisions and applications associated with each of the Corporation's utilities, refer to the "Regulatory Highlights" section of the MD&A and to Notes 2 and 9 of the Financial Statements, each of which are incorporated by reference in this AIF and available on SEDAR and EDGAR.

RISK FACTORS

For information with respect to the Corporation's business risks, refer to the "Business Risks" section of the MD&A, which is incorporated by reference in this AIF and available on SEDAR and EDGAR.

SUSTAINABILITY

Fortis is committed to being a strong energy partner for its communities by operating in an environmentally and socially responsible manner. The Corporation is focused on maintaining infrastructure to deliver energy more efficiently and to facilitate the delivery of cleaner energy. Fortis believes that responsible environmental and sustainability management not only creates business value, but it is also good for the planet and our customers.

To bring focus and accountability to sustainability, oversight has been integrated into each senior level of responsibility at Fortis. The Board is responsible for risk management oversight and ensuring that business is conducted to meet high standards of environmental and social responsibility. The Governance and Nominating Committee of the Board is responsible for overseeing governance structure and practices, including reviewing programs designed to promote corporate citizenship and environmental and social responsibility. The Executive Vice President, Sustainability and Chief Human Resource Officer is responsible for enterprise-wide sustainability and stewardship. Local management teams and boards of directors at each of the Corporation's utilities are responsible for operational aspects of sustainability. Sustainability performance impacts how all Fortis executives are compensated.

Fortis is primarily an energy delivery company with 93% of its assets dedicated to this function. This focus on energy delivery presents a unique opportunity to facilitate the delivery of cleaner energy to customers and naturally limits our impact on the environment when compared with energy generation intensive businesses. Although Fortis has limited fossil-fuel generation exposure, the Corporation is committed to reducing carbon emissions and delivering more sustainable energy to our customers.

ANNUAL INFORMATION FORM	25	December 31, 2019

The Corporation's GHG emissions come primarily from its generation assets, including fossil fuel-based generation representing 5% of the Corporation's total assets. TEP is the Corporation's primary producer of fossil fuel-based generation and is taking significant steps to reduce coal-fired generation and resulting carbon emissions. TEP has a goal of delivering 30% of retail sales with renewable power in 2030, double the State of Arizona's 2025 goal. TEP is expecting to surpass this goal well ahead of 2030 as renewable generation is expected to exceed 28% of retail sales in 2021. With this goal almost achieved, TEP is now engaging key community stakeholders and collaborating with the University of Arizona's Institute of the Environment to develop new science-based targets aligned with GHG limits outlined in the 2015 Paris Agreement on Climate Change.

FortisBC Energy and FortisBC Electric have set a combined goal to reduce GHG emissions associated with customers' energy use by 30% by the year 2030. To achieve this objective, the utilities will focus on tripling investment in energy efficiency projects, increasing renewable natural gas supply and focusing on low and zero-carbon vehicles and transportation infrastructure. This overall GHG emission reduction target is supported by FortisBC Energy's aim to have 15% of its gas supply come from renewable sources by 2030.

The Corporation's environmental statement sets out its commitment to comply with all applicable laws and regulations relating to the protection of the environment, regularly conduct monitoring and audits of environmental management systems and seek feasible, cost-effective opportunities to decrease GHG emissions and increase renewable energy sources. The Fortis Sustainability Working Group, comprising key leaders from across the Fortis group of utilities, enables communication and sharing of information among the Corporation's utilities on sustainability performance, issues and opportunities. Each operating subsidiary has extensive environmental compliance programs aligned with the ISO 14001 standard, regularly reviews its environmental management systems and protocols, strives for continual performance improvement and sets and reviews its own environmental objectives, targets and programs. The Fortis Operating Group, comprised of senior operational executives from all utilities, meets regularly to share best practices and identify opportunities for collaboration on a range of topics including environment, health and safety.

Social and Environmental Policies

The Corporation and its utilities each have a range of social and environmental policies, programs and practices. Fortis has a Code of Conduct which sets out the Corporation's standards for the ethical conduct of its business, applicable to all of its directors, officers and employees, and to the extent feasible also to its consultants, contractors and representatives. The core principles of the Fortis Code of Conduct apply universally across the organization, with each operating subsidiary adopting its own substantially similar Code. To ensure implementation, Fortis and its utilities hold regular Code of Conduct employee training and Fortis requires all employees to certify compliance.

The Code of Conduct is supported by other policies that outline the behaviour expected from management and employees, including the Anti-Corruption Policy and Respectful Workplace Policy. All Fortis operating subsidiaries have policies in place that uphold the Corporation's values as contained in these policies and demonstrate their commitment to ensuring equal opportunity and providing safe, respectful work environments.

Each Fortis operating subsidiary has a Whistleblower Policy to support the reporting of conduct that may breach the subsidiary's Code of Conduct or other workplace policies.

The Corporation's Board and Executive Diversity Policy describes the principles and objectives for diversity among the Board and the Corporation's executive leadership, including a commitment to maintaining a Board where at least one-third of its independent directors are represented by each gender. The Corporation has steadily increased the number of female directors on its Board from 10% of elected directors in 2013 to 42% in 2019. In addition, 38% of the Fortis Inc. leadership team is female.

In 2019 the Corporation adopted a formal Inclusion and Diversity Commitment that applies to all employees at Fortis and its operating subsidiaries. This statement of commitment to inclusion and diversity was developed to guide activities that advance and enhance inclusion and diversity in the workplace.

ANNUAL INFORMATION FORM	26	December 31, 2019

The Corporation's operating subsidiaries are also responsible for implementing policy frameworks that reflect their unique operations and jurisdictions, while addressing certain common priority areas, including: occupational health and safety; environmental stewardship; non-discrimination and equal opportunity in hiring and promotion; and support of local communities.

Sustainability Regulation and Environmental Contingencies

As part of the regulatory process, operating subsidiaries engage with stakeholders, including community groups, regulators and customers, to consult on the potential environmental impact of their operations. The Corporation and its subsidiaries are subject to various federal, provincial, state and municipal laws, regulations and guidelines relating to the protection of the environment. Environmental compliance involves significant operating and capital costs. At the Corporation's regulated utilities, prudently incurred costs associated with environmental protection and compliance are generally eligible for recovery in customer rates.

The following contingencies have been made as of December 31, 2019:

Mine Reclamation at Generation Facilities Not Operated by TEP. TEP pays ongoing reclamation costs related to coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP is permitted to fully recover these costs from retail customers and, accordingly, these costs are deferred as a regulatory asset.

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing San Juan and Four Corners. TEP's estimated share of mine reclamation costs at both mines is $74 million (US$57 million) upon expiration of the related coal supply agreements, which expire in 2022 and 2031, respectively. An aggregate liability balance related to San Juan and Four Corners final mine reclamation of $47 million (US$36 million) and $42 million (US$31 million) as at December 31, 2019 and 2018, respectively, was recorded on the balance sheet.

In December 2019 TEP entered into an agreement with the owner and operator of the Kayenta Mine and the third-party owners of the Navajo Generating Station for the settlement and release of asserted claims associated with the early retirement of Navajo. During 2019 TEP paid $23 million (US$17 million) in final mine reclamation costs related to the early retirement of Navajo, which includes $11 million (US$8 million) paid for final mine reclamation costs as a result of the settlement. As at December 31, 2019, TEP had no liability balance related to Navajo final mine reclamation. A liability balance related to final mine reclamation at Navajo of $7 million (US$5 million) as at December 31, 2018, which was recorded on the balance sheet.

Former Manufactured Gas Plant Facilities. Environmental regulations require Central Hudson to investigate sites at which Central Hudson or its predecessors once owned and/or operated manufactured gas plants and, if necessary, remediate these sites. Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated. As at December 31, 2019, an obligation of $74 million (US$57 million) was recognized. Central Hudson has notified its insurers and intends to seek reimbursement where insurance coverage exists. Further, as authorized by the NYPSC, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for manufactured gas plant site investigation and remediation and the associated rate allowances.

CAPITAL STRUCTURE AND DIVIDENDS

Description of Capital Structure

The authorized share capital of the Corporation consists of an unlimited number of common shares without nominal or par value, an unlimited number of first preference shares without nominal or par value, and an unlimited number of second preference shares without nominal or par value.

As at February 12, 2020, the Corporation had issued and outstanding 463.5 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M.

ANNUAL INFORMATION FORM	27	December 31, 2019

For a summary of the terms and conditions of the Corporation's authorized securities, and trading information for the Corporation's publicly listed securities, refer to Exhibit "A" and Exhibit "B" of this AIF.

Dividends and Distributions

The declaration and payment of dividends on the Corporation's common shares and first preference shares are at the discretion of the Board. Dividends on the common shares are typically paid quarterly, on the first day of March, June, September and December of each year. Dividends on the Corporation's First Preference Shares, Series F, G, H, I, J, K and M are typically also paid quarterly.

In September 2019 Fortis increased its quarterly dividend per common share 6.1% to $0.4775 per share, or $1.91 on an annualized basis. In November 2019 the Board declared a first quarter 2020 dividend on the common shares of $0.4775 per share and on the First Preference Shares, Series F, G, H, I, J, K and M in accordance with the applicable prescribed rate. The first quarter dividends on the common shares and the First Preference Shares, Series F, G, H, I, J, K and M are to be paid on March 1, 2020 to holders of record as of February 18, 2020.

The following table summarizes the cash dividends declared per share for each of the Corporation's class of shares for the past three years.

	2019	2018	2017
Common Shares	1.855	1.750	1.650
First Preference Shares, Series F ^(1)^	1.2250	1.2250	1.2250
First Preference Shares, Series G^(2)^	1.0983	1.0345	0.9708
First Preference Shares, Series H^(3)^	0.6250	0.6250	0.6250
First Preference Shares, Series I ^(4)^	0.7771	0.7116	0.5262
First Preference Shares, Series J ^(1)^	1.1875	1.1875	1.1875
First Preference Shares, Series K^(5)^	0.9821	1.0000	1.0000
First Preference Shares, Series M^(6)^	1.0135	1.0250	1.0250
^(1)^	The dividend rate on the First Preference Shares, Series F and First Preference Shares, Series J are fixed and do not reset.
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^(2)^	The annual fixed dividend per share for the First Preference Shares, Series G was reset from $0.9708 to $1.0983 for the five-year period from September 1, 2018 to but excluding September 1, 2023.
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^(3)^	The annual fixed dividend per share for the First Preference Shares, Series H was reset from $1.0625 to $0.6250 for the five-year period from June 1, 2015 to but excluding June 1, 2020.
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^(4)^	The First Preference Shares, Series I are entitled to receive floating rate cumulative dividends, which rate will reset every quarter based on the then current three‑month Government of Canada Treasury Bill rate plus 1.45%.
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^(5)^	The Fixed Rate Reset First Preference Shares, Series K were issued in July 2013 at $25.00 per share and were entitled to receive cumulative dividends in the amount of $1.0000 per share per annum to but excluding March 1, 2019. The annual fixed dividend per share for the First Preference Shares, Series K was reset to $0.9823 for the five-year period from March 1, 2019 to but excluding March 1, 2024.
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^(6)^	The Fixed Rate Reset First Preference Shares, Series M were issued in September 2014 at $25.00 per share and were entitled to receive cumulative dividends in the amount of $1.0250 per share per annum for the first five years. The annual fixed dividend per share for the First Preference Shares, Series M was reset to $0.9783 for the five-year period from December 1, 2019 to but excluding December 1, 2024.
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For purposes of the enhanced dividend tax credit rules contained in the Income Tax Act (Canada) and any corresponding provincial and territorial tax legislation, all dividends paid on common and preference shares after December 31, 2005 by Fortis to Canadian residents are designated as "eligible dividends". Unless stated otherwise, all dividends paid by Fortis hereafter are designated as "eligible dividends" for the purposes of such rules.

ANNUAL INFORMATION FORM	28	December 31, 2019

Debt Covenant Restrictions on Dividend Distributions

The Corporation has a $1.3 billion unsecured committed revolving corporate credit facility, maturing in July 2024, that is available for general corporate purposes. The credit facility contains covenants that (i) restrict the issuance of additional debt such that the consolidated debt to consolidated capitalization ratio does not exceed 70% at any time; and (ii) provide that Fortis 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%.

As at December 31, 2019 and 2018, the Corporation was in compliance with its debt covenant restrictions pertaining to dividend distributions, as described above.

Credit Ratings

Securities issued by Fortis and its utilities, that are currently rated, are rated by one or more credit rating agencies, namely DBRS Morningstar, S&P, Moody's and/or Fitch. The ratings assigned to securities issued by Fortis and its utilities are reviewed by the agencies on an ongoing basis. Credit and stability ratings are intended to provide investors with an independent measure of credit quality of an issue of securities and are not recommendations to buy sell or hold securities. Ratings may be subject to revision or withdrawal at any time by the rating organization. The following table summarizes the Corporation's debt credit ratings as at February 12, 2020.

Company/Security	DBRS Morningstar	S&P	Moody's
Fortis^^- Unsecured Debt ^(1)^	BBB (high), Stable	BBB+, Negative	Baa3, Stable
Caribbean Utilities^^-^^Unsecured Debt ^(2)^	A (low), Stable	BBB+, Stable	—
Central Hudson^^-^^Unsecured Debt ^(3) (4)^	—	A-, Stable	A3, Stable
FortisAlberta - Unsecured Debt	A (low), Stable	A-, Negative	Baa1, Stable
FortisBC Electric
Secured Debt	A (low), Stable	—	—
Unsecured Debt	A (low), Stable	—	Baa1, Stable
FortisBC Energy
Unsecured Debt	A, Stable	—	A3, Stable
Commercial Paper	R-1 (low), Stable	—	—
ITC Holdings
Unsecured Debt (5)	—	BBB+, Negative	Baa2, Stable
Commercial Paper	—	A-2, Negative	Prime-2, Stable
ITC Great Plains -^^First Mortgage Bonds	—	A, Negative	A1, Stable
ITC Midwest - First Mortgage Bonds	—	A, Negative	A1, Stable
ITCTransmission - First Mortgage Bonds	—	A, Negative	A1, Stable
Maritime Electric - Secured Debt	—	A, Stable	—
METC - Secured Debt	—	A, Negative	A1, Stable
Newfoundland Power - First Mortgage Bonds	A, Stable	—	A2, Stable
TEP
Unsecured Debt	—	A-, Negative	A3, Stable
Unsecured Bank Credit Facility			A3, Stable
UNS Electric
Unsecured Debt	—	—	A3, Stable
Unsecured Bank Credit Facility	—	—	A3, Stable
UNS Gas - Unsecured Debt	—	—	A3, Stable
UNS Energy - Unsecured Bank Credit Facility	—	—	Baa1, Stable
^(1)^	Between March and May 2019, all three rating agencies affirmed the Corporation's credit ratings and outlooks. The negative outlook from S&P reflects a modest temporary weakening of financial measures as a result of U.S. tax reform reducing cash flow at the Corporation's U.S. regulated utilities.
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^(2)^	In October 2019 S&P downgraded Caribbean Utilities' unsecured debt rating to BBB+ from A- due to climate change risk and revised its outlook to stable from negative due to its predictable cash flows.
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^(3)^	In July 2019 Moody's downgraded Central Hudson's unsecured debt rating to A3 from A2 and revised its outlook to stable from negative due to higher capital expenditures and the impacts of U.S. tax reform.
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^(4)^	Central Hudson's senior unsecured debt is also rated by Fitch at 'A-'.
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ANNUAL INFORMATION FORM	29	December 31, 2019
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^(5)^	In September 2019 S&P downgraded the senior unsecured debt rating of ITC Holdings to BBB+ from A- due to an expected increase in the ratio of debt at its regulated utilities relative to debt at the holding company and maintained its negative outlook. S&P also affirmed ITC's regulated subsidiaries' secured debt ratings of A.

DBRS Morningstar rates debt instruments by rating categories ranging from AAA to D, which represents the range from highest to lowest quality of such securities. DBRS Morningstar states that: (i) its long-term debt ratings are meant to give an indication of the risk that the borrower will not fulfill its obligations in a timely manner with respect to both interest and principal commitments; (ii) its ratings do not take factors such as pricing or market risk into consideration and are expected to be used by purchasers as one part of their investment decision; and (iii) every rating is based on quantitative and qualitative considerations that are relevant for the borrowing entity. According to DBRS Morningstar, a rating of A by DBRS Morningstar is in the middle of three subcategories within the third highest of nine major categories. Such rating is assigned to debt instruments considered to be of satisfactory credit quality and for which protection of interest and principal is still substantial, but the degree of strength is less than with AA rated entities. Entities rated in the BBB category are considered to have long-term debt of adequate credit quality. Protection of interest and principal is considered acceptable, but the entity is fairly susceptible to adverse changes in financial and economic conditions, or there may be other adverse conditions present which reduce the strength of the entity and its rated securities. The assignment of a (high) or (low) modifier within each rating category indicates relative standing within such category.

S&P's long-term debt ratings are on a ratings scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities. S&P uses '+' or '-' designations to indicate the relative standing of securities within a particular rating category. Such modifiers are not added to ratings below CCC. S&P states that its credit ratings are current opinions of the financial security characteristics with respect to the ability to pay under contracts in accordance with their terms. This opinion is not specific to any particular contract, nor does it address the suitability of a particular contract for a specific purpose or purchaser. An issuer rated A is regarded as having financial security characteristics to meet its financial commitments but is somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than those in higher-rated categories. Debt instruments rated BBB exhibit adequate protection parameters. However, adverse economic conditions or changing circumstances are more likely to lead to a weakened capacity of the issuer to meet its financial commitment on the obligation.

Moody's long-term debt ratings are on a rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities. In addition, Moody's applies numerical modifiers 1, 2 and 3 in each generic rating classification from Aa to Caa to indicate relative standing within such classification. The modifier 1 indicates that the security ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking in its generic rating category and the modifier 3 indicates that the security ranks in the lower end of its generic rating category. Moody's states that its long-term debt ratings are opinions of relative risk of fixed-income obligations with an original maturity of one year or more and that such ratings reflect both the likelihood of default and any financial loss suffered in the event of default. According to Moody's, a rating of Baa is the fourth highest of nine major categories and such a debt rating is assigned to debt instruments considered to be of medium-grade quality. Debt instruments rated Baa are subject to moderate credit risk and may possess certain speculative characteristics. Debt instruments rated A are considered upper-medium grade and are subject to low credit risk.

Moody's short-term debt ratings are on a rating scale that includes four designations, all of which are judged to be investment grade. From highest to lowest relative repayment ability of rated issuers, such designations are Prime-1, Prime-2, Prime-3 and Not Prime. Issuers with a Not Prime rating do not fall within any of the Prime rating categories. According to Moody's, a rating of Prime-2 means that an issuer has a strong ability to repay short-term debt obligations.

ANNUAL INFORMATION FORM	30	December 31, 2019

Fitch's long-term debt ratings are on a rating scale that ranges from AAA to C, which represents the range from highest to lowest quality of such securities. Fitch uses '+' or '-' designations to indicate the relative status of securities within a particular rating category. Such modifiers are not added to the AAA rating or to ratings below B. Fitch states that its credit ratings provide an opinion on the relative ability of an entity to meet financial commitments, such as interest, preferred dividends, repayment of principal, insurance claims or counterparty obligations. Fitch's credit ratings do not directly address any risk other than credit risk. The rating of A denotes expectation of low default risk, with strong capacity for payment of financial commitments. A rating of BBB denotes current expectations of low default risk, with adequate capacity for the payment of financial commitments.

The Corporation and/or each of its currently rated utilities pay DBRS Morningstar, S&P, Moody's and/or Fitch an annual monitoring fee and a one-time fee in connection with each rated issuance. In 2018 Fortis also paid fees to DBRS Morningstar in respect of advisory services provided in connection with potential asset dispositions.

ANNUAL INFORMATION FORM	31	December 31, 2019

DIRECTORS AND OFFICERS

The Board has governance guidelines that cover various items, including director tenure. The governance guidelines provide that Directors of the Corporation are to be elected for a term of one year and are eligible for re‑election until the annual meeting of shareholders following the date they turn 72 or until they have served on the Board for 12 years, whichever is earlier. Exceptions may be made by the Board if it is in the best interests of the Corporation and the Director has received solid annual performance evaluations, has the necessary skills and experience and meets the other Board policies and legal requirements for Board service.

The following table sets out the name, province or state, and country of residence of each of the Directors of the Corporation and their principal occupations during the five preceding years. Each Director's current term expires at the next annual meeting of shareholders.

Name, Residence, Principal Occupation Within Five Preceding Years	Director Since	Committees ^(1)^
		AC	GN	HR
DOUGLAS J. HAUGHEY (Chair), Alberta, Canada<br><br>Corporate Director.	2009	l	l	l
TRACEY C. BALL, British Columbia, Canada<br><br>Corporate Director.	2014	C	l
PIERRE J. BLOUIN, Quebec, Canada<br><br>Corporate Director.	2015		C ^(2)^	l
PAUL J. BONAVIA, Texas, USA<br><br>Corporate Director.	2018		l	l
LAWRENCE T. BORGARD, Florida, USA<br><br>Corporate Director. President and Chief Operating Officer of Integrys Energy Group from 2014 to 2015.	2017	l		l
MAURA J. CLARK, New York, USA<br><br>Corporate Director.	2015	l	l
MARGARITA K. DILLEY, District of Columbia, USA<br><br>Corporate Director.	2016	l		l
JULIE A. DOBSON, Maryland, USA<br><br>Corporate Director.	2018	l	l
BARRY V. PERRY, Newfoundland and Labrador, Canada<br><br>President and Chief Executive Officer of the Corporation.	2015	^(3)^
JOSEPH L. WELCH, Florida, USA<br><br>Corporate Director. President and Chief Executive Officer of ITC Holdings from 2003 to 2016.	2017	^(4)^
JO MARK ZUREL, Newfoundland and Labrador, Canada<br><br>Corporate Director. President of Stonebridge Capital Inc., a private investment company from 2006 to March 2019.	2016	l		C
^(1)^	Audit Committee, Governance and Nominating Committee and Human Resources Committee. "C" represents Chair.
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^(2)^	Mr. Blouin was appointed Chair of the Governance and Nominating Committee effective January 18, 2020.
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^(3)^	Mr. Perry does not serve on any of the committees because he is the President and Chief Executive Officer of the Corporation.
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^(4)^	Mr. Welch does not serve on any of the committees. He was not considered independent under Canadian securities laws until November 1, 2019 as he was President and Chief Executive Officer of ITC Holdings until October 31, 2016.
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ANNUAL INFORMATION FORM	32	December 31, 2019
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The following table sets out the name, province or state, and country of residence of each of the executive officers of Fortis and indicates the office held and principal occupations of the executive officers during the five preceding years.

Name, Residence, Principal Occupation During the Five Preceding Years	Office
BARRY V. PERRY, Newfoundland and Labrador, Canada<br><br>President and Chief Executive Officer since January 2015.	President and Chief Executive Officer
JOCELYN H. PERRY, Newfoundland and Labrador, Canada<br><br>Executive Vice President, Chief Financial Officer since June 2018. President and Chief Executive Officer of Newfoundland Power from 2017 to May 2018, Chief Financial Officer and Chief Operating Officer from 2016 to 2017 and Vice President, Finance & Chief Financial Officer from 2007 to 2016.	Executive Vice President, Chief Financial Officer
NORA M. DUKE, Newfoundland and Labrador, Canada<br><br>Executive Vice President, Sustainability and Chief Human Resource Officer since December 2017 and Executive Vice President, Corporate Services and Chief Human Resource Officer from August 2015 to December 2017.	Executive Vice President, Sustainability and Chief Human Resource Officer
DAVID G. HUTCHENS, Arizona, USA<br><br>Chief Operating Officer since January 2020 and Executive Vice President, Western Utility Operations from January 2018 to January 2020. Chief Executive Officer of UNS Energy since January 2020 and President and Chief Executive Officer of UNS Energy from May 2014 to January 2020.	Chief Operating Officer
JAMES P. LAURITO, Florida, USA<br><br>Executive Vice President, Business Development and Chief Technology Officer since May 2019 and Executive Vice President, Business Development since April 2016. President and Chief Executive Officer of Central Hudson from 2010 to April 2016.	Executive Vice President, Business Development and Chief Technology Officer
JAMES R. REID, Ontario, Canada<br><br>Executive Vice President, Chief Legal Officer and Corporate Secretary since March 2018. Partner with Davies Ward Phillips & Vineberg LLP from 2003 to March 2018.	Executive Vice President, Chief Legal Officer and Corporate Secretary
GARY J. SMITH, Newfoundland and Labrador, Canada<br><br>Executive Vice President, Eastern Canadian and Caribbean Operations since June 2017. President and Chief Executive Officer of Newfoundland Power from 2014 to June 2017.	Executive Vice President, Eastern Canadian and Caribbean Operations
STEPHANIE A. AMAIMO, Michigan, USA<br><br>Vice President, Investor Relations since October 2017, Director, Investor Relations from 2016 to October 2017 and Director, Investor Relations of ITC Holdings from 2015 to 2016.	Vice President, Investor Relations
KAREN J. GOSSE, Newfoundland and Labrador, Canada<br><br>Vice President, Treasury and Planning since April 2018. Vice President, Planning and Forecasting from November 2015 to April 2018.	Vice President, Treasury and Planning
RONALD J. HINSLEY, Michigan, USA<br><br>Vice President, Chief Information Officer since May 2019.Vice President, Information Technology and Chief Information Officer of ITC Holdings since 2013.	Vice President, Chief Information Officer
KAREN M. MCCARTHY, Newfoundland and Labrador, Canada<br><br>Vice President, Communications and Corporate Affairs since May 2018 and Director, Communications and Corporate Affairs from 2016 to May 2018. Director, Customer and Corporate Relations of Newfoundland Power from 2014 to 2016.	Vice President, Communications and Corporate Affairs
REGAN P. O'DEA, Newfoundland and Labrador, Canada<br><br>Vice President, General Counsel since May 2017 and Associate General Counsel from 2014 to May 2017.	Vice President, General Counsel
JAMIE D. ROBERTS, Newfoundland and Labrador, Canada<br><br>Vice President, Controller since March 2013.	Vice President, Controller

The directors and executive officers of Fortis, as a group, beneficially own, directly or indirectly, or exercise control or direction over 2,405,459 common shares, representing 0.52% of the issued and outstanding common shares of Fortis. The common shares are the only voting securities of the Corporation.

ANNUAL INFORMATION FORM	33	December 31, 2019

AUDIT COMMITTEE

Members

The members of the Corporation's Audit Committee are Tracey C. Ball (Chair), Lawrence T. Borgard, Maura J. Clark, Margarita K. Dilley, Julie A. Dobson, Douglas J. Haughey and Jo Mark Zurel. All members of the Audit Committee are independent and financially literate as those terms are defined by Canadian and US securities laws and TSX and NYSE requirements. In addition, the Board has determined that Tracey C. Ball, Maura J. Clark, Margarita K. Dilley and Jo Mark Zurel are financial experts and has designated each of them as "audit committee financial experts" under US securities laws.

The Corporation's Audit Committee Mandate, effective as of January 1, 2019, is attached as Exhibit "C" to this AIF.

Education and Experience

The education and experience of each Audit Committee member that is relevant to such member's responsibilities as a member of the Audit Committee are set out below.

Committee Member	Relevant Education and Experience
TRACEY C. BALL<br><br>(Chair)	Ms. Ball retired in September 2014 as Executive Vice President and Chief Financial Officer of Canadian Western Bank Group. Ms. Ball has served on several private and public sector boards, including the Province of Alberta Audit Committee and the Financial Executives Institute of Canada. She graduated from Simon Fraser University with a Bachelor of Arts (Commerce). She is a member of the Chartered Professional Accountants of Alberta and the Chartered Professional Accountants of British Columbia. Ms. Ball was elected as a Fellow of the Chartered Professional Accountants of Alberta in 2007. She holds an ICD.D designation from the Institute of Corporate Directors.
LAWRENCE T. BORGARD	Mr. Borgard retired from Integrys Energy Group in 2015 where he was President and Chief Operating Officer and the Chief Executive Officer of each of Integrys' six regulated electric and natural gas utilities. Mr. Borgard graduated from Michigan State University with a Bachelor of Science (Electrical Engineering) and the University of Wisconsin-Oshkosh with an MBA. He also attended the Advanced Management Program at Harvard University Business School.
MAURA J. CLARK	Ms. Clark retired from Direct Energy, a subsidiary of Centrica plc, in March 2014 where she was President of Direct Energy Business, a leading energy retailer in Canada and the US. Previously Ms. Clark was Executive Vice President of North American Strategy and Mergers and Acquisitions for Direct Energy. Ms. Clark's prior experience includes investment banking and serving as Chief Financial Officer of an independent oil refining and marketing company. Ms. Clark graduated from Queen's University with a Bachelor of Arts in Economics. She is a member of the Association of Chartered Professional Accountants of Ontario.
MARGARITA K. DILLEY	Ms. Dilley retired from ASTROLINK International LLC in 2004, an international wireless broadband telecommunications company, where she was Vice President and Chief Financial Officer. Ms. Dilley's prior experience includes serving as Director, Strategy & Corporate Development as well as Treasurer for Intelsat. Ms. Dilley graduated from Cornell University with a Bachelor of Arts, from Columbia University with a Master of Arts and from Wharton Graduate School, University of Pennsylvania with an MBA.
JULIE A. DOBSON	Ms. Dobson is Non-Executive Chairman of Telebright, Inc. a private firm established in 1989, where she oversees the development of management software applications and mobile applications for the business to business and business to consumer markets. She was Chief Operating Officer at Telecorp PCS, Inc. and held various senior management positions with Bell Atlantic Corporation during her 18-year career with the company. Ms. Dobson graduated from the College of William and Mary with a Bachelor of Science and from the University of Pittsburgh with an MBA.
DOUGLAS J. HAUGHEY	Mr. Haughey, from August 2012 through May 2013, was Chief Executive Officer of The Churchill Corporation. Prior to that, he served as President and Chief Executive Officer of Provident Energy Ltd. and held several executive roles with Spectra Energy and predecessor companies. He graduated from the University of Regina with a Bachelor of Business Administration and from the University of Calgary with an MBA. Mr. Haughey holds an ICD.D designation from the Institute of Corporate Directors.
JO MARK ZUREL	Mr. Zurel was the president of Stonebridge Capital Inc., a private investment company, from 2006 to March 2019. From 1998 to 2006, Mr. Zurel was Senior Vice-President and Chief Financial Officer of CHC Helicopter Corporation. Mr. Zurel graduated from Dalhousie University with a Bachelor of Commerce and is a Fellow of the Association of Chartered Professional Accountants of Newfoundland and Labrador. He holds an ICD.D designation from the Institute of Corporate Directors.
ANNUAL INFORMATION FORM	34	December 31, 2019
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Pre-Approval Policies and Procedures

The Audit Committee has established a policy that requires pre-approval of all audit and non-audit services provided to the Corporation and its subsidiaries by the Corporation's external auditor. The Pre‑Approval Policy for Independent Auditor Services describes the services that may be contracted from the external auditor and the related limitations and authorization procedures. This policy defines prohibited services, including but not limited to bookkeeping, valuations, internal audit and management functions, which may not be contracted from the external auditor and establishes an annual limit for permissible non-audit services not greater than the total fee for audit services. Audit Committee pre-approval is required for all services provided by the external auditor.

External Auditor Service Fees

The aggregate fees billed by the Corporation's external auditors during each of the last two fiscal years are set out in the following table.

		Deloitte LLP
($ thousands)	Description of Fee Category	2019	2018
Audit Fees	Core audit services	9,745	9,121
Audit-Related Fees	Assurance and related services that are reasonably related to the audit or review of the Financial Statements and are not included under Audit Fees	1,490	1,462
Tax Fees	Services related to tax compliance, planning and advice	669	636
Other	Services which are not Audit Services, Audit-Related Fees or Tax Fees	—	27
Total		11,904	11,246

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar in Canada for the common shares and first preference shares of Fortis is Computershare Trust Company of Canada in Montréal and Toronto.

The co-transfer agent and co-registrar in the US for the common shares is Computershare Trust Company, N.A. in Canton, MA, Jersey City, NJ and Louisville, KY.

Computershare Trust Company of Canada

8^th^ Floor, 100 University Avenue

Toronto, ON M5J 2Y1

T: 514.982.7555 or 1.866.586.7638

F: 416.263.9394 or 1.888.453.0330

W: www.investorcentre.com/fortisinc

Computershare Trust Company, N.A.

Att: Stock Transfer Department

Overnight Mail Delivery: 462 South 4th Street, Louisville, KY 40202

Regular Mail Delivery: P.O. Box 505005, Louisville, KY 40233-5005

T: 303.262.0600 or 1.800.962.4284

ANNUAL INFORMATION FORM	35	December 31, 2019

INTERESTS OF EXPERTS

Deloitte LLP is independent with respect to the Corporation within the meaning of the US Securities Act of 1933 and the applicable rules and regulations thereunder adopted by the SEC and the Public Company Accounting Oversight Board (United States) and within the meaning of the rules of professional conduct of the Chartered Professional Accountants of Newfoundland and Labrador.

ADDITIONAL INFORMATION

Additional information relating to the Corporation can be found on the Corporation's website at www.fortisinc.com, on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. The information contained on, or accessible through, any of these websites is not incorporated by reference into this document unless otherwise stated.

Additional financial information is provided in the Corporation's MD&A and Financial Statements, which are incorporated by reference in this AIF and can be found on the Corporation's website at www.fortisinc.com, on SEDAR and on EDGAR.

Further additional information, including officers' and directors' remuneration and indebtedness, principal holders of the securities of Fortis, options to purchase securities and interests of insiders in material transactions, where applicable, is contained in the Management Information Circular of Fortis dated March 15, 2019 for the May 2, 2019 annual meeting of shareholders.

Requests for additional copies of the above‑mentioned documents, as well as this 2019 Annual Information Form, should be directed to the Corporate Secretary, Fortis, P.O. Box 8837, St. John's, NL, A1B 3T2 (telephone: 709.737.2800).

ANNUAL INFORMATION FORM	36	December 31, 2019

EXHIBIT A: Summary of Terms and Conditions of Authorized Securities

Common Shares

Dividends on common shares are declared at the discretion of the Board. Holders of common shares are entitled to dividends on a pro rata basis if, as, and when declared by the Board. Subject to the rights of the holders of the first preference shares and second preference shares and any other class of shares of the Corporation entitled to receive dividends in priority to or ratably with the holders of the common shares, the Board may declare dividends on the common shares to the exclusion of any other class of shares of the Corporation.

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 preference shares 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.

Holders of the common shares are entitled to receive notice of and to attend all annual and special meetings of the shareholders of Fortis, other than separate meetings of holders of any other class or series of shares, and are entitled to one vote in respect of each Common Share held at such meetings.

Preference Shares

First Preference Shares

The following is a summary of the material rights, privileges, conditions and restrictions attached to the first preference shares as a class. The specific terms of the first preference shares, including the currency in which first preference shares may be purchased and redeemed and the currency in which any dividend is payable, if other than Canadian dollars, and the extent to which the general terms described herein apply to those first preference shares, is or will be as set forth in the applicable articles of amendment of Fortis relating to such series.

Issuance in Series

The Board may from time to time issue first preference shares in one or more series. Prior to issuing shares in a series, the Board is required to fix the number of shares in the series and determine the designation, rights, privileges, restrictions and conditions attaching to that series of first preference shares.

Priority

The shares of each series of first preference shares rank on a parity with the first preference shares of every other series and in priority to all other shares of Fortis, including the second preference shares, as to the payment of dividends, return of capital and the distribution of assets in the event of the liquidation, dissolution or winding-up of Fortis, whether voluntary or involuntary, or any other distribution of the assets of Fortis among its shareholders for the purpose of winding-up its affairs.

Each series of first preference shares participates ratably with every other series of first preference shares in respect of accumulated cumulative dividends and returns of capital, if any, cumulative dividends, whether or not declared and any amount payable on the return of capital in respect of a series of first preference shares, if not paid in full.

Voting

The holders of the first preference shares are not entitled to any voting rights as a class except to the extent that voting rights may from time to time be attached to any series of first preference shares, and except as provided by law or as described below under the heading "Modification". At any meeting of the holders of first preference shares, each holder shall have one vote in respect of each first preference share held.

ANNUAL INFORMATION FORM	37	December 31, 2019

Redemption

Subject to the provisions of the Corporations Act (Newfoundland and Labrador) and any provisions relating to any particular series, Fortis, upon giving proper notice, may redeem out of capital or otherwise at any time, or from time to time, the whole or any part of the then outstanding first preference shares of any one or more series on payment for each such first preference share at such price or prices as may be applicable to such series. Subject to the foregoing, if only a part of the then outstanding first preference shares of any particular series is at any time redeemed, the shares to be redeemed will be selected by lot in such manner as the directors or the transfer agent for the first preference shares, if any, decide, or if the directors so determine, may be redeemed pro rata, disregarding fractions.

Modification

The class provisions attached to the first preference shares may only be amended with the prior approval of the holders of the first preference shares, in addition to any other approvals required by the Corporations Act (Newfoundland and Labrador) or any other statutory provisions of like or similar effect in force from time to time.

The approval of the holders of the first preference shares with respect to any and all matters may be given by at least two-thirds of the votes cast at a meeting of the holders of the first preference shares duly called for that purpose.

First Preference Shares Authorized and Outstanding

The following table summarizes the series of first preference shares as of February 12, 2020.

	Authorized	Issued and Outstanding	Initial Yield (%)	Annual Dividend ($) ^(1)^	Reset Dividend Yield<br><br>(%)	Earliest Redemption and/or Conversion Option Date ^(2)^	Redemption Value ($)	Right to Convert on a One for One Basis
Perpetual Fixed Rate
Series F	5,000,000	5,000,000	4.90	1.2250	—	December 1, 2011	25.00	—
Series J ^(3)^	8,000,000	8,000,000	4.75	1.1875	—	December 1, 2017	25.50	—
Fixed Rate Reset ^(4) (5)^
Series G	9,200,000	9,200,000	5.25	1.0983	2.13	September 1, 2013	25.00	—
Series H	10,000,000	7,024,846	4.25	0.6250	1.45	June 1, 2015	25.00	Series I
Series K ^(6)^	12,000,000	10,000,000	4.00	0.9823	2.05	March 1, 2019	25.00	Series L
Series M ^(7)^	24,000,000	24,000,000	4.10	0.9783	2.48	December 1, 2019	25.00	Series N
Floating Rate Reset ^(5) (8)^
Series I ^(3)^	10,000,000	2,975,154	2.10	—	1.45	June 1, 2015	25.50	Series H
Series L	12,000,000	—	—	—	2.05	March 1, 2024	—	Series K
Series N	24,000,000	—	—	—	2.48	December 1, 2024	—	Series M
^(1)^	Holders are entitled to receive a fixed or floating cumulative quarterly cash dividend as and when declared by the Board, 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 were redeemable at $26.00 until December 1, 2018, decreasing by $0.25 each year until December 1, 2021 and redeemable at $25.00 per share thereafter. First Preference Shares, Series I are redeemable at $25.50 per share to but excluding June 1, 2020, and at $25.00 per share on June 1, 2020, and on every fifth anniversary date thereafter.
---	---
^(4)^	On the redemption and/or conversion option date and 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 K was reset from $1.0000 to $0.9823 for the five-year period from March 1, 2019 to but excluding March 1, 2024.
---	---
^(7)^	The annual dividend per share for the First Preference Shares, Series M was reset from $1.0250 to $0.9783 for the five-year period from December 1, 2019 to but excluding December 1, 2024.
---	---
ANNUAL INFORMATION FORM	38	December 31, 2019
---	---	---

^(8)^	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.

Second Preference Shares

The rights, privileges, conditions and restrictions attaching to the second preference shares are substantially identical to those attaching to the first preference shares, except that the second preference shares are junior to the first preference shares with respect to the payment of dividends, repayment of capital and the distribution of assets of Fortis in the event of a liquidation, dissolution or winding up of Fortis.

The specific terms of the second preference shares, including the currency in which second preference shares may be purchased and redeemed and the currency in which any dividend is payable, if other than Canadian dollars, and the extent to which the general terms described in herein apply to those second preference shares, will be as set forth in the applicable articles of amendment of Fortis relating to such series.

As of February 12, 2020, there were no second preference shares issued and outstanding.

ANNUAL INFORMATION FORM	39	December 31, 2019

EXHIBIT B: MARKET FOR SECURITIES

Common Shares

The common shares are traded on the TSX in Canada, and on the NYSE in the US, in each case under the symbol FTS. The following table sets forth the reported high and low trading prices and trading volumes, on a monthly basis for the year ended December 31, 2019, for the common shares on the TSX and NYSE in Canadian Dollars and US Dollars, respectively.

2019 Trading Prices and Volumes – Common Shares
	TSX			NYSE
Month	High ($)	Low ($)	Volume	High (US$)	Low (US$)	Volume
January	46.96	44.00	24,601,842	35.74	32.85	6,753,713
February	48.10	46.11	22,820,085	36.25	34.96	6,703,655
March	50.06	47.22	26,985,538	37.29	35.50	7,566,171
April	50.47	48.88	21,753,244	37.75	36.46	6,648,254
May	51.35	49.13	27,291,236	38.04	36.49	11,148,765
June	52.95	50.95	22,571,031	40.09	37.78	7,067,672
July	52.90	51.44	15,382,634	40.47	39.14	6,953,052
August	55.31	51.62	21,514,936	41.52	39.16	7,826,388
September	56.79	54.70	24,174,617	42.80	41.12	10,575,457
October	56.94	53.24	24,646,611	42.75	40.74	9,937,864
November	55.36	51.65	35,560,577	41.98	38.76	8,425,448
December	54.98	51.73	30,187,739	41.81	38.91	10,295,297

Preference Shares

The First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series I; First Preference Shares, Series J; First Preference Shares, Series K; and First Preference Shares, Series M of Fortis are listed on the TSX under the symbols FTS.PR.F; FTS.PR.G; FTS.PR.H; FTS.PR.I; FTS.PR.J; FTS.PR.K and FTS.PR.M, respectively.

The following tables set forth the reported high and low trading prices and volumes for the First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series I; First Preference Shares, Series J; First Preference Shares, Series K; and First Preference Shares, Series M on a monthly basis for the year ended December 31, 2019.

2019 Trading Prices and Volumes – First Preference Shares
	First Preference Shares, Series F			First Preference Shares, Series G
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	22.95	21.90	55,188	19.82	18.22	170,526
February	22.65	22.20	46,385	19.09	18.00	163,374
March	23.08	22.09	77,069	19.55	18.66	86,361
April	23.05	22.67	93,924	19.44	18.90	185,715
May	22.75	22.30	63,933	19.35	17.93	236,838
June	22.65	21.99	60,312	18.04	16.59	193,203
July	23.20	22.54	50,398	18.45	17.60	124,023
August	23.21	22.45	44,828	18.09	15.70	121,649
September	23.58	22.76	33,962	17.65	16.70	89,309
October	23.88	23.49	54,130	17.00	16.10	192,386
November	23.89	23.41	57,020	17.15	16.28	216,028
December	23.87	23.09	41,513	16.89	16.00	392,303
ANNUAL INFORMATION FORM	40	December 31, 2019
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	First Preference Shares, Series H			First Preference Shares, Series I
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	15.69	14.21	201,508	15.80	14.47	12,806
February	15.06	13.81	81,589	14.92	13.98	29,655
March	15.13	14.10	34,257	14.48	14.12	10,900
April	14.91	14.16	25,322	14.50	14.20	122,700
May	14.54	12.62	121,532	14.57	12.85	28,638
June	12.95	12.25	296,434	12.85	11.82	148,700
July	13.90	12.81	31,124	13.65	12.51	90,300
August	13.15	11.62	93,398	13.00	11.25	88,225
September	13.32	12.45	157,154	13.12	12.40	26,663
October	13.02	11.85	200,341	12.86	11.92	40,220
November	13.47	12.52	118,876	13.11	12.32	45,441
December	13.49	12.15	268,761	13.02	12.20	55,158
	First Preference Shares, Series J			First Preference Shares, Series K
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	22.08	21.25	63,951	18.96	16.87	89,759
February	21.90	21.27	116,814	18.01	16.63	120,848
March	22.13	21.35	466,001	18.02	17.37	231,559
April	22.00	21.67	172,394	18.31	17.38	104,410
May	21.93	21.33	126,314	18.08	16.20	127,202
June	21.72	21.24	223,502	16.79	15.41	263,218
July	22.20	21.75	80,749	17.70	16.80	102,296
August	22.18	21.44	116,863	16.94	15.00	140,985
September	22.21	21.55	610,780	16.70	15.52	133,391
October	22.58	22.05	265,996	16.25	15.20	229,073
November	22.60	22.19	117,437	16.61	15.70	179,504
December	22.50	22.06	164,666	16.55	15.40	182,757
	First Preference Shares, Series M
Month	High ($)	Low ($)	Volume
January	20.72	18.58	343,059
February	19.49	17.96	286,793
March	19.80	18.67	284,482
April	19.98	18.65	311,866
May	19.27	17.00	284,236
June	17.47	15.77	259,306
July	18.81	17.16	203,862
August	18.87	15.06	646,405
September	16.99	16.02	631,806
October	17.17	15.98	294,566
November	17.59	16.35	224,894
December	17.39	16.34	828,348
ANNUAL INFORMATION FORM	41	December 31, 2019
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EXHIBIT C: AUDIT COMMITTEE MANDATE

1.0	PURPOSE AND AUTHORITY

1.1 The purpose of the Committee is to assist the Board with its oversight of:

(a)	the integrity of the Corporation's financial statements, financial disclosures and internal controls over financial reporting;
(b)	the Corporation's compliance with related legal and regulatory requirements;
---	---
(c)	the qualifications, independence and performance of the Independent Auditor and Internal Auditor;
---	---
(d)	the related policies of the Corporation set out herein; and
---	---
(e)	other matters set out herein or otherwise delegated to the Committee by the Board.
---	---

1.2 Consistent with this purpose, the Committee should encourage continuous improvement of, and foster adherence to, the Corporation's policies, procedures and practices at all levels. The Committee should also provide for open communication among the Independent Auditor, the Internal Auditor, Management and the Board.

1.3 To perform its duties and responsibilities, the Committee has the authority to: (i) conduct investigations into any matters within its scope of responsibility; (ii) obtain advice and assistance from outside legal, accounting, or other advisors as the Committee may deem appropriate, in its sole discretion; and (iii) meet with and seek any information it requires from external parties or employees, officers and directors of the Corporation or any affiliate of the Corporation.

1.4 The Corporation will provide appropriate funding, as determined by the Committee, for compensation to the Independent Auditor, to any independent counsel or other advisors that the Committee chooses to engage, and for payment of ordinary administrative expenses of the Committee that are necessary and appropriate in carrying out its duties.

1.5 The Committee will primarily fulfill its responsibilities by carrying out the activities set out in this Mandate.

2.0	DEFINITIONS

2.1 In this Mandate:

(a) "Board" means the board of directors of the Corporation;

(b) "Chair" means the Chair of the Committee;

(c)	"Committee" means the audit committee appointed by the Board pursuant to this Mandate;
(d)	"Core Audit Services" means services necessary to: (i) audit the Corporation's annual consolidated or non-consolidated financial statements; (ii) review the Corporation's interim condensed consolidated financial statements; and (iii) audit internal controls over financial reporting in accordance with the requirements of the Sarbanes Oxley Act of 2002;
---	---

(e) "Corporation" means Fortis Inc.;

(f) "CPAB" means the Canadian Public Accountability Board or its successor;

ANNUAL INFORMATION FORM	42	December 31, 2019

(g) "Director" means a member of the Board;

(h)	"ERM Program" means the Corporation's Enterprise Risk Management Program that incorporates an effective risk management framework and applies a logical and systematic methodology to identify, evaluate, treat, monitor and communicate key corporate risks;
(i)	"Financial Expert" means an "audit committee financial expert" as defined in Item 407(d)(5) of SEC Regulation S‑K;
---	---
(j)	"Financially Literate" means having the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breath and complexity of the issues that can reasonably be expected to be present in the Corporation's financial statements;
---	---
(k)	"Governance and Nominating Committee" means the governance and nominating committee of the Board;
---	---
(l)	"Independent" means, in the context of a Member and in accordance with applicable law and stock exchange requirements, free from any direct or indirect material relationship with the Corporation and its subsidiaries which, in the view of the Board, could reasonably be expected to interfere with the exercise of a Member's independent judgment;
---	---
(m)	"Independent Auditor" means the firm of chartered professional accountants, registered with the CPAB and the PCAOB, and appointed by the Shareholders to act as external auditor;
---	---
(n)	"Internal Auditor" means the person(s) employed or engaged by the Corporation to perform the internal audit function of the Corporation;
---	---

(o) "Management" means the senior officers of the Corporation;

(p) "Mandate" means this mandate of the Committee;

(q)	"MD&A" means the Corporation's management discussion and analysis prepared in accordance with the requirements of National Instrument 51-102F1 and the SEC in respect of the Corporation's annual consolidated and interim condensed consolidated financial statements;

(r) "Member" means a Director appointed to the Committee;

(s) "NYSE" means the New York Stock Exchange;

(t)

"PCAOB" means the Public Company Accounting Oversight Board or its successor;

(u)

"Related Party Transactions" means those transactions required to be disclosed under Items 404(a) and 404(b) of SEC Regulation S-K and required to be evaluated by an appropriate group within the Corporation pursuant to Section 314.00 of the NYSE Listed Company Manual which, without limiting the foregoing, are transactions between: (i) executive officers, directors, principal shareholders or their immediate family members; and (ii) the Corporation;

---

(v) "SEC" means the United States Securities and Exchange Commission; and

(w) "Shareholders" means the shareholders of the Corporation.

ANNUAL INFORMATION FORM	43	December 31, 2019

3.0 ESTABLISHMENT AND COMPOSITION OF COMMITTEE

3.1 The Committee will be comprised of three (3) or more Directors, each of whom is Independent and Financially Literate. No Member may be a member of Management or an employee of the Corporation or of any affiliate of the Corporation. The Board will appoint to the Committee at least one Director who is a Financial Expert.

3.2 Members will be appointed by the Board at the annual organizational meeting of the Board, or at other times as may be necessary, provided, however, that if the appointment of Members is not so made at such a meeting, the Directors who are then serving as Members will continue as Members until their successors are appointed. Each Member shall serve until his or her successor is appointed, unless he or she shall resign or be removed by the Board or he or she shall otherwise cease to be a Director.

3.3 The Board may appoint a Member to fill a vacancy which occurs on the Committee between annual elections of Directors. If a vacancy exists on the Committee, the remaining Members will exercise all of the powers of the Committee so long as at least three (3) Members remain in office.

3.4 Any Member may be removed from the Committee by a resolution of the Board.

3.5 No Member will serve on more than three public company audit committees without the approval of the Board.

3.6 The Board will appoint a Chair on the recommendation of the Corporation’s Governance and Nominating Committee, or such other committee as the Board may authorize, provided, however, that if the appointment of the Chair is not so made, the Director who is then serving as Chair will continue as Chair until his or her successor is appointed. The Board will periodically rotate the Chair and will make reasonable efforts to rotate the Chair every four years. Such rotation will occur after the annual general meeting of Shareholders.

4.0	COMMITTEE MEETINGS

4.1 The Committee will meet at least quarterly and will meet at such other times during the year as it deems appropriate. Meetings of the Committee will be held at the call of: (i) the Chair; or (ii) any two Members; or (iii) the Independent Auditor; and may be held in-person, by means of remote communication or a combination thereof. The time and place of the meetings of the Committee and the procedures for such meetings will be determined by the Committee.

4.2 The Chief Executive Officer, the Chief Financial Officer, the Independent Auditor and the Internal Auditor will receive notice of and, unless otherwise determined by the Chair, will attend all meetings of the Committee. For clarity, the Independent Auditor must attend the Committee meetings at which the Corporation's annual audited consolidated and non-consolidated financial statements and interim unaudited condensed consolidated financial statements are reviewed.

4.3 A quorum at any meeting of the Committee will be at least three (3) or more Members.

4.4 Each Member will have the right to vote on matters that come before the Committee.

4.5 Any matter to be determined by the Committee will be decided by a majority of votes cast at a meeting of the Committee at which such matter is considered. Actions of the Committee may also be taken by an instrument or instruments in writing signed by all of the Members, and such actions will be effective as though they had been decided by a majority of votes cast at a meeting of the Committee called for such purpose.

4.6 The Chair will act as chair of all meetings of the Committee at which the Chair is present. In the absence of the Chair from any meeting of the Committee, the Members present at the meeting will appoint one of such Members to act as Chair of the meeting.

ANNUAL INFORMATION FORM	44	December 31, 2019

4.7 Unless otherwise determined by the Chair, the Corporate Secretary of the Corporation will act as secretary of all meetings of the Committee.

4.8 The Committee will periodically meet separately with Management, the Internal Auditor and the Independent Auditor to discuss any matters that the Committee or any of these persons or firms believes should be discussed privately.

5.0	SPECIFIC RESPONSIBILITIES AND DUTIES OF THE COMMITTEE

A. Independent Auditor

5.1 In consultation and coordination with the subsidiary audit committees, the Committee will be directly responsible for the appointment (through a recommendation to the Board for the appointment by Shareholders), compensation and retention of the Independent Auditor.

5.2 The Committee will oversee the work of the Independent Auditor in connection with the Core Audit Services and any other services performed for the Corporation. The Independent Auditor will report directly to the Committee and the Committee has the authority to communicate directly with the Independent Auditor.

5.3 The Committee will oversee the resolution of any disagreements between Management and the Independent Auditor. The Committee will discuss with the Independent Auditor the matters required to be discussed under PCAOB Auditing Standard No. 1301 relating to the conduct of the audit, including any problems or difficulties encountered and Management's responses thereto and any restrictions on the scope of activities or access to requested information.

5.4 The Committee will pre-approve all services performed by the Independent Auditor in accordance with the Corporation's Pre-Approval Policy for Independent Auditor Services. For any service, other than Core Audit Services, requiring specific pre-approval in accordance with such policy, the Committee may delegate pre-approval authority to one or more of its Members. Currently, pre-approval authority in this regard has been delegated to the Chair or, in that person's absence, the Chair of the Board who is a Member. Delegates must report all pre-approval decisions to the Committee at the next scheduled meeting.

5.5 The Committee will annually obtain and review a report from the Independent Auditor delineating all relationships between the Independent Auditor and the Corporation and its subsidiaries in accordance with Item 407(d) of SEC Regulation S-K and Section 303A.07 of the NYSE Listed Company Manual and addressing the matters set forth in PCAOB Rule 3526. The Committee will use reasonable efforts, including discussion with the Independent Auditor, to satisfy itself as to the Independent Auditor's independence in accordance with Canadian generally accepted auditing standards and PCAOB standards, the requirements and interpretative guidance of SEC Regulation S-X and any other applicable regulations and professional standards. The Committee will discuss any potential independence issues with the Board and recommend any commensurate action that the Committee deems appropriate.

5.6 The Committee will review and evaluate the qualifications and performance of the Independent Auditor and its lead engagement partner. Without limiting the generality of the foregoing, the Committee will:

(a)	review and discuss with Management and separately with the Independent Auditor the results of the Corporation's annual Independent Auditor assessment process; and
(b)	at least annually, obtain and review a report from the Independent Auditor describing the firm's internal quality control process and procedures, including any material issues raised by the most recent internal quality-control review or peer review, or by any inquiry or investigation by governmental or professional authorities (including without limitation the PCAOB and the CPAB) within the preceding five years with respect to independent audits carried out by the Independent Auditor, and any steps taken to deal with such issues.
---	---
ANNUAL INFORMATION FORM	45	December 31, 2019
---	---	---

The Committee will discuss any arising issues with the Board and recommend any commensurate action that the Committee deems appropriate.

5.7 The Committee will ensure the rotation of the audit partner(s) as required by applicable law and consider the need for rotation of the Independent Auditor.

5.8 The Committee will meet with the Independent Auditor prior to the audit to discuss the planning and staffing of the audit, including the general approach, scope, areas subject to significant risk of material misstatement, estimated fees and other terms of engagement.

B.	Financial Reporting

5.9 In consultation with Management, the Independent Auditor and the Internal Auditor, the Committee will review and satisfy itself as to: (i) the integrity of the Corporation's internal and external financial reporting processes; (ii) the adequacy and effectiveness of the Corporation's disclosure controls and procedures (including those pertaining to the review of disclosure containing financial information extracted or derived from the Corporation's financial statements) and internal controls over financial reporting; and (iii) the competence of the Corporation's personnel responsible for accounting and financial reporting. Without limiting the generality of the foregoing, the Committee will receive and review:

(a)	reports regarding: (i) critical accounting estimates, policies and practices; (ii) goodwill impairment testing; (iii) derivatives and hedges; and (iv) the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the Corporation's financial statements;
(b)	analyses by Management and the Independent Auditor regarding significant financial reporting issues and judgements made in connection with the preparation of the Corporation's consolidated financial statements including: (i) alternative treatments of financial information within generally accepted accounting principles related to material matters that have been discussed with Management, their ramifications and the treatment preferred by the Independent Auditor; (ii) major issues regarding accounting principles and presentations, including significant changes in the selection or application of accounting principles; and (iii) major issues regarding the adequacy of the Corporation's internal controls and any specific audit steps adopted in light of material weaknesses or significant deficiencies in internal controls; and
---	---
(c)	other material written communication between Management and the Independent Auditor.
---	---

5.10 The Committee will, prior to external release if applicable, review and discuss with Management and the Independent Auditor, and with others as it deems appropriate:

(a)	the Corporation's annual audited consolidated and non-consolidated financial statements and interim unaudited condensed consolidated financial statements and the Independent Auditor's related attestation reports as well as any related MD&As;
(b)	Management's report and the Independent Auditor's audit report on internal controls over financial reporting;
---	---
(c)	significant reports or summaries thereof pertaining to the Corporation's processes for compliance with the requirements of the Sarbanes Oxley Act of 2002 with respect to internal controls over financial reporting;
---	---
(d)	the Independent Auditor's quarterly review reports and annual audit results report summarizing the scope, status, results and recommendations of the quarterly reviews of the Corporation's interim condensed consolidated financial statements and of the audit of the Corporation's annual consolidated financial statements and related audit of internal controls over financial reporting, and also containing at least: (i) the communications with respect thereto between the Independent Auditor and the
---	---
ANNUAL INFORMATION FORM	46	December 31, 2019
---	---	---

Committee required by PCAOB Auditing Standard No. 1301 and any other applicable regulations and professional standards, including without limitation schedules of corrected and uncorrected account and disclosure misstatements and significant deficiencies and material weaknesses in internal controls; (ii) the (at least) annual independence communication required by PCAOB Rule 3526; (iii) the Management representation letter; and (iv) the documentation and communication required quarterly from the Independent Auditor under the Corporation's Pre-Approval Policy for Independent Auditor Services;

(e)	the Report to Shareholders contained in the Corporation's annual report; and
(f)	any other document that the Committee determines should be reviewed and discussed with Management and the Independent Auditor or for which a legal or regulatory requirement in that regard exists.
---	---

5.11 The Committee will, prior to external release, review and discuss with Management and with others as it deems appropriate, the financial information to be disclosed in the Corporation's interim and annual earnings media releases or other media releases.

5.12 The Committee will recommend the Corporation's annual audited consolidated financial statements together with the Independent Auditor's audit report thereon and on internal controls over financial reporting, Management's report on internal controls over financial reporting, MD&A, earnings media release, and Report to Shareholders for approval by the Board and subsequent external release as well as inclusion of the noted financial statements in the Corporation's annual report on Form 40-F. The Committee will approve the external release of the Corporation's interim unaudited condensed consolidated financial statements and related interim MD&As and earning media releases on behalf of the Board.

5.13 The Committee will, prior to external release, review and discuss with Management and with others as it deems appropriate, and recommend for approval by the Board:

(a)any earnings and dividend guidance to be provided by the Corporation;

(b)	the Annual Information Form and Management Information Circular to be filed by the Corporation;
(c)	any prospectus or other offering documents and documents related thereto for the issuance of securities by the Corporation; and
---	---
(d)	other financial information and disclosure documents to be released publicly.
---	---

5.14 The Committee will review, and discuss with Management and with others as it deems appropriate, the disclosures made by the Chief Executive Officer and Chief Financial Officer of the Corporation pursuant to their certification of the Corporation's annual and quarterly reports regarding significant deficiencies or material weaknesses in the design or operation of internal controls over financial reporting and any fraud involving Management or other employees.

5.15 The Committee will use reasonable efforts to satisfy itself as to the appropriateness of the Corporation's material financing and tax structures.

5.16 The Committee will review, and discuss with Management and with others as it deems appropriate, financial information provided to analysts and ratings agencies. Such discussions may be in general terms (i.e. discussion of the types of information to be disclosed and the types of presentations to be made) and need not occur in advance of each release of information.

5.17 The Committee will prepare, or cause to be prepared, any reports of the Committee required to be included in the Corporation's public disclosures or otherwise required by applicable law.

ANNUAL INFORMATION FORM	47	December 31, 2019

5.18 The Committee will review, discuss with Management and with others as it deems appropriate, and approve all Related Party Transactions and the disclosure thereof.

C. Internal Audit

5.19 The Committee will be responsible for the oversight of the Internal Auditor in accordance with the Policy on the Role of the Internal Audit Function and has the authority to communicate directly with the Internal Auditor.

5.20 The Committee will review, discuss with the Internal Auditor and others as it deems appropriate and approve the annual internal audit plan.

5.21 The Committee will review and discuss with Management and the Internal Auditor and others as it deems appropriate the quarterly internal audit reports prepared for the Committee (which will incorporate all significant activities of the internal audit function for the quarter) and any Management responses thereto.

5.22 The Committee will periodically discuss with the Internal Auditor any significant difficulties, disagreements with Management, or scope restrictions encountered in the course of carrying out the work of the internal audit function.

5.23 The Committee will periodically discuss with the Internal Auditor the internal audit function’s responsibility, budget and staffing.

5.24 The Committee will satisfy itself as to the performance of the internal audit function and the qualifications of its staff.

D. Risk Management and Other

5.25 The Committee will be responsible for the oversight of the Corporation's ERM Program.

5.26 The Committee will review and discuss with Management, the Internal Auditor and others as it deems appropriate Management's report regarding identifying, assessing and addressing significant risks and related matters pursuant to the ERM Program.

5.27 The Committee will review and discuss with Management and others as it deems appropriate the quarterly report prepared by Management regarding significant litigation and other significant legal matters that could have a significant impact on the Corporation or its financial statements.

5.28 The Committee will be responsible for the oversight of the Corporation's insurance program.

E.	Policies and Mandate

5.29 The Committee is responsible for the oversight of the following policies:

(a)	Policy on Reporting Allegations of Suspected Improper Conduct and Wrongdoing (including overseeing procedures for the receipt, retention, and treatment of complaints regarding accounting, internal controls, or auditing matters as well as procedures for confidential, anonymous submissions by employees regarding questionable accounting or auditing matters as required by applicable law);
(b)	Derivative Instruments and Hedging Policy;
---	---
(c)	Pre-Approval Policy for Independent Auditor Services;
---	---
(d)	Hiring from Independent Auditing Firms Policy;
---	---
(e)	Policy on the Role of the Internal Audit Function;
---	---
ANNUAL INFORMATION FORM	48	December 31, 2019
---	---	---

(f)	Disclosure Policy; and
(g)	other policies that may be established from time-to-time regarding accounting, financial reporting, disclosure controls and procedures, internal controls over financial reporting, oversight of the external audit of the Corporation's financial statements, and oversight of the internal audit function.
---	---

5.30 The Committee will periodically review this Mandate and the policies in Section 5.29 and recommend any necessary amendments to the Governance and Nominating Committee for consideration and recommendation to the Board as deemed appropriate.

6.0 REPORTING

6.1 The Chair, or another designated Member, shall report to the Board at each regular meeting on those matters that were dealt with by the Committee since the last regular meeting of the Board.

7.0 REMUNERATION OF MEMBERS

7.1 Members and the Chair will receive such remuneration for their service on the Committee as the Board may determine from time to time, having considered the recommendation of the Committee.

7.2 No Member may earn fees from the Corporation or any of its subsidiaries other than Directors' fees (which fees may include a combination of cash, benefits, deferred share units and common shares or other equity securities of the Corporation). For greater certainty, no Member will accept, directly or indirectly, any consulting, advisory or other compensatory fee from the Corporation.

8.0 GENERAL

8.1 This Mandate will be posted on the Corporation's corporate website at www.fortisinc.com.

8.2 The Committee will annually review its own effectiveness and performance.

8.3 The Committee will perform any other activities consistent with this Mandate, the Corporation’s bylaws and applicable law that the Board or Committee determines are necessary or appropriate.

8.4 The Committee is not responsible for certifying the accuracy or completeness of the Corporation's financial statements or their presentation in accordance with generally accepted accounting principles, or for guaranteeing the accuracy of the attestation reports of the Independent Auditor. The fundamental responsibility for the Corporation's financial statements and disclosures and internal controls over financial reporting rests with Management and, in accordance with its professional responsibilities, the Independent Auditor. Nothing in this Mandate is intended to modify or augment the obligations of the Corporation or the fiduciary duties of the Committee or the Board under applicable law.

ANNUAL INFORMATION FORM	49	December 31, 2019

EXHIBIT D: MATERIAL CONTRACTS

The following are the material contracts of Fortis filed on SEDAR and EDGAR during 2019 or which were entered into prior to 2019 and are still in effect. Requests for additional copies of these material contracts should be directed to the Corporate Secretary, Fortis, P.O. Box 8837, St. John's, NL, A1B 3T2 (telephone: 709.737.2800). All such contracts are also available under the Corporation's profile at www.sedar.com and www.sec.gov.

Revolving Credit Facility

Fortis is a party to a Third Amended and Restated Credit Facility dated July 31, 2017, with The Bank of Nova Scotia as underwriter, sole lead arranger and bookrunner and administrative agent and Canadian Imperial Bank of Commerce and Royal Bank of Canada as co-syndication agents, and the lenders party thereto from time to time, as amended by the First Amending Agreement dated May 11, 2018 and the Second Amending Agreement dated May 13, 2019, each between Fortis, The Bank of Nova Scotia and the lenders named therein. The Third Amended and Restated Credit Facility is a $1.3 billion unsecured committed revolving credit facility and contains the terms and conditions upon which such credit is available to Fortis during the duration of the facility. The Third Amended and Restated Credit Facility contains customary representations and warranties, affirmative and negative covenants and events of default. Customary fees are payable by Fortis in respect of the facility and amounts outstanding under the facility bear interest at market rates.

Shareholders' Agreement

On October 14, 2016, ITC Investment Holdings, ITC Holdings, FortisUS and Eiffel Investment Pte Ltd (an affiliate of GIC and successor to Finn Investment Pte Ltd) entered into a Shareholders' Agreement which governs the rights of the parties in their respective capacities as direct or indirect shareholders of ITC Holdings. The Shareholders' Agreement provides certain customary rights to Eiffel Investment Pte Ltd, including the right to appoint one director to the boards of ITC Investment Holdings and ITC Holdings as long as it owns at least 9.95% (except in specified instances of dilution) of the outstanding common stock of ITC Investment Holdings.

Under the terms of the Shareholders' Agreement, Eiffel Investment Pte Ltd has certain minority approval rights relating to ITC Investment Holdings and ITC Holdings, subject to maintenance of certain ownership thresholds with respect to ITC Investment Holdings, including with respect to: (i) amendments to charter documents; (ii) changes in board size; (iii) issuances of equity; (iv) business combinations that would impact Eiffel Investment Pte Ltd differently than other shareholders; (v) insolvency; (vi) certain acquisitions of, investments in, or joint ventures relating to non-core assets, or certain material sales or dispositions of core assets; (vii) in limited circumstances, the incurrence of indebtedness by ITC Investment Holdings, ITC Holdings or its subsidiaries or the taking of certain actions that would reasonably be expected to result in the long-term unsecured indebtedness of ITC Investment Holdings, ITC Holdings and its subsidiaries being rated below investment grade; (viii) actions that would cause a ratio of ITC Holding's cash flow to debt to exceed an agreed targeted threshold; (ix) limitations on corporate overhead costs paid by ITC Holdings to Fortis; and (x) expansion of the core business outside ITC Holdings' current regulatory jurisdictions. The Shareholders' Agreement also provides for a dividend policy, which can be amended only with the approval of all the independent directors of ITC Investment Holdings.

Indenture and First Supplemental Indenture

On October 4, 2016, Fortis entered into an Indenture and a First Supplement thereto with The Bank of New York Mellon, as US trustee, and BNY Trust Company of Canada, as Canadian co-trustee. The Indenture and the First Supplement set forth the terms of the Corporation's outstanding US$1.1 billion aggregate principal amount of 3.055% Unsecured Notes due 2026. The Indenture contains customary covenants, events of default and rights for the benefit of security holders and the trustees. An unlimited amount of debt securities may be issued under the Indenture, which is governed by the laws of the State of New York.

ANNUAL INFORMATION FORM	50	December 31, 2019

	Exhibit

Exhibit 99.2

FORTIS INC.

Audited Consolidated Financial Statements

As at and for the years ended December 31, 2019 and 2018

Management's Report on Internal Control over Financial Reporting		i	NOTE 11	Property, Plant and Equipment	25
Report of Independent Registered Public Accounting Firm - Opinion on the<br><br>Financial Statements		ii	NOTE 12	Intangible Assets	27
Report of Independent Registered Public Accounting Firm - Opinion on Internal<br><br>Control over Financial Reporting		v	NOTE 13	Goodwill	28
Consolidated Balance Sheets		1	NOTE 14	Accounts Payable and Other Current Liabilities	28
Consolidated Statements of Earnings		2	NOTE 15	Long-Term Debt	29
Consolidated Statements of Comprehensive<br><br>Income		2	NOTE 16	Leases	32
Consolidated Statements of Cash Flows		3	NOTE 17	Other Liabilities	34
Consolidated Statements of Changes in Equity		4	NOTE 18	Common Shares	35
Notes to Consolidated Financial Statements			NOTE 19	Earnings Per Common Share	35
NOTE 1	Description of Business	5	NOTE 20	Preference Shares	36
NOTE 2	Regulation	6	NOTE 21	Accumulated Other Comprehensive Income	37
NOTE 3	Summary of Significant Accounting Policies	10	NOTE 22	Stock-Based Compensation Plans	37
NOTE 4	Future Accounting Pronouncements	18	NOTE 23	Disposition	41
NOTE 5	Segmented Information	19	NOTE 24	Other Income, Net	41
NOTE 6	Revenue	21	NOTE 25	Income Taxes	41
NOTE 7	Accounts Receivable and Other Current Assets	22	NOTE 26	Employee Future Benefits	43
NOTE 8	Inventories	22	NOTE 27	Supplementary Cash Flow Information	48
NOTE 9	Regulatory Assets and Liabilities	23	NOTE 28	Fair Value of Financial Instruments and Risk Management	48
NOTE 10	Other Assets	25	NOTE 29	Commitments and Contingencies	52

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, 2019, 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, 2019, the Corporation's ICFR was effective.

The Corporation's ICFR as of December 31, 2019 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, 2019. Deloitte LLP issued an unqualified opinion for both audits.

February 12, 2020

/s/ Barry V. Perry

Barry V. Perry

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, 2019 and 2018, 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, 2019, 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, 2019 and 2018, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2019, 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, 2019, 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 12, 2020, 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 13 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 the reporting units included the following, among others:

•	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:
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•	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:
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•	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.
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Impact of Rate Regulation on the Financial Statements - Refer to Notes 2, 3 and 9 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 its inherent complexities across different jurisdictions.

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.
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iii
---

•	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.
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/s/ Deloitte LLP

Chartered Professional Accountants

St. John’s, Canada

February 12, 2020

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, 2019, 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, 2019, 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 at and for the year ended December 31, 2019, of the Corporation and our report dated February 12, 2020, 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 12, 2020

v

FORTIS INC.
Consolidated Balance Sheets
As at December 31
(in millions of Canadian dollars)
	2019		2018
ASSETS
Current assets
Cash and cash equivalents	$	370	$	332
Accounts receivable and other current assets (Note 7)	1,297		1,357
Prepaid expenses	88		84
Inventories (Note 8)	394		398
Regulatory assets (Note 9)	425		324
Assets held for sale (Note 23)	—		766
Total current assets	2,574		3,261
Other assets (Note 10)	620		552
Regulatory assets (Note 9)	2,958		2,751
Property, plant and equipment, net (Note 11)	33,988		32,757
Intangible assets, net (Note 12)	1,260		1,200
Goodwill (Note 13)	12,004		12,530
Total assets	$	53,404	$	53,051
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings (Note 15)	$	512	$	60
Accounts payable and other current liabilities (Note 14)	2,378		2,289
Regulatory liabilities (Note 9)	572		656
Current installments of long-term debt (Note 15)	690		926
Current installments of finance leases (Note 16)	24		252
Liabilities associated with assets held for sale (Note 23)	—		69
Total current liabilities	4,176		4,252
Other liabilities (Note 17)	1,446		1,138
Regulatory liabilities (Note 9)	2,786		2,970
Deferred income taxes (Note 25)	2,969		2,686
Long-term debt (Note 15)	21,501		23,159
Finance leases (Note 16)	413		390
Total liabilities	33,291		34,595
Commitments and contingencies (Note 29)
Equity
Common shares (Note 18) ^(1)^	13,645		11,889
Preference shares (Note 20)	1,623		1,623
Additional paid-in capital	11		11
Accumulated other comprehensive income (Note 21)	336		928
Retained earnings	2,916		2,082
Shareholders' equity	18,531		16,533
Non-controlling interests	1,582		1,923
Total equity	20,113		18,456
Total liabilities and equity	$	53,404	$	53,051
^(1)^ No par value. Unlimited authorized shares; 463.3 million and 428.5 million issued and outstanding as at December 31, 2019 and 2018, 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

FORTIS INC.
Consolidated Statements of Earnings
For the years ended December 31
(in millions of Canadian dollars, except per share amounts)
		2019		2018
Revenue (Note 6)		$	8,783	$	8,390
Expenses
Energy supply costs		2,520		2,495
Operating expenses		2,452		2,287
Depreciation and amortization		1,350		1,243
Total expenses		6,322		6,025
Gain on disposition (Note 23)		577		—
Operating income		3,038		2,365
Other income, net (Note 24)		138		60
Finance charges		1,035		974
Earnings before income tax expense		2,141		1,451
Income tax expense (Note 25)		289		165
Net earnings		$	1,852	$	1,286
Net earnings attributable to:
	Non-controlling interests	$	130	$	120
	Preference equity shareholders	67		66
	Common equity shareholders	1,655		1,100
		$	1,852	$	1,286
Earnings per common share (Note 19)
Basic		$	3.79	$	2.59
Diluted		$	3.78	$	2.59
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)
	2019			2018
Net earnings	$	1,852		$	1,286
Other comprehensive (loss) income
Unrealized foreign currency translation (losses) gains, net of hedging activities and income tax (expense) recovery of (13) million and 11 million, respectively	(660		)	985
Other, net of income tax recovery (expense) of 5 million and (2) million, respectively	(7		)	6
	(667		)	991
Comprehensive income	$	1,185		$	2,277
Comprehensive income attributable to:
	$	55		$	244
	67			66
	1,063			1,967
	$	1,185		$	2,277
See accompanying Notes to Consolidated Financial Statements

All values are in US Dollars.

FORTIS INC.
Consolidated Statements of Cash Flows
For the years ended December 31
(in millions of Canadian dollars)
			2019			2018
Operating activities
Net earnings			$	1,852		$	1,286
Adjustments to reconcile net earnings to net cash provided by
operating activities:
		Depreciation - property, plant and equipment	1,199			1,107
		Amortization - intangible assets	125			106
		Amortization - other	26			30
		Deferred income tax expense (Note 25)	247			136
		Equity component, allowance for funds used during construction<br><br>(Note 24)	(74		)	(64		)
		Gain on disposition (Note 23)	(583		)	—
		Other	145			92
Change in long-term regulatory assets and liabilities			(106		)	13
Change in working capital (Note 27)			(168		)	(102		)
Cash from operating activities			2,663			2,604
Investing activities
Capital expenditures - property, plant and equipment			(3,499		)	(3,032		)
Capital expenditures - intangible assets			(221		)	(186		)
Contributions in aid of construction			102			106
Proceeds on disposition (Note 23)			995			—
Other			(145		)	(140		)
Cash used in investing activities			(2,768		)	(3,252		)
Financing activities
Proceeds from long-term debt, net of issuance costs (Note 15)			937			1,566
Repayments of long-term debt, net of extinguishment costs, and finance leases			(1,676		)	(563		)
Borrowings under committed credit facilities			5,892			5,666
Repayments under committed credit facilities			(6,290		)	(5,523		)
Net change in short-term borrowings			472			38
Issue of common shares, net of costs, and dividends reinvested (Note 18)			1,442			34
Dividends
	Common shares, net of dividends reinvested		(494		)	(459		)
	Preference shares		(67		)	(66		)
	Subsidiary dividends paid to non-controlling interests		(73		)	(85		)
Other			11			36
Cash from financing activities			154			644
Effect of exchange rate changes on cash and cash equivalents			(26		)	24
Change in cash and cash equivalents			23			20
Cash and change in cash associated with assets held for sale			15			(15		)
Cash and cash equivalents, beginning of year			332			327
Cash and cash equivalents, end of year			$	370		$	332
Supplementary Cash Flow Information (Note 27)
See accompanying Notes to Consolidated Financial Statements

FORTIS INC.
Consolidated Statements of Changes in Equity
For the years ended December 31, 2019 and 2018
(in millions of Canadian dollars, except share numbers)
	Common Shares<br><br>(# millions)	Common<br><br>Shares<br><br>(Note 18)		Preference Shares<br><br>(Note 20)		Additional Paid-In<br><br>Capital			Accumulated Other Comprehensive Income (Loss)<br><br>(Note 21)			Retained<br><br>Earnings			Non-Controlling<br><br>Interests			Total<br><br>Equity
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
Subsidiary dividends paid to non-controlling interests	—	—		—		—			—			—			(73		)	(73		)
Dividends declared on common shares ($1.855 per share)	—	—		—		—			—			(821		)	—			(821		)
Dividends declared on preference shares	—	—		—		—			—			(67		)	—			(67		)
Disposition (Note 23)	—	—		—		—			—			—			(318		)	(318		)
Other	—	—		—		5			—			—			(5		)	—
As at December 31, 2019	463.3	$	13,645	$	1,623	$	11		$	336		$	2,916		$	1,582		$	20,113
As at December 31, 2017	421.1	$	11,582	$	1,623	$	10		$	61		$	1,727		$	1,746		$	16,749
Net earnings	—	—		—		—			—			1,166			120			1,286
Other comprehensive income	—	—		—		—			867			—			124			991
Common shares issued	7.4	307		—		(1		)	—			—			—			306
Subsidiary dividends paid to non-controlling interests	—	—		—		—			—			—			(85		)	(85		)
Dividends declared on common shares ($1.75 per share)	—	—		—		—			—			(745		)	—			(745		)
Dividends declared on preference shares	—	—		—		—			—			(66		)	—			(66		)
Other	—	—		—		2			—			—			18			20
As at December 31, 2018	428.5	$	11,889	$	1,623	$	11		$	928		$	2,082		$	1,923		$	18,456
See accompanying Notes to Consolidated Financial Statements

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

1. DESCRIPTION OF BUSINESS

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

Regulated Utilities

ITC: Comprised of 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: Comprised of 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

3,143

megawatts ("MW"), including 59 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: Comprised of FortisBC Energy Inc., which is the largest regulated distributor of natural gas in British Columbia, providing 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: Comprised of FortisBC Inc., 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: Comprised of utilities in eastern Canada and the Caribbean, 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") (Note 10); 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") (Note 10).

5

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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

140

MW. FortisOntario is comprised 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 of connecting remote First Nations communities to the electricity grid in Ontario through the development of new transmission lines.

In January 2019 Fortis reduced its equity investment in Wataynikaneyap Partnership from

49%

39%

to facilitate the inclusion of two additional First Nations communities into the partnership.

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 is comprised 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: Comprised of 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 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 (Note 23).

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"). Under PBR mechanisms, formulae are generally applied that incorporate 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 9).

6

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

ITC

ITC is regulated by the Federal Energy Regulatory Commission ("FERC") under the Federal Power Act (United States). Rates are set annually, using FERC-approved cost-based formula rate templates, and remain in effect for one year, which provides timely cost recovery. An annual true-up mechanism compares actual revenue requirements to billed revenues, and any variances are accrued and reflected in future rates within a two-year period. The formula rates do not require annual FERC approvals, although inputs remain subject to legal challenge by customers with FERC. ITC's allowed ROE ranged from

9.88%

up to a maximum of

12.24%

with incentive adders on a capital structure of

60%

common equity for 2019 and 2018, reflecting the impact of a November 2019 order discussed below under "ROE Complaints".

Incentive Adder Complaint

In April 2018 a third-party complaint was filed with FERC challenging the independence incentive adders that are included in transmission rates charged by ITCTransmission, METC and ITC Midwest (collectively, "ITC's MISO Subsidiaries"), which operate in the Midcontinent Independent System Operator ("MISO") region. The adder allowed up to

0.50%

1.00%

to be added to the authorized ROE, subject to any ROE cap established by FERC. In October 2018 FERC issued an order reducing the adders to

0.25%

, effective April 20, 2018. This equated to a

0.25%

decrease in ROE, down from the approximate

0.50%

that ITC was earning in rates previously approved by FERC. ITC began reflecting the

0.25%

adder in transmission rates in November 2018. ITC's MISO Subsidiaries sought rehearing of this order in 2018, which was denied by FERC. In September 2019 ITC's MISO Subsidiaries filed an appeal in the U.S. Court of Appeal. The final resolution of this matter is not expected to have a material impact on the Corporation's earnings or cash flows.

ROE Complaints

Two third-party complaints requested that the base ROE for MISO transmission owners, including ITC's MISO Subsidiaries, be found to no longer be just or reasonable. The complaints cover two consecutive 15-month periods from November 2013 through February 2015 (the "Initial Refund Period" or "Initial Complaint") and February 2015 through May 2016 (the "Second Refund Period" or "Second Complaint").

In June 2016 the presiding Administrative Law Judge ("ALJ") issued an initial decision on the Second Complaint, recommending a base ROE of

9.70%

, up to a maximum of

10.68%

with incentive adders. Pending an order from FERC, an estimated regulatory liability of $206 million (US$151 million) had been recognized as at December 31, 2018 based on the ALJ's initial decision (Note 9).

In September 2016 FERC ordered that the base ROE for the Initial Refund Period be set at

10.32%

, down from

12.38%

, up to a maximum of

11.35%

with incentive adders. The resultant rates applied prospectively from September 2016 until an approved ROE was established for the Second Refund Period. The total refund for the Initial Complaint as a result of the September 2016 FERC order was $158 million (US$118 million), including interest, and was paid in 2017.

In November 2019 FERC issued a decision on ITC's ROE Complaints ("November 2019 FERC Order"), which determined that the base ROE for the Initial Complaint and from September 2016 onward be

9.88%

, up to a maximum of

12.24%

with incentive adders. FERC also dismissed the Second Complaint, resulting in a ROE for that period of

12.38%

plus incentive adders with no refund required. In addition, as an ROE complaint had not been filed for the period of May 2016 to September 2016, the ROE for that period continued to be

12.38%

plus incentive adders with no refund required. The regulated utilities in the MISO region, including ITC, sought rehearing of this order on the basis that it will not allow utilities to earn a reasonable rate of return on investment. In January 2020 FERC issued an order granting the rehearing for further consideration, effectively extending FERC's review.

As at December 31, 2019, a regulatory liability of $91 million (US$70 million) was recognized related to the impact of the November 2019 FERC Order on the Initial Refund Period and for the period from September 2016 to December 2019 (Note 9). Additionally, the regulatory liability of $206 million (US$151 million) as at December 31, 2018 (Note 9), related to the Second Complaint, was reversed in 2019. The net impact of the November 2019 FERC Order was an increase in revenue and a decrease in interest expense resulting in an increase in net earnings of $79 million of which Fortis' share was $63 million. The favourable impact was comprised of: (i) $83 million related to the net reversal of liabilities established in prior periods; partially offset by (ii) $20 million related to the 2019 impact of a reduced ROE.

7

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

Based on the outcome of the request for rehearing, it is possible the ROE and refunds could materially change from those recognized in 2019.

Notices of Inquiry

In March 2019 FERC issued a notice of inquiry ("NOI") seeking comments on whether and how to improve its electric transmission incentives policy. The outcome may impact the existing incentive adders that are included in transmission rates charged by transmission owners, including ITC. Also in March 2019, FERC issued a second NOI seeking comments on whether and how recent policies concerning the determination of the base ROE for electric utilities should be modified. The comment period for both NOI proceedings has ended. The outcome may impact ITC's future ROE and incentive adders.

UNS Energy

UNS Energy is regulated by the Arizona Corporation Commission ("ACC") and certain activities are subject to regulation by FERC under the Federal Power Act (United States). UNS Energy uses a historical test year to establish retail electricity and gas rates.

TEP's rates reflect an allowed ROE of

9.75%

on a capital structure of approximately

50%

common equity. Effective August 1, 2016, UNS Electric's rates reflect an allowed ROE of

9.5%

on a capital structure of

52.8%

common equity. Effective May 1, 2012, UNS Gas' rates reflect an allowed ROE of

9.75%

on a capital structure of

50.8%

common equity.

General Rate Application

In April 2019 TEP filed a general rate application with the ACC requesting an increase in non-fuel revenue of US$99 million, effective May 1, 2020, with electricity rates based on a 2018 historical test year. Intervenor testimony in relation to TEP's revenue requirement and rate design was filed in October 2019. The application, adjusted for rebuttal testimony filed by TEP in November 2019, includes a request to increase TEP's allowed ROE to

10.00%

from

9.75%

and the equity component of its capital structure to

53%

from

50%

on a rate base of US$2.7 billion. Hearings before the ALJ commenced in January and a decision is expected by mid-2020.

Central Hudson

Central Hudson is regulated by the New York State Public Service Commission ("PSC") and certain activities are subject to regulation by FERC under the Federal Power Act (United States). Central Hudson uses a future test year to establish rates.

Pursuant to a three-year settlement agreement arising from a 2017 general rate application, Central Hudson's rates reflect an allowed ROE of

8.8%

on a capital structure of

48%

49%

and

50%

common equity as of July 1, 2018, 2019 and 2020, respectively. Prior thereto, effective July 1, 2015, Central Hudson's allowed ROE was

9.0%

on a capital structure of

48%

common equity.

Central Hudson is also subject to an earnings sharing mechanism whereby the Company and its customers share equally earnings between 50 and 100 basis points above the allowed ROE. Earnings beyond that are primarily returned to customers.

FortisBC Energy and FortisBC Electric

FortisBC Energy and FortisBC Electric are regulated by the British Columbia Utilities Commission ("BCUC") pursuant to the Utilities Commission Act (British Columbia), and are subject to multi-year PBR plans whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula is applied annually to the previous year's rates to establish new rates for the remainder of the multi-year period.

The PBR plans for the most recent term of 2014 through 2019 incorporate incentive mechanisms for improving operating and capital expenditure efficiencies. Operation and maintenance expenses and base capital expenditures during the PBR period are subject to an incentive formula reflecting incremental costs for inflation and half of customer growth, less a fixed productivity adjustment factor of

1.1%

for FortisBC Energy and

1.03%

for FortisBC Electric each year. The approved PBR plans also include a 50/50 sharing of variances from the formula‑driven operation and maintenance expenses and capital expenditures over the PBR period, and a number of service quality measures designed to ensure FortisBC Energy and FortisBC Electric maintain specified service levels.

8

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

FortisBC Energy is the benchmark utility in British Columbia, as designated by the BCUC, and effective January 1, 2016, its rates reflected an allowed ROE of

8.75%

on a capital structure of

38.5%

common equity. Effective January 1, 2016, FortisBC Electric's rates reflected an allowed ROE of

9.15%

on a capital structure of

40%

common equity.

In March 2019 FortisBC Energy and FortisBC Electric filed applications with the BCUC requesting approval of a multi-year rate plan and PBR methodology for 2020-2024. A decision is expected in mid-2020.

FortisAlberta

FortisAlberta is regulated by the Alberta Utilities Commission ("AUC") pursuant to the Electric Utilities Act (Alberta), the Public Utilities Act (Alberta), the Hydro and Electric Energy Act (Alberta) and the Alberta Utilities Commission Act (Alberta). FortisAlberta is subject to multi-year PBR plans for 2018-2022 whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula is applied annually to the previous year's rates to establish new rates for the remainder of the multi-year period.

The PBR plans include mechanisms for the recovery or settlement of items determined to flow through directly to customers ("Y factor") and the recovery of costs related to capital expenditures that are not being recovered through the formula ("capital tracker" or "K-bar"). It also includes a Z factor, a PBR re-opener, and an efficiency carry-over mechanism. The Z factor permits an application for recovery of costs, subject to certain thresholds, related to significant unforeseen events. The PBR re-opener permits, subject to certain thresholds, an application to re-open and review the PBR plan to address specific problems with its design or operation. The efficiency carry-over mechanism provides an efficiency incentive by permitting the Company to continue to benefit from any efficiency gains achieved during the PBR term for two years following the end of that term.

Pursuant to generic cost of capital proceedings completed in 2018, FortisAlberta's rates reflect an allowed ROE of

8.5%

on a capital structure of

37%

common equity for 2018-2020, unchanged from 2017.

Second-Term Performance-Based Rate-Setting Proceeding

The AUC has ongoing proceedings to review regulatory applications for rebasing inputs included in PBR rates for 2018-2022, including anomaly-related adjustments and approved changes to depreciation parameters.

In January 2020 the AUC issued two decisions: (i) confirming that changes to depreciation parameters will be incorporated into incremental funding mechanisms; and (ii) establishing new criteria for anomaly-related adjustments. PBR utilities in Alberta are permitted to file depreciation studies by July 2020 and were required to submit their intent to file an anomaly-related adjustment application by February 7, 2020. FortisAlberta does not anticipate filing a depreciation study in 2020 and did notify the AUC of its intent to file an anomaly-related adjustment application.

Generic Cost of Capital Proceeding

In December 2018 the AUC initiated a generic cost of capital proceeding to consider a formula-based approach to setting the allowed ROE beginning in 2021 and whether any process changes are necessary for determining capital structure in years in which a ROE formula is in place. In April 2019 the AUC determined that a traditional non-formulaic approach for assessing ROE and deemed capital structure would be used in 2021, with consideration of a formula-based approach for determining the allowed ROE for 2022 and subsequent years. Expert evidence was filed in January 2020 with an oral hearing scheduled for April 2020. An AUC decision is expected later in 2020.

2018 Alberta Independent System Operator Tariff Application

In September 2019 the AUC issued a decision that addressed, among other things, a proposal to change how the Alberta Electric System Operator's customer contribution policy is accounted for between distribution facility owners, such as FortisAlberta, and transmission facility owners ("TFO"). The decision prevents any future investment by FortisAlberta under the policy and directs that the 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.

9

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

In October 2019 FortisAlberta filed evidence to oppose the decision. Implementation of the order has been suspended and the decision remains under review by the AUC. It is expected that the decision will remain under review through the first quarter of 2020. The likely outcome of this process and potential impacts, if any, cannot be determined at this time.

Other Electric

Newfoundland Power is regulated by the Newfoundland and Labrador Board of Commissioners of Public Utilities under the Public Utilities Act (Newfoundland and Labrador) and uses a future test year to establish rates. Effective 2019 to 2020, and consistent with 2018, Newfoundland Power's rates reflect an allowed ROE of

8.5%

on a capital structure of

45%

common equity.

Maritime Electric is regulated by the Island Regulatory and Appeals Commission under the provisions of the Electric Power Act (PEI), the Renewable Energy Act (PEI) and the Electric Power (Electricity Rate-Reduction) Amendment Act (PEI), and uses a future test year to establish rates. Effective March 1, 2019 for a three-year period, and consistent with 2018, Maritime Electric's rates reflect an allowed ROE of

9.35%

on a capital structure of

40%

common equity.

FortisOntario's three electric utilities are regulated by the Ontario Energy Board under the Electricity Act (Ontario) and the Ontario Energy Board Act (Ontario). Two of FortisOntario's utilities use a future test year to establish rates under five-year PBR plans whereby a going-in revenue requirement is first established and used to set initial rates and thereafter a prescribed formula using inflationary factors less an efficiency target is applied annually to the previous year's rates to establish new rates for the remainder of the five-year period. The allowed ROEs ranged from

8.78%

9.30%

for both 2019 and 2018, on a capital structure of

40%

common equity. FortisOntario's remaining utility is subject to a 35-year franchise agreement, expiring in 2033, whereby rates are based on a price cap with commodity cost flow through and with the base revenue requirement adjusted annually for inflation, load growth and customer growth.

Caribbean Utilities 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. It is regulated under a rate‑cap adjustment mechanism based on published consumer price indices. The licences detail the role of the Cayman Islands Utility Regulation and Competition Office, which oversees all licences, establishes and enforces licence standards, reviews the rate-cap adjustment mechanism, and annually approves capital expenditures. Its allowed ROA for 2019 was in the range of

7.50%

9.50%

(

7.00%

9.00%

for 2018).

FortisTCI operates under 50-year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037. Rates reflect a historical test year and a targeted allowed ROA of between

15.0%

and

17.5%

(the "Allowable Operating Profit"). The Allowable Operating Profit is based on a calculated rate base, including interest on the cumulative amount by which actual operating profits fall short of the Allowable Operating Profit (the "Cumulative Shortfall"). The calculated Allowable Operating Profit and Cumulative Shortfall are submitted to the Government annually. The recovery of the Cumulative Shortfall is dependent on future sales volumes and expenses. The achieved ROAs at the utilities have been significantly lower than those allowed as a result of the inability, due to economic and political factors, to increase rates to support significant capital investment in recent years.

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.

10

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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 23). 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 Doubtful Accounts

Fortis and each subsidiary, other than ITC, maintain an allowance for doubtful accounts that is estimated based on a variety of factors, including receivables aging, historical experience, specific events such as customer bankruptcy and economic conditions. ITC recognizes losses for uncollectible accounts based upon their specific identification. 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.

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) an obligation 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 9) 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.

11

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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 totalling $40 million (2018 - $31 million) is reported as a reduction of finance charges and the equity component is reported as other income (Note 24). 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 the Alberta Electric System Operator ("AESO") toward funding the construction of transmission facilities (Note 2).

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 2019 ranged from

0.9%

35.0%

(2018 -

0.9%

34.6%

). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was

2.6%

for 2019 (2018 –

2.5%

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

		2019		2018
(years)		Service Life Ranges	Weighted Average Remaining Service Life	Service Life Ranges	Weighted Average Remaining Service Life
Distribution
	Electric	5-80	32	5-80	33
	Gas	15-95	36	14-95	35
Transmission
	Electric	20-90	43	20-90	42
	Gas	5-85	32	5-85	41
Generation		1-85	25	1-85	24
Other		3-70	14	3-70	15

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%

50.0%

for 2019 (2018 –

1.0%

50.0%

12

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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

	2019		2018
(years)	Service Life Ranges	Weighted Average Remaining Service Life	Service Life Ranges	Weighted Average Remaining Service Life
Computer software	3-10	4	3-10	4
Land, transmission and water rights	43-90	58	36-90	57
Other	10-100	12	10-100	13

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.

Goodwill

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

Impairment testing is performed if an event or change in circumstances indicates that the fair value of a reporting unit may be below its carrying value. If so determined, goodwill is written down to estimated fair value and an impairment loss is recognized.

Otherwise, Fortis performs an annual assessment for each of the 11 reporting units having goodwill. The Corporation performs a qualitative assessment for certain reporting units and if it is determined that it is not likely that fair value is less than carrying value then a quantitative estimate of the fair value is not required. Otherwise, the primary method for estimating the fair value of the reporting units is the income approach, whereby net cash flow projections are discounted using an enterprise value method. 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 method, the market approach along with a reconciliation of the total estimated fair value of all 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.

13

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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 9).

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 9).

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. Revenue is 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.

14

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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 6). This represents the level of disaggregation used by the Corporation's President and Chief Executive Officer ("CEO") to allocate resources and evaluate performance.

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, all representing cash-settled awards, at fair value at each reporting date until settlement. 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, 2019 was

$53.97

(December 31, 2018 -

$45.14

). 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, 2019 was US$1.00=CAD$

1.30

(December 31, 2018 – US$1.00=CAD$

1.36

Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which was US$1.00=CAD$

1.33

for 2019 (2018 - US$1.00=CAD$

1.30

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.

15

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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 thereto recognized as regulatory assets or liabilities for recovery from, or refund to, customers in future rates (Note 9).

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.

Derivatives Designated as Hedges

The Corporation, ITC and UNS Energy use cash flow hedges 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 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, 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, for the 50-year term of its PPAs, BECOL are not subject to income tax.

Differences between the income tax expense or recovery recognized under US GAAP and that 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 9).

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.

16

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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 $2.8 billion as at December 31, 2019 (December 31, 2018 - $2.3 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.

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, right-of-ways 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 17) 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

Leases

Effective January 1, 2019, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-02, Leases, that requires lessees to recognize a right-of-use asset and lease liability for all leases with a lease term greater than 12 months, along with additional disclosures (Note 16).

At lease inception, 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.

17

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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.

Fortis applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods in accordance with the modified retrospective approach. Fortis elected a package of implementation options, referred to as practical expedients, that allowed it to not reassess: (i) whether existing contracts, including land easements, are or contain a lease; (ii) the classification of existing leases; or (iii) the initial direct costs for existing leases. Fortis also utilized the hindsight practical expedient to determine the lease term. Upon adoption, Fortis did not identify or record an adjustment to the opening balance of retained earnings, and there was no impact on net earnings or cash flows.

Hedging

Effective January 1, 2019, the Corporation adopted ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, which better aligns risk management activities and financial reporting for hedging relationships through changes to designation, measurement, presentation and disclosure guidance. Adoption did not have a material impact on the consolidated financial statements and related disclosures.

Fair Value Measurement Disclosures

Effective January 1, 2019, the Corporation adopted ASU No. 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement, which improves the effectiveness of financial statement note disclosures by clarifying what is required and important to users of the financial statements. The adoption of this ASU removed the following disclosures for all periods presented: (i) the amount of, and reasons for, transfers between level 1 and level 2 of the fair value hierarchy; (ii) the policy for the timing of transfers between levels; and (iii) the valuation processes for level 3 fair value measurements.

Pensions and Other Post-Retirement Plan Disclosures

Effective December 31, 2019, the Corporation early adopted, on a retrospective basis, ASU No. 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans, which modifies the disclosure requirements for employers with defined pension or other post-retirement plans and clarifies disclosure requirements. In particular, it removed the following disclosures: (i) the amounts in accumulated other comprehensive income expected to be recognized as components of net period benefit costs over the next fiscal period; and (ii) the effects of a one-percentage-point change on the assumed health care costs and the change in rates on service cost, interest cost and the benefit obligation for post-retirement health care benefits (Note 26).

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.

4. FUTURE ACCOUNTING PRONOUNCEMENTS

Income Taxes

ASU No. 2019-12, Simplifying the Accounting for Income Taxes, issued in December 2019, is effective for Fortis January 1, 2021, with early adoption permitted. Principally, it improves consistent application of, and clarifies, existing income tax guidance. Fortis is assessing the impact that adoption will have on its consolidated financial statements.

18

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

5. SEGMENTED INFORMATION

General

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

Related-party and inter-company transactions

Inter-company balances, transactions and profit are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities, which are summarized below.

(in millions)	2019		2018
Sale of capacity from Waneta Expansion to FortisBC Electric ^(1)^	$	17	$	47
Lease of gas storage capacity and gas sales from Aitken Creek to<br><br>FortisBC Energy	23		25
^(1)^	Reflects amounts to the April 16, 2019 disposition of the Waneta Expansion (Note 23)
---	---

As at December 31, 2019, accounts receivable included approximately $8 million due from Belize Electricity (December 31, 2018 - $16 million).

The Corporation periodically provides short-term financing to subsidiaries to support capital expenditures, acquisitions and seasonal working capital requirements. As at December 31, 2019, there were inter-segment loans outstanding of $279 million (December 31, 2018 - $nil), payable on demand with a weighted average interest rate of

2.48%

. Total interest charged in 2019 was $2 million.

19

FORTIS INC.<br><br>NOTES TO CONSOLIDATED FINANCIAL STATEMENTS<br><br>For the years ended December 31, 2019 and 2018
	REGULATED																NON-REGULATED
---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---	---
Year Ended																	Energy						Inter-
December 31, 2019			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	$	1,761	$	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<br><br>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
Year Ended
December 31, 2018
(in millions)
Revenue	$	1,504	$	2,202	$	924	$	1,187	$	579	$	408	$	1,412	$	8,216	$	184		$	—		$	(10	)	$	8,390
Energy supply costs	—		868		315		322		—		135		853		2,493		2			—			—			2,495
Operating expenses	448		609		410		308		167		105		182		2,229		40			28			(10		)	2,287
Depreciation and amortization	234		272		71		219		192		61		160		1,209		32			2			—			1,243
Operating income	822		453		128		338		220		107		217		2,285		110			(30		)	—			2,365
Other income, net	40		10		7		7		1		3		1		69		1			(10		)	—			60
Finance charges	285		104		41		134		100		40		76		780		6			188			—			974
Income tax expense	139		66		20		55		1		14		22		317		6			(158		)	—			165
Net earnings	438		293		74		156		120		56		120		1,257		99			(70		)	—			1,286
Non-controlling interests	77		—		—		1		—		—		15		93		27			—			—			120
Preference share dividends	—		—		—		—		—		—		—		—		—			66			—			66
Net earnings attributable<br><br>to common equity shareholders	$	361	$	293	$	74	$	155	$	120	$	56	$	105	$	1,164	$	72		$	(136	)	$	—		$	1,100
Goodwill	$	8,369	$	1,884	$	615	$	913	$	227	$	235	$	260	$	12,503	$	27		$	—		$	—		$	12,530
Total assets	19,798		10,182		3,670		6,815		4,691		2,244		4,119		51,519		1,478			127			(73		)	53,051
Capital expenditures	998		599		245		486		433		106		300		3,167		44			7			—			3,218
20
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

6. REVENUE

(in millions)	2019		2018
Electric and gas revenue
United States
ITC	$	1,697	$	1,539
UNS Energy	1,966		1,993
Central Hudson	894		963
Canada
FortisBC Energy	1,289		1,136
FortisAlberta	576		554
FortisBC Electric	362		354
Newfoundland Power	671		651
Maritime Electric	209		200
FortisOntario	206		197
Caribbean
Caribbean Utilities	270		253
FortisTCI	85		78
Total electric and gas revenue	8,225		7,918
Other services revenue^(1)^	374		408
Revenue from contracts with customers	8,599		8,326
Alternative revenue ^(2)^	116		16
Other revenue	68		48
Total revenue	$	8,783	$	8,390
^(1)^	Includes $273 million and $234 million from regulated operations for 2019 and 2018, respectively
---	---
^(2)^	Includes a $91 million adjustment associated with the November 2019 FERC Order (Notes 2 and 9)
---	---

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.

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; (iii) the sale of energy from non-regulated generation operations, including the Waneta Expansion up to its disposition on April 16, 2019 (Note 23); and (iv) 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 Corporation's significant alternative revenue programs 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 9). The formula rates do not require annual regulatory approvals, although inputs remain subject to legal challenge.

21

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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.

At FortisBC Energy and FortisBC Electric, the earnings sharing mechanism allows for a 50/50 sharing of variances from operating and maintenance expenses and capital expenditures approved as part of the annual revenue requirement. This mechanism was in place until the expiry of the current PBR plan in 2019. Additionally, variances in the forecast versus actual customer-use rates are captured throughout the year in a revenue stabilization adjustment mechanism and a flow-through deferral account, both of which are either refunded to, or recovered from, customers in rates within two years.

Other Revenue

Other revenue primarily includes gains or losses on energy contract derivatives and lease revenue.

7. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS

(in millions)	2019			2018
Trade accounts receivable	$	504		$	538
Unbilled accounts receivable	601			575
Allowance for doubtful accounts	(35		)	(33		)
Total accounts receivable	1,070			1,080
Income tax receivable	35			91
Other ^(1)^	192			186
	$	1,297		$	1,357
^(1)^	Consists mainly of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases at FortisBC Energy, and the fair value of derivative instruments (Note 28)
---	---

8. INVENTORIES

(in millions)	2019		2018
Materials and supplies	$	294	$	280
Gas and fuel in storage	69		87
Coal inventory	31		31
	$	394	$	398
22
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

9. REGULATORY ASSETS AND LIABILITIES

(in millions)	2019			2018
Regulatory assets
Deferred income taxes (Notes 3 and 25)	$	1,556		$	1,532
Employee future benefits (Notes 3 and 26)	530			485
Deferred energy management costs (i)	279			230
Rate stabilization and related accounts (ii)	208			90
Derivatives (Notes 3 and 28)	119			57
Deferred lease costs (iii)	116			110
Generation early retirement costs (iv)	88			98
Manufactured gas plant site remediation deferral (Note 17)	81			73
Other regulatory assets (v)	406			400
Total regulatory assets	3,383			3,075
Less: Current portion	(425		)	(324		)
Long-term regulatory assets	$	2,958		$	2,751
Regulatory liabilities
Deferred income taxes (Notes 3 and 25)	$	1,440		$	1,574
Asset removal cost provision (Note 3)	1,187			1,169
Rate stabilization and related accounts (ii)	166			220
Energy efficiency liability (vi)	101			106
Renewable energy surcharge (vii)	94			85
ROE complaints liability (Note 2)	91			206
Electric and gas moderator account (viii)	45			60
Employee future benefits (Notes 3 and 26)	45			37
Other regulatory liabilities (v)	189			169
Total regulatory liabilities	3,358			3,626
Less: Current portion	(572		)	(656		)
Long-term regulatory liabilities	$	2,786		$	2,970

(i) 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 1 to 10 years.

(ii)	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 resulting from 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 6).

(iii)	Deferred Lease Costs

Deferred lease costs at FortisBC Electric primarily relate to the Brilliant Power Purchase Agreement ("BPPA") (Note 16). 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.

23

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018
(iv)	Generation Early Retirement Costs
---	---

UNS Energy holds an undivided interest in the jointly owned Navajo Generating Station ("Navajo"), located on a site leased from the Navajo Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allowed TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. TEP and the co-owners retired Navajo in November 2019, with related decommissioning activities continuing through 2054, and the capital and operating costs are being recovered through 2030.

UNS Energy owns the Sundt Generating Facility ("Sundt") and was required to retire Sundt Units 1 and 2 in November 2019. Capital and operating costs related to Sundt Units 1 and 2 are being recovered through 2028 and 2030, respectively.

Due to the early retirement of Navajo and Sundt, TEP requested recovery of final retirement costs over a 10-year period in the 2019 general rate application.

(v)	Other Regulatory Assets and Liabilities

These balances are comprised of regulatory assets and liabilities individually less than $40 million.

(vi)	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.

(vii)	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 ("REC"). 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 10) with a corresponding regulatory liability to reflect the obligation to use the RECs for future RES compliance. When RECs are reported to the ACC for compliance with RES requirements, energy supply costs and revenue are recognized in an equal amount.

(viii)	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 $1,510 million and $1,490 million as at December 31, 2019 and 2018, 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.

24

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

10. OTHER ASSETS

(in millions)	2019		2018
Supplemental Executive Retirement Plan	$	145	$	143
Renewable Energy Credits (Note 9 (vii))	99		88
Equity investment - Belize Electricity	71		76
Employee future benefits (Note 26)	63		27
Operating leases (Note 16)	46		—
Other investments	43		34
Deferred compensation plan	30		26
Equity Investment - Wataynikaneyap Partnership	12		43
Other ^(1)^	111		115
	$	620	$	552
^(1)^	Includes the fair value of derivatives (Note 28)
---	---

ITC, UNS Energy and Central Hudson provide additional post-employment benefits through Supplemental Executive Retirement Plans ("SERPs") and deferred compensation plans for Directors and Officers. The assets held to support these plans are reported separately from the related liabilities (Note 17). 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 28). Included in SERP assets are available-for-sale securities at ITC of $70 million (2018 - $72 million), for which gains and losses are recognized in earnings.

11. PROPERTY, PLANT AND EQUIPMENT

(in millions)		Cost		Accumulated Depreciation			Net Book Value
2019
Distribution
	Electric ^(1)^	$	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
25
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018
(in millions)		Cost		Accumulated Depreciation			Net Book Value
---	---	---	---	---	---	---	---	---
2018
Distribution
	Electric^(1)^	$	11,000	$	(3,093	)	$	7,907
	Gas	4,767		(1,244		)	3,523
Transmission
	Electric	14,665		(3,212		)	11,453
	Gas	2,214		(639		)	1,575
Generation		6,164		(2,279		)	3,885
Other		3,877		(1,251		)	2,626
Assets under construction		1,478		—			1,478
Land		310		—			310
		$	44,475	$	(11,718	)	$	32,757
^(1)^	Includes FortisAlberta's deferred operating overhead costs of $121 million (December 31, 2018 - $103 million), representing costs related to the construction of PPE that are deferred for collection in future customer rates over the lives of the related PPE. These costs were reclassified to PPE from long-term regulatory assets to provide greater comparability between subsidiaries.
---	---

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 the Aitken Creek natural gas storage facility.

As at December 31, 2019 and 2018, assets under construction were primarily associated with ongoing transmission projects at ITC and the addition of gas-fired generating capacity at UNS Energy.

The cost of PPE under finance lease as at December 31, 2019 was $514 million (December 31, 2018 -$656 million) and related accumulated depreciation was $206 million (December 31, 2018 - $203 million) (Note 16).

26

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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, 2019, interests in jointly owned facilities consisted of the following.

	Ownership			Accumulated			Net Book
(in millions, except as noted)	%	Cost		Depreciation			Value
San Juan Unit 1	50.0	$	377	$	(251	)	$	126
Four Corners Units 4 and 5	7.0	234		(100		)	134
Luna Energy Facility	33.3	74		(1		)	73
Gila River Common Facilities	50.0	105		(35		)	70
Springerville Coal Handling Facilities	83.0	270		(117		)	153
Transmission Facilities	1.0-80.0	982		(384		)	598
		$	2,042	$	(888	)	$	1,154

12. INTANGIBLE ASSETS

			Accumulated			Net Book
(in millions)	Cost		Amortization			Value
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
			Accumulated			Net Book
---	---	---	---	---	---	---	---
(in millions)	Cost		Amortization			Value
2018
Computer software	$	860	$	(533	)	$	327
Land, transmission and water rights	855		(125		)	730
Other	120		(58		)	62
Assets under construction	81		—			81
	$	1,916	$	(716	)	$	1,200

Included in the cost of land, transmission and water rights as at December 31, 2019 was $133 million (December 31, 2018 - $131 million) not subject to amortization. Amortization expense was $125 million for 2019 (2018 - $106 million). Amortization is estimated to average approximately $77 million for each of the next five years.

27

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

13. GOODWILL

(in millions)	2019			2018
Balance, beginning of year	$	12,530		$	11,644
Acquisition of distribution systems by FortisAlberta	1			—
Foreign currency translation impacts ^(1)^	(527		)	886
Balance, end of year	$	12,004		$	12,530
^(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 2019 or 2018.

14. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES

(in millions)	2019		2018
Trade accounts payable	$	754	$	679
Employee compensation and benefits payable	229		193
Dividends payable	228		199
Customer and other deposits	226		267
Gas and fuel cost payable	225		281
Accrued taxes other than income taxes	223		206
Interest payable	212		230
Fair value of derivatives (Note 28)	83		69
Manufactured gas plant site remediation (Note 17)	31		32
Employee future benefits (Note 26)	24		25
Other	143		108
	$	2,378	$	2,289
28
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

15. LONG-TERM DEBT

(in millions)		Maturity Date	2019			2018
ITC
Secured US First Mortgage Bonds -
	4.46% weighted average fixed rate (2018 - 4.51%)	2020-2055	$	2,624		$	2,652
Secured US Senior Notes -
	4.26% weighted average fixed rate (2018 - 4.19%)	2040-2049	747			648
Unsecured US Senior Notes -
	3.79% weighted average fixed rate (2018 - 3.91%)	2020-2043	3,312			3,751
Unsecured US Shareholder Note -
	6.00% fixed rate (2018 - 6.00%)	2028	258			271
Unsecured US Term Loan Credit Agreement -
	2.35% weighted average fixed rate	2021	260			—
UNS Energy
Unsecured US Tax-Exempt Bonds - 4.64% weighted
	average fixed and variable rate (2018 - 4.66%)	2020-2040	603			654
Unsecured US Fixed Rate Notes -
	4.38% weighted average fixed rate (2018 - 4.38%)	2021-2048	1,851			1,943
Central Hudson
Unsecured US Promissory Notes - 4.27% weighted
	average fixed and variable rate (2018 - 4.43%)	2020-2059	986			938
FortisBC Energy
Unsecured Debentures -
	4.87% weighted average fixed rate (2018 - 5.03%)	2026-2049	2,795			2,595
FortisAlberta
Unsecured Debentures -
	4.64% weighted average fixed rate (2018 - 4.64%)	2024-2052	2,185			2,185
FortisBC Electric
Secured Debentures -
	8.80% fixed rate (2018 - 8.80%)	2023	25			25
Unsecured Debentures -
	5.05% weighted average fixed rate (2018 - 5.05%)	2021-2050	710			710
Other Electric
Secured First Mortgage Sinking Fund Bonds -
	6.14% weighted average fixed rate (2018 - 6.14%)	2020-2057	571			578
Secured First Mortgage Bonds -
	5.66% weighted average fixed rate (2018 - 5.66%)	2025-2061	220			220
Unsecured Senior Notes -
	4.45% weighted average fixed rate (2018 - 4.45%)	2041-2048	152			152
Unsecured US Senior Loan Notes and Bonds - 4.53% weighted
	average fixed and variable rate (2018 - 4.76%)	2020-2049	645			584
Corporate
Unsecured US Senior Notes and Promissory Notes -
	3.80% weighted average fixed rate (2018 - 3.41%)	2020-2044	2,903			4,398
Unsecured Debentures -
	6.50% fixed rate (2018 - 6.50%)	2039	200			200
Unsecured Senior Notes - 2.85% fixed rate (2018 - 2.85%)		2023	500			500
Long-term classification of credit facility borrowings			640			1,066
Fair value adjustment - ITC acquisition			133			161
Total long-term debt (Note 28)			22,320			24,231
Less: Deferred financing costs and debt discounts			(129		)	(146		)
Less: Current installments of long-term debt			(690		)	(926		)
			$	21,501		$	23,159
29
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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 at the Corporation have covenants that (i) restrict the issuance of additional debt such that the consolidated debt to consolidated capitalization ratio does not exceed

70%

at any time, and (ii) 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 %)	Month Issued	Interest Rate<br><br>(%)		Maturity	Amount		Use of Proceeds
ITC
Secured notes	January	4.55		2049	US	50	^(1) (2) (3)^
Unsecured term loan credit agreement ^(4)^	June	^(5)^		2021	US	200	^(6)^
Secured notes	July	4.65		2049	US	50	^(1) (2) (3)^
First mortgage bonds	August	3.30		2049	US	75	^(1) (2) (3)^
Central Hudson
Unsecured notes	October	3.89		2049	US	50	^(2) (3) (6)^
Unsecured notes	October	3.99		2059	US	50	^(2) (3) (6)^
FortisBC Energy
Unsecured debentures	August	2.82		2049	200		^(1)^
FortisTCI
Unsecured non-revolving term loan	February	^(7^	^)^	2025	US	5	^(2) (3)^
Caribbean Utilities
Unsecured notes	May	4.14		2049	US	40	^(1) (3) (6)^
Unsecured notes	August	4.14		2049	US	20	^(2) (3) (6)^
Unsecured notes	August	3.83		2039	US	20	^(2) (3) (6)^
^(1)^	Repay credit facility borrowings
---	---
^(2)^	Finance capital expenditures
---	---
^(3)^	General corporate purposes
---	---
^(4)^	Maximum amount of borrowings under this agreement is US$400 million; in January 2020 the remaining US$200 million was drawn to repay outstanding commercial paper balances
---	---
^(5)^	Floating rate of a one-month LIBOR plus a spread of 0.60%
---	---
^(6)^	Repay maturing long-term debt
---	---
^(7)^	Floating rate of a one-month LIBOR plus a spread of 1.75%
---	---

Fortis used the proceeds from the disposition of the Waneta Expansion (Note 23) to repay credit facility borrowings and repurchase, via a tender offer, US$400 million of its outstanding

3.055%

unsecured senior notes due in 2026. A gain on the repayment of debt of $11 million ($7 million after tax), net of expenses, was recognized in other income, net (Note 24).

Fortis used the proceeds from the issuance of common shares (Note 18) to redeem the US$500 million,

2.10%

unsecured notes that were due in 2021, to repay credit facility borrowings, and for general corporate purposes.

30

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

In January 2020 ITC entered into an unsecured term loan credit agreement, due in January 2021, under which the maximum amount of US$75 million was borrowed. The proceeds were used to repay credit facility borrowings.

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.

	Total
(year)	(in millions)
2020	$	690
2021	872
2022	1,146
2023	1,553
2024	1,106
Thereafter	16,953
	$	22,320

Credit Facilities

As at December 31, 2019, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.6 billion, of which approximately $4.3 billion was unused, including $1.3 billion unused under the Corporation's committed revolving corporate credit facility.

The following summarizes the credit facilities of the Corporation and its subsidiaries.

(in millions)	Regulated<br>Utilities			Corporate<br>and Other			2019			2018
Total credit facilities	$	4,209		$	1,381		$	5,590		$	5,165
Credit facilities utilized:
Short-term borrowings ^(1)^	(512		)	—			(512		)	(60		)
Long-term debt^^(including current portion) ^(2)^	(640		)	—			(640		)	(1,066		)
Letters of credit outstanding	(64		)	(50		)	(114		)	(119		)
Credit facilities unutilized	$	2,993		$	1,331		$	4,324		$	3,920

^(1)^The weighted average interest rate was approximately

3.2%

(December 31, 2018 -

4.2%

^(2)^	The weighted average interest rate was approximately 2.4% (December 31, 2018 - 3.3%). The current portion was $252 million (December 31, 2018 - $735 million).

Credit facilities are syndicated primarily with large banks in Canada and the United States, with no one bank holding more than

20%

of the total facilities. Approximately $5.1 billion of the total credit facilities are committed facilities with maturities ranging from 2020-2024.

31

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

Consolidated credit facilities of approximately $5.6 billion as at December 31, 2019 are itemized below.

(in millions)	Amount		Maturity
Unsecured committed revolving credit facilities
Regulated utilities
ITC ^(1)^	US	900	October 2022
UNS Energy	US	500	October 2022
Central Hudson	US	250	(2)
FortisBC Energy	700		August 2024
FortisAlberta	250		August 2024
FortisBC Electric	150		April 2024
Other Electric	190		(3)
Other Electric ^(4)^	US	50	January 2020
Corporate and Other	1,350		(5)
Other facilities
UNS Energy - unsecured non-revolving facility	US	225	December 2020
Central Hudson - uncommitted credit facility	US	40	n/a
FortisBC Electric - unsecured demand overdraft facility	10		n/a
Other Electric - unsecured demand facilities	20		n/a
Other Electric - unsecured demand facility and emergency<br><br>standby loan	US	60	April 2020
Corporate and Other - unsecured non-revolving facility	31		n/a
^(1)^	ITC also has a US$400 million commercial paper program, under which US$200 million was outstanding as at December 31, 2019, which is reported in short-term borrowings.
---	---
^(2)^	US$50 million in July 2020 and US$200 million in October 2020
---	---
^(3)^	$40 million in June 2021, $50 million in February 2022 and $100 million in August 2024
---	---
^(4)^	Subsequent to year end, facility was increased to US$70 million and the maturity date extended to January 2025
---	---
^(5)^	$50 million in April 2022 and $1.3 billion in July 2024 with the option to increase by an amount up to $500 million
---	---

16. LEASES

The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 22 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 lease premises.

The Corporation's subsidiaries also have finance leases related to generating facilities with remaining terms of up to 36 years.

32

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

Leases were presented on the consolidated balance sheet as follows.

(in millions)	2019
Operating leases
Other assets	$	46
Accounts payable and other current liabilities	(8		)
Other liabilities	(38		)
Finance leases ^(1) (2) (3)^
Regulatory assets	$	116
PPE, net	308
Current installments of finance leases	(24		)
Finance leases	(413		)
^(1)^	FortisBC Electric has a finance lease for the BPPA (Note 9 (iii)), 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)^	TEP is party to two Springerville Common Facilities leases with fixed purchase options and initial terms to January 2021. During 2019 TEP exercised its option to purchase a 32.2% undivided interest in the Springerville Common Facilities by January 2021 for $88 million.
---	---
^(3)^	In December 2019 TEP exercised its option to purchase Gila River Unit 2 for $212 million.
---	---
The components of lease expense were as follows.
---	---	---
(in millions)	2019
Operating lease cost	$	10
Finance lease cost:
Amortization	17
Interest	48
Variable lease cost	39
Total lease cost	$	114

Operating lease cost in 2018 was $10 million.

As at December 31, 2019, the present value of minimum lease payments was as follows.

(in millions)	Operating Leases			Finance<br><br>Leases			Total
2020	$	10		$	56		$	66
2021	8			121			129
2022	7			33			40
2023	6			33			39
2024	4			33			37
Thereafter	22			1,083			1,105
	57			1,359			1,416
Less: Imputed interest	(11		)	(922		)	(933		)
Total lease obligations	46			437			483
Less: Current installments	(8		)	(24		)	(32		)
	$	38		$	413		$	451
33
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

As at December 31, 2018, the present value of minimum lease payments was as follows.

	Total
(year)	(in millions)
2019	$	313
2020	77
2021	80
2022	49
2023	47
Thereafter	1,885
	2,451
Less: Imputed interest and executory costs	(1,809		)
Total capital lease and finance obligations	642
Less: Current installments	(252		)
	$	390
Supplemental lease information was as follows.
---	---	---	---
(in millions, except as indicated)	2019
Weighted average remaining lease term (years)
Operating leases	10
Finance leases	27
Weighted average discount rate (%)
Operating leases	4.1
Finance leases	4.8
Cash payments related to lease liabilities
Operating cash flows used for operating leases	$	(10	)
Operating cash flows used for finance leases	(47		)
Financing cash flows used for finance leases	(16		)
Investing cash flows used for finance leases	(212		)

See Note 27 for non-cash transactions that resulted in right-of-use assets obtained in exchange for new lease liabilities.

OTHER LIABILITIES	(in millions)	2019		2018
Employee future benefits (Note 26)	$	832	$	741
AROs (Note 3)	148		111
Stock-based compensation plans (Note 22)	83		56
Customer and other deposits	70		57
Fair value of derivatives (Note 28)	68		30
Manufactured gas plant site remediation (i)	48		32
Mine reclamation obligations (ii)	43		40
Operating leases	38		—
Finance obligations (iii)	38		—
Deferred compensation plan (Note 10)	33		29
Other	45		42
	$	1,446	$	1,138
34
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018
(i)	Environmental regulations require Central Hudson to investigate sites at which the Company 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, 2019, an obligation of $74 million (US$57 million) was recognized, including a current portion of $26 million (US$20 million) recognized in accounts payable and other current liabilities (Note 14). 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 9).
---	---
(ii)	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 $74 million (US$57 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.
---	---
(iii)	Between 2000 and 2005 FortisBC Energy entered into arrangements whereby certain natural gas distribution assets were leased to certain municipalities and then leased back by FortisBC Energy. These assets are integral equipment to real estate assets and the transactions have been accounted for as finance transactions, with the proceeds thereof recognized as finance obligations. Lease payments, net of the portion recognized as interest expense, reduce the finance obligations. The finance obligations have implicit interest rates ranging from 6.9% to 7.25% and are being repaid over an initial 35-year period with an early termination option after 17 years. If the Company exercises this option, it would pay the municipality an early termination payment equal to the carrying value of the obligation at termination. In November 2019 and October 2018, FortisBC Energy exercised early termination payment options in the amount of $12 million and $27 million, respectively, on two of these arrangements.
---	---

18. 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.

19. EARNINGS PER COMMON SHARE

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

	2019			2018
	Net Earnings	Weighted		Net Earnings	Weighted
	to Common	Average		to Common	Average
	Shareholders	Shares	EPS	Shareholders	Shares	EPS
	( millions)	(# millions)	()	( millions)	(# millions)	()
Basic EPS		436.8			424.7
Potential dilutive effect of<br><br>stock options	—	0.7	—	—	0.5	—
Diluted EPS		437.5			425.2

All values are in US Dollars.

35

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

20. PREFERENCE SHARES

Authorized

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

Issued and outstanding	2019			2018
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	7,025	172		7,025	172
Series I	2,975	73		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

Characteristics of the first preference shares are as follows.

				Earliest
			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	—	December 1, 2011	25.00	—
Series J ^(3)^	4.75	1.1875	—	December 1, 2017	25.50	—
Fixed rate reset ^(4) (5)^
Series G	5.25	1.0983	2.13	September 1, 2013	25.00	—
Series H	4.25	0.6250	1.45	June 1, 2015	25.00	Series I
Series K ^(6)^	4.00	0.9823	2.05	March 1, 2019	25.00	Series L
Series M ^(7)^	4.10	0.9783	2.48	December 1, 2019	25.00	Series N
Floating rate reset ^(5) (8)^
Series I ^(3)^	2.10	—	1.45	June 1, 2015	25.50	Series H
Series L	—	—	2.05	March 1, 2024	—	Series K
Series N	—	—	2.48	December 1, 2024	—	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 were redeemable at $26.00 until December 1, 2018, decreasing by $0.25 each year until December 1, 2021 and redeemable at $25.00 per share thereafter. First Preference Shares, Series I are redeemable at $25.50 per share, up to but excluding June 1, 2020, and at $25.00 per share on June 1, 2020, and on every fifth anniversary date thereafter.
---	---
^(4)^	On the redemption and/or conversion option date, and 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 K was reset from $1.0000 to $0.9823 for the five-year period from March 1, 2019 up to but excluding March 1, 2024.
---	---
^(7)^	The annual dividend per share for the First Preference Shares, Series M was reset from $1.0250 to $0.9783 for the five-year period from December 1, 2019 up to but excluding December 1, 2024.
---	---
^(8)^	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.
---	---
36
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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.

21. ACCUMULATED OTHER COMPREHENSIVE INCOME

(in millions)	Opening Balance			Net Change			Ending Balance
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 28)	11			6			17
Unrealized employee future benefits losses (Note 26)	(20		)	(18		)	(38		)
Income tax recovery	1			5			6
	(8		)	(7		)	(15		)
Accumulated other comprehensive income	$	928		$	(592	)	$	336
2018
Unrealized foreign currency translation gains (losses)
Net investments in foreign operations	$	247		$	1,223		$	1,470
Hedges of net investments in foreign operations	(172		)	(372		)	(544		)
Income tax (expense) recovery	(1		)	11			10
	74			862			936
Other
Cash flow hedges (Note 28)	10			1			11
Unrealized employee future benefits (losses) gains (Note 26)	(26		)	6			(20		)
Income tax recovery (expense)	3			(2		)	1
	(13		)	5			(8		)
Accumulated other comprehensive income	$	61		$	867		$	928

22. 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 termination, death or retirement of the optionee, and vest evenly over a four-year period on each anniversary of the grant date.

37

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

The following options were granted in 2019 and 2018.

	2019	2018
	February	February	March
Options granted (# in thousands)	852	722	40
Exercise price ($) ^(1)^	47.57	41.27	42.00
Grant date fair value ($)	3.70	3.43	4.08
Valuation assumptions:
Dividend yield (%) ^(2)^	3.8	3.7	3.7
Expected volatility (%) ^(3)^	15.2	15.5	15.7
Risk-free interest rate (%) ^(4)^	1.8	2.1	2.0
Weighted average expected life (years) ^(5)^	5.6	5.6	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 2019.

	Total Options				Non-vested Options ^(1)^
(in thousands, except as indicated)	Number of Options		Weighted Average<br> Exercise Price		Number of Options		Weighted Average<br>Grant Date Fair Value
Options outstanding, January 1, 2019	4,015		$	37.73	1,771		$	3.10
Granted	852		$	47.57	852		$	3.70
Exercised	(1,449	)	$	35.36	n/a		n/a
Vested	n/a		n/a		(713	)	$	2.92
Cancelled/Forfeited	—		n/a		—		n/a
Options outstanding, December 31, 2019	3,418		$	41.18	1,910		$	3.43
Options vested, December 31, 2019^(2)^	1,508		$	37.69
^(1)^	As at December 31, 2019, 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, 2019, the weighted average remaining term of vested options was six years with an aggregate intrinsic value of $24 million.
---	---

The following table summarizes additional stock option information.

(in millions)	2019		2018
Stock option expense recognized	$	2	$	2
Stock options exercised:
Cash received for exercise price	51		12
Intrinsic value realized by employees	22		3
Fair value of options that vested	2		2

Directors' 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.

38

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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.

The following table summarizes information related to DSUs.

	2019			2018
Number of units (in thousands)
Beginning of year	177			185
Granted	29			32
Notional dividends reinvested	6			8
Paid out	(47		)	(48		)
End of year	165			177
Additional information (in millions)
Compensation expense recognized	$	3		$	2
Cash payout ^(1)^	2			2
Accrued liability as at December 31 ^(2)^	9			8
^(1)^	Reflects a weighted average payout price of $51.76 per DSU (2018 - $43.15)
---	---
^(2)^	Recognized at the respective December 31^st^ VWAP (Note 3) and included in long-term other liabilities (Note 17)
---	---

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 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. 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 maturity 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.

39

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

The following table summarizes information related to PSUs.

	2019			2018
Number of units (in thousands)
Beginning of year	1,763			1,351
Granted	690			669
Notional dividends reinvested	73			66
Paid out	(357		)	(281		)
Cancelled/forfeited	(51		)	(42		)
End of year	2,118			1,763
Additional information (in millions)
Compensation expense recognized	$	74		$	22
Compensation expense unrecognized ^(1)^	35			27
Cash payout ^(2)^	16			14
Accrued liability as at December 31 ^(3)^	106			50
Aggregate intrinsic value as at December 31 ^(4)^	141			77
^(1)^	Relates to unvested PSUs and is expected to be recognized over a weighted average period of two years
---	---
^(2)^	Reflects a weighted average payout price of $45.14 per PSU and a payout percentage of 101% (2018 - $46.01 and 109% respectively)
---	---
^(3)^	Recognized at the respective December 31^st^ VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 14 and 17)
---	---
^(4)^	Relates to outstanding PSUs and reflects a weighted average contractual life of one year
---	---

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.

The following table summarizes information related to RSUs.

	2019			2018
Number of units (in thousands)
Beginning of year	717			483
Granted	429			305
Notional dividends reinvested	35			26
Paid out	(92		)	(75		)
Cancelled/forfeited	(39		)	(22		)
End of year	1,050			717
Additional information (in millions)
Compensation expense recognized	$	24		$	11
Compensation expense unrecognized ^(1)^	17			15
Cash payout ^(2)^	4			3
Accrued liability as at December 31 ^(3)^	39			19
Aggregate intrinsic value as at December 31 ^(4)^	56			34
^(1)^	Relates to unvested RSUs and is expected to be recognized over a weighted average period of two years
---	---
^(2)^	Reflects a weighted average payout price of $45.83 per RSU (2018 - $45.55)
---	---
^(3)^	Recognized at the respective December 31^st^ VWAP (Note 3) and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 14 and 17)
---	---
^(4)^	Relates to outstanding RSUs and reflects a weighted average contractual life of one year
---	---
40
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

23. DISPOSITION

On April 16, 2019, Fortis sold its

51%

ownership interest in the

335

-megawatt 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 has been removed from equity. Refer to Note 15 for use of proceeds.

Up to the date of disposition, the Waneta Expansion contributed $17 million to earnings before income tax expense, excluding the gain on disposition (December 31, 2018 - $54 million), of which Fortis' share was

51%

24. OTHER INCOME, NET

(in millions)	2019		2018
Equity component of AFUDC	$	74	$	64
Derivative gains (losses)	17		(12		)
Interest income	16		15
Gain on repayment of debt (Note 15)	11		—
Other	20		(7		)
	$	138	$	60

25. INCOME TAXES

Deferred Income Tax Assets and Liabilities

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

(in millions)	2019			2018
Gross deferred income tax assets
Regulatory liabilities	$	588		$	635
Tax loss and credit carryforwards	532			522
Employee future benefits	165			153
Unrealized foreign exchange losses on long-term debt	40			69
Other	88			76
	1,413			1,455
Valuation allowance	(22		)	(56		)
Net deferred income tax asset	$	1,391		$	1,399
Gross deferred income tax liabilities
PPE	$	(3,986	)	$	(3,780	)
Regulatory assets	(269		)	(203		)
Intangible assets	(105		)	(102		)
	(4,360		)	(4,085		)
Net deferred income tax liability	$	(2,969	)	$	(2,686	)

The deferred income tax assets associated with unrealized foreign exchange losses on long‑term debt reflect $22 million of unrealized capital losses as at December 31, 2019 (December 31, 2018 - $56 million). These deferred income tax assets can only be utilized if the Corporation has capital gains to offset these losses once realized. Management believes that it is "more likely than not" that Fortis will not be able to generate sufficient future capital gains and, consequently, the Corporation recognized a valuation allowance.

41

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

Management believes that, based on its historical pattern of taxable income, Fortis will produce the necessary income in the future to realize all other deferred income tax assets.

Unrecognized Tax Benefits

(in millions)	2019			2018
Beginning of year	$	38		$	28
Additions related to current year	5			6
Adjustments related to prior years	(7		)	4
End of year	$	36		$	38

Unrecognized tax benefits, if recognized, would reduce income tax expense by $1 million in 2019. Fortis has not recognized interest expense in 2019 and 2018 related to unrecognized tax benefits.

Income Tax Expense

(in millions)	2019			2018
Canadian
Earnings before income tax expense	$	901		$	376
Current income tax	49			51
Deferred income tax	42			(25		)
Total Canadian	$	91		$	26
Foreign
Earnings before income tax expense	$	1,240		$	1,075
Current income tax	(7		)	(22		)
Deferred income tax	205			161
Total Foreign	$	198		$	139
Income tax expense	$	289		$	165

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.

42

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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

(in millions, except %)	2019			2018
Earnings before income tax expense	$	2,141		$	1,451
Combined Canadian federal and provincial statutory income tax rate	28.5		%	28.5		%
Expected federal and provincial taxes at statutory rate	$	610		$	414
Decrease resulting from:
Foreign and other statutory rate differentials	(124		)	(110		)
Difference between gain on sale for accounting and amounts calculated for tax purposes	(73		)	—
Release of Valuation Allowance	(33		)	(16		)
Remeasurement of deferred tax liabilities	—			(44		)
AFUDC	(16		)	(14		)
Effects of rate-regulated accounting:
Difference between depreciation claimed for income tax and accounting purposes	(48		)	(34		)
Items capitalized for accounting purposes but expensed for income tax purposes	(17		)	(21		)
Other	(10		)	(10		)
Income tax expense	$	289		$	165
Effective tax rate	13.5		%	11.4		%

Income Tax Carryforwards

(in millions)	Expiring Year	2019
Canadian
Capital loss	n/a	$	19
Non-capital loss	2028-2039	110
Other tax credits	2026-2038	2
		131
Unrecognized		(14		)
		117
Foreign
Federal and state net operating loss	2020-2039	2,929
Other tax credits	2023-2039	74
		3,003
Total income tax carryforwards recognized as at December 31		$	3,120

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 2019 taxation years are still open for audit in Canadian jurisdictions and its 2016 to 2019 taxation years are still open for audit in United States jurisdictions.

26. 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.

43

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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, 2016 for FortisBC Electric and FortisBC Energy (plans covering unionized employees); December 31, 2017 for Newfoundland Power, FortisAlberta, FortisOntario and the Corporation; December 31, 2018 for FortisBC Energy (plan covering non-unionized employees); and December 31, 2019 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 as at December 31

	2019 Target Allocation
(weighted average %)		2019	2018
Equities	46	47	45
Fixed income	47	46	47
Real estate	6	6	7
Cash and other	1	1	1
	100	100	100

Fair Value of Plan Assets as at December 31

(in millions)	Level 1 ^(1)^		Level 2 ^(1)^		Level 3 ^(1)^		Total
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
2018
Equities	$	508	$	885	$	—	$	1,393
Fixed income	144		1,338		—		1,482
Real estate	—		14		190		204
Private equities	—		—		25		25
Cash and other	8		11		—		19
	$	660	$	2,248	$	215	$	3,123
^(1)^	Refer to Note 28 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)	2019			2018
Balance, beginning of year	$	215		$	190
Return on plan assets	19			15
Foreign currency translation	(2		)	3
Purchases, sales and settlements	(3		)	7
Balance, end of year	$	229		$	215
44
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018
Funded Status	Defined Benefit<br>Pension Plans						OPEB Plans
---	---	---	---	---	---	---	---	---	---	---	---	---
(in millions)	2019			2018			2019			2018
Change in benefit obligation ^(1)^
Balance, beginning of year	$	3,207		$	3,215		$	655		$	665
Service costs	77			84			27			31
Employee contributions	16			16			2			2
Interest costs	124			114			25			23
Benefits paid	(144		)	(145		)	(27		)	(26		)
Actuarial losses (gains)	439			(217		)	46			(69		)
Past service costs (credits)/plan<br><br>amendments	1			(1		)	4			(3		)
Foreign currency translation	(88		)	141			(20		)	32
Balance, end of year ^(2) (3)^	$	3,632		$	3,207		$	712		$	655
Change in value of plan assets
Balance, beginning of year	$	2,830		$	2,841		$	293		$	277
Actual return on plan assets	523			(93		)	62			(13		)
Benefits paid	(138		)	(137		)	(27		)	(26		)
Employee contributions	18			16			2			2
Employer contributions	53			79			28			29
Foreign currency translation	(78		)	124			(15		)	24
Balance, end of year ^(4)^	$	3,208		$	2,830		$	343		$	293
Funded status	$	(424	)	$	(377	)	$	(369	)	$	(362	)
Balance sheet presentation
Long-term assets (Note 10)	$	46		$	26		$	17		$	1
Current liabilities (Note 14)	(12		)	(12		)	(12		)	(13		)
Long-term liabilities (Note 17)	(458		)	(391		)	(374		)	(350		)
	$	(424	)	$	(377	)	$	(369	)	$	(362	)
^(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 $3,352 million (2018 - $2,936 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 favourable market returns, largely related to the performance of equity investments during the year.
---	---

For those defined benefit pension plans for which the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2019, the obligation was $2,971 million compared to plan assets of $2,511 million, respectively (December 31, 2018 - $2,600 million and $2,207 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, 2019, the obligation was $2,752 million compared to plan assets of $2,478 million, respectively (December 31, 2018 - $2,185 million and $1,940 million, respectively).

For those OPEB plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2019, the obligation was $537 million compared to plan assets of $151 million, respectively (December 31, 2018 - $486 million and $123 million, respectively).

45

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018
Net Benefit Cost ^(1)^	Defined Benefit<br>Pension Plans						OPEB Plans
---	---	---	---	---	---	---	---	---	---	---	---	---
(in millions)	2019			2018			2019			2018
Service costs	$	77		$	84		$	27		$	31
Interest costs	124			114			25			23
Expected return on plan assets	(161		)	(162		)	(16		)	(16		)
Amortization of actuarial losses (gains)	24			48			(4		)	—
Amortization of past service credits/plan<br><br>amendments	(1		)	—			(7		)	(10		)
Regulatory adjustments	2			(1		)	3			6
Net benefit cost	$	65		$	83		$	28		$	34
^(1)^	The non-service cost components of net periodic benefit cost are included in other income, net on 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<br><br>Pension Plans						OPEB Plans
(in millions)	2019			2018			2019			2018
Unamortized net actuarial losses (gains)	$	32		$	19		$	(2	)	$	(2	)
Unamortized past service costs	1			1			7			2
Income tax recovery	(8		)	(3		)	(1		)	(1		)
Accumulated other comprehensive income (loss) (Note 21)	$	25		$	17		$	4		$	(1	)
Net actuarial losses (gains)	$	486		$	457		$	(18	)	$	(25	)
Past service credits	(9		)	(10		)	(8		)	(16		)
Other regulatory deferrals	15			15			19			27
	$	492		$	462		$	(7	)	$	(14	)
Regulatory assets (Note 9)	$	492		$	462		$	38		$	23
Regulatory liabilities (Note 9)	—			—			(45		)	(37		)
Net regulatory assets (liabilities)	$	492		$	462		$	(7	)	$	(14	)
46
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

The following table summarizes the components of net benefit cost recognized in comprehensive income or as regulatory assets, which would otherwise have been recognized in comprehensive income.

	Defined Benefit<br><br>Pension Plans						OPEB Plans
(in millions)	2019			2018			2019			2018
Current year net actuarial losses (gains)	$	11		$	(3	)	$	—		$	(2	)
Past service costs (credits)/plan amendments	—			—			5			(1		)
Amortization of actuarial losses (gains)	1			(1		)	—			—
Foreign currency translation	1			1			—			—
Income tax (recovery) expense	(5		)	2			—			—
Total recognized in comprehensive income	$	8		$	(1	)	$	5		$	(3	)
Current year net actuarial losses (gains)	$	64		$	41		$	3		$	(39	)
Past service credits/plan amendments	—			—			—			(3		)
Amortization of actuarial (losses) gains	(23		)	(47		)	4			—
Amortization of past service (costs) credits	(1		)	1			8			11
Foreign currency translation	(10		)	21			—			(3		)
Regulatory adjustments	—			4			(8		)	(1		)
Total recognized in regulatory assets	$	30		$	20		$	7		$	(35	)
Significant Assumptions	Defined Benefit<br>Pension Plans		OPEB Plans
---	---	---	---	---
(weighted average %)	2019	2018	2019	2018
Discount rate during the year ^(1)^	4.05	3.56	4.10	3.57
Discount rate as at December 31	3.20	4.07	3.25	4.13
Expected long-term rate of return on plan assets ^(2)^	5.78	5.80	5.50	5.48
Rate of compensation increase	3.33	3.35	—	—
Health care cost trend increase as at December 31 ^(3)^	—	—	4.62	4.61
^(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 2020 weighted average health care cost trend rate is 6.15% and is assumed to decrease over the next 12 years to the weighted average ultimate health care cost trend rate of 4.62% in 2031 and thereafter.
---	---
	Defined Benefit		OPEB
---	---	---	---	---
Expected Benefit Payments	Pension Payments		Payments
(year)	(in millions)		(in millions)
2020	$	152	$	25
2021	156		27
2022	164		29
2023	168		30
2024	175		31
2025-2029	959		174

During 2020 the Corporation expects to contribute $46 million for defined benefit pension plans and $32 million for OPEB plans.

In 2019 the Corporation expensed $39 million (2018 - $38 million) related to defined contribution pension plans.

47

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

27. SUPPLEMENTARY CASH FLOW INFORMATION

(in millions)	2019			2018
Cash paid (received) for
Interest	$	1,007		$	969
Income taxes	(37		)	73
Change in working capital
Accounts receivable and other current assets	$	1		$	(204	)
Prepaid expenses	(8		)	1
Inventories	(13		)	(8		)
Regulatory assets - current portion	(75		)	16
Accounts payable and other current liabilities	(8		)	99
Regulatory liabilities - current portion	(65		)	(6		)
	$	(168	)	$	(102	)
Non-cash investing and financing activities
Accrued capital expenditures	$	382		$	328
Common share dividends reinvested	299			272
Finance leases	88			223
Right-of-use assets obtained in exchange for operating lease liabilities	55			—
Contributions in aid of construction	15			14
Exercise of stock options into common shares	5			1

28. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT

Derivatives

The Corporation generally limits derivative usage to those qualifying as accounting, economic or cash flow hedges, or those that are otherwise 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 flows.

Cash flows associated with the settlement of all derivatives are 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 were 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 were measured using forward pricing provided by independent third-party information.

FortisBC Energy holds gas supply contracts and commodity swaps 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.

48

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

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, 2019, unrealized losses of $119 million (December 31, 2018 - $57 million) were recognized as regulatory assets and unrealized gains of $2 million (December 31, 2018 - $9 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 were measured using a market approach utilizing independent third-party information, where possible.

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 were 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. During 2019 unrealized losses of $16 million (2018 - unrealized losses of $12 million) were recognized in revenue.

Total return swaps

The Corporation holds total return swaps to manage the cash flow risk associated with forecasted future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $111 million and terms of one to three years expiring in January 2020, 2021 and 2022. Fair value was measured using an income valuation approach based on forward pricing curves. During 2019 unrealized gains of $11 million (2018 - unrealized gains of less than $1 million) were recognized in other income, net.

Foreign exchange contracts

The Corporation holds US dollar foreign exchange contracts to help mitigate exposure to volatility of foreign exchange rates. The contracts expire in 2020 and have a combined notional amount of $166 million. Fair value was measured using independent third-party information. During 2019 unrealized gains of $11 million (2018 - unrealized losses of $11 million) were recognized in other income, net.

Interest rate swaps

During 2019 ITC entered into forward-starting interest rate swaps to manage the interest rate risk associated with the refinancing of long-term debt due in June 2021. The swaps have a combined notional value of $260 million and five-year terms with a mandatory early termination provision. The swaps will be terminated no later than the effective date of November 2020. Fair value was measured using a discounted cash flow method based on LIBOR rates. Unrealized gains and losses associated with changes in fair value are recognized in other comprehensive income, will be reclassified to earnings as a component of interest expense over the life of the debt, and were not material for 2019 and 2018.

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 on these funds are recognized in other income, net and were not material for 2019 and 2018.

49

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

Recurring Fair Value Measures

The following table presents the fair value of assets and liabilities that were accounted for at fair value on a recurring basis.

($ millions)	Level 1 ^(1)^		Level 2 ^(1)^		Level 3 ^(1)^	Total
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	)		As at December 31, 2018
---	---	---	---	---	---	---	---	---
Assets
Energy contracts subject to regulatory deferral ^(2) (3)^	—		33		8		41
Energy contracts not subject to regulatory deferral ^(2)^	—		13		3		16
Other investments ^(4)^	155		—		—		155
	155		46		11		212
Liabilities
Energy contracts subject to regulatory deferral ^(3) (5)^	—		(86	)	(3	)	(89	)
Energy contracts not subject to regulatory deferral ^(5)^	—		(1	)	—		(1	)
Foreign exchange contracts, interest rate and total return swaps ^(5)^	(8	)	(1	)	—		(9	)
	(8	)	(88	)	(3	)	(99	)
^(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 measurement. At December 31, 2019, all level 3 assets and liabilities transferred to level 2 because observable market data became available.
---	---
^(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.^^
---	---
^(4)^	Included in other assets
---	---
^(5)^	Included in accounts payable and other current liabilities or other liabilities
---	---

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

Energy Contracts<br><br><br>($ millions)	Gross Amount Recognized in Balance Sheet		Counterparty Netting of Energy Contracts		Cash Collateral Received/Posted		Net Amount
As at December 31, 2019
Derivative assets	30		22		10		(2	)
Derivative liabilities	(151	)	(22	)	(2	)	(127	)
50
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018
Energy Contracts<br><br><br><br><br><br>($ millions)	Gross Amount Recognized in Balance Sheet		Counterparty<br><br>Netting of<br><br>Energy<br><br>Contracts		Cash<br><br>Collateral<br><br>Received/<br><br>Posted	Net<br><br>Amount
---	---	---	---	---	---	---	---
As at December 31, 2018
Derivative assets	57		28		16	13
Derivative liabilities	(90	)	(28	)	—	(62	)

Volume of Derivative Activity

As at December 31, 2019, 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.

As at December 31	2019	2018
Energy contracts subject to regulatory deferral ^(1)^
Electricity swap contracts (GWh)	628	774
Electricity power purchase contracts (GWh)	3,198	651
Gas swap contracts (PJ)	168	203
Gas supply contract premiums (PJ)	241	266
Energy contracts not subject to regulatory deferral ^(1)^
Wholesale trading contracts (GWh)	1,855	1,440
Gas swap contracts (PJ)	43	37
^(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.

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 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, bond, letter of credit, an investment-grade credit rating, or a financial guarantee from an entity with an investment-grade credit rating.

UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and the Corporation may be exposed to credit risk from 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 $161 million as at December 31, 2019 (December 31, 2018 - $75 million).

51

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

Foreign Exchange Hedge

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 flows 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, 2019, US$2.2 billion (December 31, 2018 - US$3.4 billion) of corporately issued US dollar-denominated long-term debt has been designated as an effective hedge of foreign net investments, leaving approximately US$9.7 billion (December 31, 2018 - US$8.0 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, 2019, the carrying value of long-term debt, including current portion, was $22.3 billion (December 31, 2018 - $24.2 billion) compared to an estimated fair value of $25.3 billion (December 31, 2018 - $25.1 billion).

29. COMMITMENTS AND CONTINGENCIES

As at December 31, 2019, consolidated unconditional minimum purchase obligations were as follows.

(in millions)	Total		Due within 1 year	Due in year 2	Due in year 3	Due in year 4	Due in year 5	Due after <br>5 years
Waneta Expansion capacity agreement ^(1)^	$	2,628	51	52	53	54	55	2,363
Gas and fuel purchase obligations ^(2)^	2,398		606	424	349	255	140	624
Power purchase obligations ^(3)^	1,743		244	183	168	163	119	866
Renewable PPAs ^(4)^	1,513		104	104	104	103	103	995
Build-transfer agreement - Oso Grande ^(5)^	438		438	—	—	—	—	—
ITC easement agreement ^(6)^	401		13	13	13	13	13	336
Renewable energy credit purchase agreements ^(7)^	124		26	18	17	10	10	43
Debt collection agreement ^(8)^	116		3	3	3	3	3	101
Other ^(9)^	299		36	26	24	25	29	159
Total	$	9,660	1,521	823	731	626	472	5,487
^(1)^	FortisBC Electric entered into an agreement to purchase capacity from Waneta Expansion. In April 2019 the Waneta Expansion ceased to be a related party, resulting in the disclosure of FortisBC Electric's agreement to purchase capacity from the Waneta Expansion over the 40-year agreement that began in April 2015.
---	---
^(2)^	FortisBC Energy ($1.5 billion): includes contracts for the purchase of gas, gas transportation and storage services, with expiry dates from 2020 to 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, 2019.
---	---
52
---

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

UNS Energy ($775 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 between 2020 and 2040.

^(3)^

Maritime Electric ($669 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 February 2024.

FortisOntario ($653 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 from January 2020 through December 2030.

FortisBC Electric ($344 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 2031 through 2043, that require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities once commercial operation is achieved. Amounts are the estimated future payments.
^(5)^	In March 2019 UNS Energy entered into a build-transfer agreement to develop a wind-powered electric generation facility, the Oso Grande Wind Project, with estimated project cost of US$384 million. Construction commenced in the third quarter of 2019 and is expected to be completed by December 2020. UNS Energy made payments of US$47 million in 2019 and US$226 million in January 2020 under this agreement.
---	---
^(6)^	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.
---	---
^(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)^	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.
---	---
^(9)^	Includes land easements, asset retirement obligations and joint-use asset and shared service agreements.
---	---

Other Commitments

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 ("construction loan agreements"). In the event a lender under the construction 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.

53

FORTIS INC.<br><br>Notes to Consolidated Financial Statements<br><br>For the years ended December 31, 2019 and 2018

Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York State. In December 2014 an application was filed with FERC for the recovery of the cost of and return on five high-voltage transmission projects totalling $2.2 billion (US$1.7 billion). Central Hudson's maximum commitment is $236 million (US$182 million), for which it has issued a parental guarantee. As at December 31, 2019, there was no obligation under this guarantee.

As at December 31, 2019, FortisBC Holdings Inc. had $78 million (December 31, 2018 - $77 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.

54

		Exhibit

Exhibit 99.3

Management Discussion and Analysis

For the year ended December 31, 2019

Dated February 12, 2020

TABLE OF CONTENTS
About Fortis	1	Cash Flow Requirements	16
Significant Items	3	Cash Flow Summary	18
Performance at a Glance	3	Contractual Obligations	20
The Industry	6	Capital Structure and Credit Ratings	20
Operating Results	7	Capital Plan	21
Business Unit Performance	8	Business Risks	25
ITC	8	Accounting Matters	33
UNS Energy	9	Financial Instruments	37
Central Hudson	9	Long-term Debt and Other	37
FortisBC Energy	10	Derivatives	37
FortisAlberta	10	Selected Annual Financial Information	40
FortisBC Electric	11	Fourth Quarter Results	41
Other Electric	11	Summary of Quarterly Results	42
Energy Infrastructure	11	Related-Party Transactions	43
Corporate and Other	12	Management's Evaluation of Controls and Procedures	44
Non-US GAAP Financial Measures	12	Outlook	44
Regulatory Highlights	13	Forward-Looking Information	45
Financial Position	15	Glossary	46
Liquidity and Capital Resources	16	Condensed Consolidated Financial Statements	F-1

This MD&A has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. It should be read in conjunction with the 2019 Annual Financial Statements and is subject to the cautionary statement and disclaimer provided under "Forward-Looking Information" on page 45. Further information about Fortis, including its Annual Information Form filed on SEDAR, can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov.

Financial information herein has been prepared in accordance with US GAAP (except for indicated Non-US GAAP Financial Measures) and, unless otherwise specified, is presented in Canadian dollars based, as applicable, on the following US-to-Canadian dollar exchange rates: (i) average of 1.33 and 1.30 for the years ended December 31, 2019 and 2018, respectively; (ii) 1.30 and 1.36 as at December 31, 2019 and 2018, respectively; and (iii) 1.32 for all forecast periods. Certain terms used in this MD&A are defined in the "Glossary" on page 46.

ABOUT FORTIS

Fortis (TSX/NYSE: FTS) is a well-diversified leader in the North American regulated electric and gas utility industry, with revenue of $8.8 billion and total assets of $53 billion as at December 31, 2019.

Regulated utilities account for 99% of the Corporation's assets with the remainder primarily attributable to non-regulated energy infrastructure. The Corporation's 9,000 employees serve 3.3 million utility customers in five Canadian provinces, nine US states and three Caribbean countries. As at December 31, 2019, 66% of the Corporation's assets were located outside Canada and 60% of 2019 revenue was derived from foreign operations.

MANAGEMENT DISCUSSION AND ANALYSIS	1	December 31, 2019

Total Assets at December 31, 2019

Fortis is principally an energy delivery company, with 93% of its assets related to transmission and distribution. The business is characterized by low-risk, stable and predictable earnings and cash flows. EPS and TSR are the primary measures of financial performance.

Fortis' regulated utility businesses are: ITC (electric transmission - Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma); UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas distribution - New York); FortisBC Energy (natural gas transmission and distribution - British Columbia); FortisAlberta (electric distribution - Alberta); FortisBC Electric (integrated electric - British Columbia); Newfoundland Power (integrated electric - Newfoundland and Labrador); Maritime Electric (integrated electric - Prince Edward Island); FortisOntario (integrated electric - Ontario); Caribbean Utilities (integrated electric - Grand Cayman); and FortisTCI (integrated electric - Turks and Caicos Islands). Fortis also holds equity investments in the Wataynikaneyap Partnership (electric transmission - Ontario) and Belize Electricity (integrated electric - Belize).

Non-regulated energy infrastructure is comprised of Aitken Creek (natural gas storage facility - British Columbia), BECOL (three hydroelectric generation facilities - Belize) and the Waneta Expansion up to its disposition in April 2019 (see "Significant Items" on page 3).

Fortis has a unique operating model with a small head office in St. John's, Newfoundland and Labrador and business units that operate on a substantially autonomous basis. Each utility has its own management team and most have a board of directors with a majority of independent members, which provides effective oversight within the broad parameters of Fortis policies and best practices. Subsidiary autonomy supports constructive relationships with regulators, policy makers, customers and communities. Fortis believes this model enhances accountability, opportunity and performance across the Corporation's businesses, and positions Fortis well for future investment opportunities.

Additional information about the Corporation's business and reporting units is provided in Note 1 in the 2019 Annual Financial Statements.

MANAGEMENT DISCUSSION AND ANALYSIS	2	December 31, 2019

SIGNIFICANT ITEMS

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.

Fortis used the net proceeds to repay credit facility borrowings and repurchase, via a tender offer, US$400 million of its outstanding 3.055% unsecured senior notes due in 2026. The reduced earnings from the Waneta Expansion were offset by lower finance charges and a gain on repayment of the 3.055% notes.

Common Equity Offering

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

November 2019 FERC Order

In November 2019 FERC issued an order reducing the base ROE for ITC's MISO Subsidiaries to 9.88%, up to a maximum of 12.24% with incentive adders. Including incentive adders, this implies an all-in ROE for ITC's MISO subsidiaries of 10.63% compared to the previous all-in ROE of 11.07%. The net impact was a $63 million increase in earnings, comprised of $83 million related to the net reversal of liabilities established in prior periods, partially offset by $20 million related to the 2019 impact of the reduced ROE. See "Regulatory Highlights" on page 13 for further information.

PERFORMANCE AT A GLANCE

Key Financial Metrics
( millions, except as indicated)	2018	Variance
Common Equity Earnings
Actual	1,100	555
Adjusted (1)	1,066	49
Basic EPS ()
Actual	2.59	1.20
Adjusted (1)	2.51	0.04
Dividends
Paid per Common Share ()	1.7250	0.1025
Actual Payout Ratio (%)	66.6	(18.4	)
Adjusted Payout Ratio (1) (%)	68.7	3.0
Weighted Average Number of Common Shares Outstanding (millions)	424.7	12.1
Operating Cash Flow	2,604	59
Capital Expenditures	3,218	600

All values are in US Dollars.

^(1)^	See "Non-US GAAP Financial Measures" on page 12
TSR ^(1)^ (%)	1-Year		5-Year		10-Year		20-Year
---	---	---	---	---	---	---	---	---
Fortis	22.7	%	10.8	%	10.6	%	14.3	%
^(1)^	Total annualized shareholder return per Bloomberg, as at December 31, 2019
---	---

Earnings and EPS

The $555 million increase in Common Equity Earnings reflects significant one-time items, Rate Base growth driven by the Corporation's capital plan at the regulated utilities and favourable foreign exchange, partially offset by the impact of weather in Belize and Arizona, regulatory decisions at ITC and one-time positive tax adjustments primarily recognized in 2018.

MANAGEMENT DISCUSSION AND ANALYSIS	3	December 31, 2019

The significant one-time items were a $484 million gain on the disposition of the Waneta Expansion and an $83 million favourable adjustment resulting from the November 2019 FERC Order (see "Regulatory Highlights" on page 13), which resulted in the 2019 net reversal of liabilities established in prior years.

The regulated utilities delivered positive financial results reflecting Rate Base growth, driven by ITC, lower operating expenses, primarily at FortisAlberta, and favourable foreign exchange. This growth was tempered by: (i) a lower ROE at ITC due to the November 2019 FERC Order and lower ROE incentive adders effective April 2018; (ii) lower earnings contribution from UNS Energy due to lower retail sales, driven by cooler weather, and higher costs associated with Rate Base growth not yet reflected in rates; and (iii) lower earnings contribution from the Energy Infrastructure segment due to lower hydroelectric production in Belize and lower realized margins at Aitken Creek.

The one-time positive tax adjustments recognized in 2018 related to an election to file a consolidated state tax return and the designation of net assets related to the Waneta Expansion as held for sale totalling $30 million and $14 million, respectively. In addition, the finalization of US tax reform regulations associated with base-erosion and anti-abuse tax resulted in the recognition of income tax expense of $12 million in 2019.

Finally, a 12.1 million increase in the weighted average number of common shares outstanding associated with the Corporation's (i) $1.2 billion common equity issuance in the fourth quarter of 2019 (see "Significant Items" on page 3), (ii) ATM Program, and (iii) DRIP and share purchase plan, resulted in a $0.07 decrease in basic EPS.

Adjusted Common Equity Earnings and Adjusted Basic EPS increased by $49 million and $0.04, respectively. Refer to "Non-US GAAP Financial Measures" on page 12 for a reconciliation of these measures. The change in Adjusted Basic EPS is illustrated in the chart below.

^(1)^	Includes FortisBC Energy, FortisBC Electric and FortisAlberta. Driven primarily by Rate Base growth and lower operating expenses
^(2)^	Driven by Rate Base growth, partially offset by a lower 2019 ROE due to the November 2019 FERC Order
---	---
^(3)^	Driven by Rate Base growth
---	---
^(4)^	Average FX of $1.33 for 2019 compared to $1.30 for 2018
---	---
^(5)^	Driven primarily by reduced hydroelectric production at Belize due to lower rainfall
---	---
^(6)^	Driven primarily by higher costs associated with Rate Base growth not yet reflected in customer rates and lower retail sales due mainly to unfavourable weather
---	---
^(7)^	Weighted average shares of 436.8 million in 2019 compared to 424.7 million in 2018, partially offset by favourable foreign exchange contracts and higher income tax recoveries
---	---

Dividends and TSR

Fortis paid a dividend of $0.4775 per common share in the fourth quarter of 2019, up from $0.45 paid in each of the previous four quarters.

The total 2019 dividend paid per common share was $1.8275, up $0.1025 or nearly 6.0% from 2018 and in line with the Corporation's dividend guidance. The Actual Payout Ratio was 48.2% in 2019 compared to 66.6% in 2018 and an annual average of 61.4% over the five-year period of 2015 through 2019. The decrease in the 2019 Actual Payout Ratio was driven by the gain on disposition of the Waneta Expansion (see "Significant Items" on page 3).

MANAGEMENT DISCUSSION AND ANALYSIS	4	December 31, 2019

Fortis has increased its common share dividend for 46 consecutive years. Growth of dividends and the market price of the Corporation's common shares have together yielded a 1-year, 5-year, 10-year and 20-year TSR of 22.7%, 10.8%, 10.6% and 14.3%, respectively.

In September 2019 Fortis extended its targeted average annual dividend per common share growth of approximately 6% through 2024.

Operating Cash Flow

The $59 million increase was due to higher cash earnings, driven by Rate Base growth at the regulated utilities, led by ITC. The increase was partially offset by: (i) unfavourable changes due to the normal operation of long-term regulatory deferrals at ITC; (ii) unfavourable changes in working capital, due primarily to timing differences, partially offset by income tax refunds received in 2019; and (iii) lower cash earnings from the Energy Infrastructure segment (see "Business Unit Performance - Energy Infrastructure" on page 11).

Capital Expenditures

Capital expenditures in 2019 were $3.8 billion, $0.6 billion higher than in 2018 and $0.5 billion lower than forecast in the Q3 2019 MD&A. The $0.6 billion increase over the prior year was driven by higher spending at the US regulated utilities. The $0.5 billion decrease from forecast was due to: (i) a $0.3 billion delayed payment related to the construction of the Oso Grande Wind Project as the performance obligations were not fulfilled until January 2020; (ii) a revised forecast and timeline related to the Southline Transmission Project resulting in $0.1 billion being deferred until 2021; and (iii) revisions to various smaller projects resulting in $0.1 billion being deferred until 2021. See "Capital Plan" on page 21 for further information.

The Corporation's five-year 2020-2024 capital plan is targeted at $18.8 billion, approximately $0.5 billion higher than the $18.3 billion capital plan disclosed in the Q3 2019 MD&A. The increase reflects the shift in spending that was originally planned for December 2019 but was made in January 2020 related to UNS Energy's Oso Grande Wind Project, as well as the timing of other spend that shifted to 2021.

Funding of the capital plan is expected to be primarily through Operating Cash Flow, utility debt and common equity from the Corporation's DRIP.

The five-year capital plan is expected to increase midyear Rate Base from $28.0 billion in 2019 to $34.5 billion by 2022 and $38.4 billion by 2024, representing three- and five-year CAGRs of 7.2% and 6.5%, respectively. These CAGRs are supportive of continuing growth in earnings and dividends.

MANAGEMENT DISCUSSION AND ANALYSIS	5	December 31, 2019

Beyond the base capital plan, Fortis continues to pursue additional energy infrastructure opportunities. Key opportunities not yet included in the five-year capital plan include: further expansion of liquefied natural gas infrastructure in British Columbia; the fully permitted, cross-border, Lake Erie connector electric transmission project in Ontario; and the acceleration of cleaner energy goals in Arizona.

THE INDUSTRY

The North American energy industry continues to transform. There is a heightened focus on the impacts of climate change and the need for cleaner energy and energy conservation initiatives to preserve the environment for future generations. The effects of climate change, coupled with technological advancements, have rapidly shifted customer expectations for cleaner energy. The trend toward renewables and natural gas as a key part of the energy mix, as well as the increasing affordability of cleaner energy, is driving opportunity in the utility sector.

Changing energy policies at the federal, state and provincial levels are creating volatility in certain jurisdictions by introducing uncertainty around environmental, tax and trade regulation. The regulatory and compliance operating environment is also evolving and becoming increasingly complex. These changes are creating additional opportunities to expand investment in new generation sources, including natural gas, solar and wind, as well as infrastructure to interconnect renewable energy sources to the grid. Investment opportunities in storage are also growing with the proliferation of variable renewable generation sources and decreasing costs of storage technology. The Corporation's utilities are well positioned and actively involved in pursuing these opportunities.

New technology is driving change across all service territories. Energy delivery systems are being upgraded with advanced meters, improved controls and more capable operational technology, providing utilities with detailed usage data. Energy management capabilities are expanding through emerging storage and demand response systems, and customers have been enabled with options to manage and reduce energy usage and access more affordable distributed generation technology.

While some of these new technologies challenge the traditional role of utilities as one-way service providers, they also offer strategic investment opportunities for improving and expanding service. The proliferation of information and operational technology, along with the exponential growth in data and grid interconnections, is driving the need for increased cyber and physical security systems.

Meaningful customer engagement is increasingly important for utilities as customer expectations change and competition for customer attention becomes more intense. Customers want to make informed energy choices and become active participants in the delivery of their energy services. They also expect personalized service, customized service offerings and more real-time, digital communication.

MANAGEMENT DISCUSSION AND ANALYSIS	6	December 31, 2019

Fortis is well positioned to capitalize on evolving industry opportunities. Its decentralized structure and customer-focused business culture support the efforts required to meet changing customer expectations and to work with policy makers and regulators on energy and service solutions that are financially sustainable. Fortis is also a strategic partner in the Energy Impact Partners utility coalition, which is a strategic private entity fund that invests in emerging technologies, products, services and business models across the full electricity supply chain.

By leveraging these strengths and partnerships, Fortis expects to remain at the forefront of this ever-changing industry.

OPERATING RESULTS

			Variance
($ millions)	2019	2018	FX	Other
Revenue	8,783	8,390	113	280
Energy Supply Costs	2,520	2,495	30	(5	)
Operating Expenses	2,452	2,287	34	131
Depreciation and Amortization	1,350	1,243	14	93
Gain on Disposition	577	—	—	577
Other Income, Net	138	60	1	77
Finance Charges	1,035	974	10	51
Income Tax Expense	289	165	4	120
Net Earnings	1,852	1,286	22	544
Net Earnings Attributable to:
Non-Controlling Interests	130	120	2	8
Preference Equity Shareholders	67	66	—	1
Common Equity Shareholders	1,655	1,100	20	535
Net Earnings	1,852	1,286	22	544

Revenue

The increase was due primarily to: (i) Rate Base growth at the regulated utilities, led by ITC; (ii) overall higher flow-through costs in customer rates; (iii) favourable foreign exchange of $113 million; and (iv) a $91 million favourable adjustment associated with the November 2019 FERC Order (see "Regulatory Highlights" on page 13). The increase was partially offset by: (i) lower revenue contribution from the Energy Infrastructure segment due primarily to the disposition of the Waneta Expansion and reduced hydroelectric production in Belize due to lower rainfall; and (ii) lower retail sales at UNS Energy due to weather.

Energy Supply Costs

Energy supply costs were comparable to 2018. A reclassification of finance lease costs of $29 million from energy supply costs to finance charges, due to the adoption of a new lease standard (see "Accounting Matters - New Accounting Policies" on page 33), was offset by overall higher commodity costs.

Operating Expenses

The increase was due primarily to general inflationary and employee-related cost increases, including higher stock-based compensation costs driven by an increase in the Corporation's share price and overall performance.

Depreciation and Amortization

The increase was due primarily to continued investment in energy infrastructure at the Corporation's regulated utilities.

Gain on Disposition

See "Significant Items" on page 3.

MANAGEMENT DISCUSSION AND ANALYSIS	7	December 31, 2019

Other Income, Net

The increase was due primarily to: (i) favourable foreign exchange contracts; (ii) higher AFUDC equity earnings at UNS Energy; and (iii) an $11 million gain on the repayment of US$400 million of debt via tender offer (see "Significant Items" on page 3).

Finance Charges

The increase was due primarily to: (i) overall higher operating utility debt levels to support the capital plan; and (ii) the reclassification of finance lease interest of $29 million to finance charges from energy supply costs. The increase was partially offset by: (i) lower finance charges due to the repayment of debt (see "Significant Items" on page 3); and (ii) the reversal of interest of $16 million as a result of the November 2019 FERC Order (see "Regulatory Highlights" on page 13).

Income Tax Expense

The increase was driven by: (i) tax on the disposition of the Waneta Expansion (see "Significant Items" on page 3); (ii) $44 million of favourable deferred income tax liability remeasurements in 2018 arising from an election to file a consolidated state income tax return and the designation of net assets related to the Waneta Expansion as held for sale; and (iii) the recognition of income tax expense of $12 million in 2019 related to the finalization of US tax reform regulations associated with base-erosion and anti-abuse tax, partially offset by higher valuation allowances released in 2019 compared to 2018.

Net Earnings

See "Performance at a Glance - Earnings and EPS" on page 3.

BUSINESS UNIT PERFORMANCE

Common Equity Earnings
Years Ended December 31				Variance
($ millions)	2019	2018		FX ^(1)^	Other
Regulated Utilities
ITC	471	361		9	101
UNS Energy	292	293		6	(7	)
Central Hudson	85	74		2	9
FortisBC Energy	165	155		—	10
FortisAlberta	131	120		—	11
FortisBC Electric	54	56		—	(2	)
Other Electric ^(2)^	106	105		1	—
	1,304	1,164		18	122
Non-Regulated
Energy Infrastructure	18	72		1	(55	)
Corporate and Other	333	(136	)	1	468
Common Equity Earnings	1,655	1,100		20	535
^(1)^	The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and BECOL is the US dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00. The Corporate and Other segment includes certain transactions denominated in US dollars.
---	---
^(2)^	Comprised of the utility operations in eastern Canada and the Caribbean: Newfoundland Power; Maritime Electric; FortisOntario; Caribbean Utilities; FortisTCI; and Belize Electricity.
---	---
ITC			Variance
---	---	---	---	---
($ millions)	2019	2018	FX	Other
Revenue ^(1)^	1,761	1,504	35	222
Earnings ^(1)^	471	361	9	101
^(1)^	Revenue represents 100% of ITC. Earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflect consolidated purchase price accounting adjustments.
---	---
MANAGEMENT DISCUSSION AND ANALYSIS	8	December 31, 2019
---	---	---

Revenue

The increase, net of foreign exchange, was due primarily to a $91 million favourable adjustment to revenue associated with the November 2019 FERC Order (see "Regulatory Highlights" on page 13). Higher flow-through costs in customer rates and growth in Rate Base also contributed to the increase in revenue, partially offset by a reduction in the ROE incentive adders.

Earnings

The increase, net of foreign exchange, was due primarily to the November 2019 FERC Order that resulted in a $63 million increase in earnings, comprised of $83 million related to the net reversal of liabilities established in prior periods, partially offset by $20 million related to the 2019 impact of the reduced ROE. Growth in Rate Base, lower business development costs and a lower effective tax rate also contributed to the earnings increase, partially offset by a reduction in the ROE incentive adders and higher non-recoverable expenses.

UNS Energy			Variance
	2019	2018	FX	Other
Retail electricity sales (GWh)	10,431	10,600	—	(169	)
Wholesale electricity sales (GWh) ^(1)^	7,923	6,806	—	1,117
Gas sales (PJ)	16	13	—	3
Revenue ($ millions)	2,212	2,202	46	(36	)
Earnings ($ millions)	292	293	6	(7	)
^(1)^	Primarily short-term wholesale sales
---	---

Sales

The decrease in retail electricity sales was due to reduced air conditioning load as a result of cooler-than-normal temperatures in the spring and summer months compared to warmer-than-normal temperatures for the same periods in 2018.

The increase in wholesale electricity sales was due primarily to higher short-term wholesale sales reflecting an increase in system capacity related to Gila River Unit 2. Revenue from short-term wholesale sales is primarily returned to customers through regulatory deferral mechanisms and, therefore, does not materially impact earnings.

The increase in gas volumes was due primarily to heating load as a result of cooler temperatures in the winter months.

Revenue

The decrease, net of foreign exchange, was due primarily to the flow through of lower energy supply costs and lower retail sales. The decrease in revenue was partially offset by higher flow-through costs related to Springerville Units 3 and 4 and higher short-term wholesale sales.

Earnings

The decrease, net of foreign exchange, was due primarily to higher depreciation and interest expense associated with Rate Base growth not yet reflected in customer rates, and lower retail sales. The decrease was partially offset by higher AFUDC earnings, lower operating costs associated with scheduled outages and maintenance, and a lower effective tax rate.

Central Hudson			Variance
	2019	2018	FX	Other
Electricity sales (GWh)	4,963	5,118	—	(155	)
Gas sales (PJ)	22	24	—	(2	)
Revenue ($ millions)	917	924	24	(31	)
Earnings ($ millions)	85	74	2	9
MANAGEMENT DISCUSSION AND ANALYSIS	9	December 31, 2019
---	---	---

Sales

The decrease in electricity sales was due primarily to lower average consumption as a result of warmer temperatures in winter months that decreased heating load and cooler temperatures in summer months that decreased air conditioning load. Gas volumes were comparable to 2018.

Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, therefore, do not materially impact earnings.

Revenue

The decrease, net of foreign exchange, was due primarily to the flow through of lower energy supply costs and lower electricity sales, partially offset by Rate Base growth.

Earnings

The increase, net of foreign exchange, was primarily due to Rate Base growth and higher storm restoration costs in 2018.

FortisBC Energy	2019	2018	Variance
Gas sales (PJ)	227	212	15
Revenue ($ millions)	1,331	1,187	144
Earnings ($ millions)	165	155	10

Sales

The increase was due primarily to higher average residential and commercial consumption as a result of colder temperatures in 2019 that increased heating load and higher consumption by transportation customers.

Revenue

The increase was due primarily to a higher cost of natural gas and other flow-through costs recovered from customers, the recovery of gas storage and transportation costs related to a third-party pipeline incident that occurred in the fourth quarter of 2018, and Rate Base growth.

Earnings

The increase was due primarily to Rate Base growth.

FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery. Due to regulatory deferral mechanisms, changes in consumption levels and commodity costs do not materially impact earnings.

FortisAlberta	2019	2018	Variance
Energy deliveries (GWh)	16,887	17,154	(267	)
Revenue ($ millions)	598	579	19
Earnings ($ millions)	131	120	11

Deliveries

The decrease was due primarily to lower average consumption by oil and gas customers along with lower average residential consumption as a result of cooler temperatures in 2019 that decreased air conditioning load in the summer months. The decrease in energy deliveries was partially offset by higher average commercial consumption due to customer additions.

As more than 80% of FortisAlberta's revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.

Revenue

The increase was due primarily to Rate Base growth and customer additions, partially offset by a favourable capital tracker revenue true-up in 2018 related to capital expenditures in 2016 and 2017.

MANAGEMENT DISCUSSION AND ANALYSIS	10	December 31, 2019

Earnings

The increase was due primarily to lower operating expenses, driven by reduced labour costs, and Rate Base growth. The increase was partially offset by the 2018 capital tracker revenue true-up and a higher effective tax rate.

FortisBC Electric	2019	2018	Variance
Electricity sales (GWh)	3,326	3,250	76
Revenue ($ millions)	418	408	10
Earnings ($ millions)	54	56	(2	)

Sales

The increase was due primarily to higher consumption by industrial customers.

Revenue

The increase was due primarily to higher electricity sales, higher revenue related to a customer load growth regulatory mechanism and overall higher flow-through costs. The increase was partially offset by lower surplus power sales and the loss of revenue associated with the provision of operating, maintenance and management services to the Waneta Expansion (see "Significant Items" on page 3).

Earnings

The decrease was due primarily to the loss of revenue associated with the Waneta Expansion, partially offset by Rate Base growth.

Other Electric			Variance
	2019	2018	FX	Other
Electricity sales (GWh)	9,366	9,314	—	52
Revenue ($ millions)	1,467	1,412	7	48
Earnings ($ millions)	106	105	1	—

Sales

The increase was due primarily to overall higher average consumption in the Caribbean and customer additions.

Revenue

The increase, net of foreign exchange, was due primarily to the flow through of higher energy supply costs and higher electricity sales, partially offset by business interruption insurance proceeds recognized in 2018 at FortisTCI related to Hurricane Irma.

Earnings

Earnings, net of foreign exchange, were comparable to 2018. Higher electricity sales and Rate Base growth were offset by FortisTCI's insurance proceeds recognized in 2018.

Energy Infrastructure			Variance
	2019	2018	FX	Other
Electricity sales (GWh)	144	853	—	(709	)
Revenue ($ millions)	82	184	1	(103	)
Earnings ($ millions)	18	72	1	(55	)

Sales

Electricity sales decreased by 541 GWh due to the disposition of the Waneta Expansion (see "Significant Items" on page 3), with the remaining decrease due to lower hydroelectric production in Belize reflecting lower rainfall.

MANAGEMENT DISCUSSION AND ANALYSIS	11	December 31, 2019

Revenue and Earnings

The decreases in revenue and earnings reflected: (i) lower hydroelectric production in Belize; (ii) the disposition of the Waneta Expansion; (iii) lower realized margins at Aitken Creek; and (iv) the unfavourable impact of mark-to-market accounting of natural gas derivatives at Aitken Creek, with unrealized losses of $15 million during 2019 compared to $10 million during 2018.

Aitken Creek is subject to commodity price risk, as it purchases and holds natural gas in storage to earn a profit margin from its ultimate sale. Aitken Creek mitigates this risk by using derivatives to materially lock in the profit margin that will be realized upon the sale of natural gas. The fair value accounting of these derivatives creates timing differences and the resulting earnings volatility can be significant.

Corporate and Other				Variance
($ millions)	2019	2018		FX	Other
Net income (expenses)	333	(136	)	1	468

The increase in net income was driven by: (i) a net after-tax gain of $484 million on the disposition of the Waneta Expansion (see "Significant Items" on page 3); (ii) lower finance charges associated with the disposition, along with a gain on the repayment of debt; (iii) favourable changes associated with foreign exchange contracts in 2019 compared to 2018; and (iv) lower tax expense due to higher valuation allowances released in 2019 compared to 2018, partially offset by the recognition of base-erosion and anti-abuse tax in 2019 as a result of the finalization of the related US tax reform regulations. The increase was also partially offset by lower income tax recovery due to the remeasurement of deferred tax liabilities recognized during 2018: (i) $30 million resulting from the election to file a consolidated state income tax return; and (ii) $14 million associated with the designation of the net assets of the Waneta Expansion as held for sale.

NON-US GAAP FINANCIAL MEASURES

Adjusted Common Equity Earnings, Adjusted Basic EPS and Adjusted Payout Ratio are Non-US GAAP Financial Measures and may not be comparable with similar measures used by other entities. They are presented because management and external stakeholders use them in evaluating the Corporation's financial performance and prospects.

Net earnings attributable to common equity shareholders (i.e., Common Equity Earnings) and basic EPS are the most directly comparable US GAAP measures to Adjusted Common Equity Earnings and Adjusted Basic EPS, respectively. The Actual Payout Ratio calculated using Common Equity Earnings is the most comparable US GAAP measure to the Adjusted Payout Ratio.

MANAGEMENT DISCUSSION AND ANALYSIS	12	December 31, 2019

Adjusted Common Equity Earnings and Adjusted Basic EPS reflect items that management excludes in its key decision-making processes and evaluation of operating results, and are reconciled as follows.

Non-US GAAP Reconciliation
Years Ended December 31
($ millions, except as shown)	2019		2018		Variance
Common Equity Earnings	1,655		1,100		555
Adjusting items:
Gain on disposition ^(1)^	(484	)	—		(484	)
November 2019 FERC Order (2)	(83	)	—		(83	)
US tax reform (3)	12		—		12
Unrealized loss on mark-to-market of derivatives (4)	15		10		5
Consolidated state income tax election (5)	—		(30	)	30
Assets held for sale (5)	—		(14	)	14
Adjusted Common Equity Earnings	1,115		1,066		49
Adjusted Basic EPS ($)	2.55		2.51		0.04
^(1)^	See "Significant Items" on page 3, included in the Corporate and Other segment
---	---
^(2)^	See "Regulatory Highlights" below, included in the ITC segment
---	---
^(3)^	The finalization of US tax reform regulations associated with base-erosion and anti-abuse tax, included in the Corporate and Other segment
---	---
^(4)^	Represents timing differences related to the accounting of natural gas derivatives at Aitken Creek, included in the Energy Infrastructure segment
---	---
^(5)^	Remeasurement of deferred income tax liabilities, included in the Corporate and Other segment
---	---

REGULATORY HIGHLIGHTS

Regulation

The earnings of the Corporation's regulated utilities are determined under COS Regulation, with some using 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 Rate Base. Under PBR mechanisms, formulae are generally applied that incorporate inflation and assumed productivity improvements for a set term.

The ability to recover prudently incurred costs of providing service and earn the regulator‑approved ROE or ROA generally depends 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.

Transmission operations in the US are regulated federally by FERC. Remaining utility operations in the US and Canada are regulated by state or provincial regulators. Utility operations in the Caribbean are regulated by government authorities.

Additional information about regulation and the regulatory matters discussed below is provided in Note 2 in the 2019 Annual Financial Statements. Also refer to "Business Risks - Regulation" on page 25.

ITC

Incentive Adder Complaint

In April 2018 a third-party complaint was filed with FERC challenging the independence incentive adders that are included in transmission rates charged by ITC's MISO Subsidiaries. The adder allowed up to 0.50% or 1.00% to be added to the authorized ROE, subject to any ROE cap established by FERC. In October 2018 FERC issued an order reducing the adders to 0.25%, effective April 20, 2018. This equated to a 0.25% decrease in ROE, down from the approximate 0.50% that ITC was earning in rates previously approved by FERC. ITC began reflecting the 0.25% adder in transmission rates in November 2018. ITC's MISO Subsidiaries sought rehearing of this order in 2018, which was denied by FERC. In September 2019 ITC's MISO Subsidiaries filed an appeal in the US Court of Appeal. The final resolution of this matter is not expected to have a material impact on the Corporation's earnings or cash flows.

MANAGEMENT DISCUSSION AND ANALYSIS	13	December 31, 2019

ROE Complaints

In June 2016 the presiding ALJ issued an initial decision on the Second Complaint, recommending a base ROE of 9.70%, up to a maximum of 10.68% with incentive adders. Pending an order from FERC, an estimated regulatory liability of $206 million (US$151 million) had been recognized as at December 31, 2018 based on the ALJ's initial decision.

In September 2016 FERC ordered that the base ROE for the Initial Refund Period be set at 10.32%, down from 12.38%, up to a maximum of 11.35% with incentive adders. The resultant rates applied prospectively from September 2016 until an approved ROE was established for the Second Refund Period. The total refund for the Initial Complaint as a result of the September 2016 FERC order was $158 million (US$118 million), including interest, and was paid in 2017.

The November 2019 FERC Order determined that the base ROE for the Initial Complaint and from September 2016 onward be 9.88%, up to a maximum of 12.24% with incentive adders. FERC also dismissed the Second Complaint, resulting in a ROE for that period of 12.38% plus incentive adders with no refund required. In addition, as an ROE complaint had not been filed for the period of May 2016 to September 2016, the ROE for that period continued to be 12.38% plus incentive adders with no refund required. The regulated utilities in the MISO region, including ITC, sought rehearing of this order on the basis that it will not allow utilities to earn a reasonable rate of return on investment. In January 2020 FERC issued an order granting the rehearing for further consideration, effectively extending FERC's review.

As at December 31, 2019, a regulatory liability of $91 million (US$70 million) was recognized related to the impact of the November 2019 FERC Order on the Initial Refund Period and for the period from September 2016 to December 2019. Additionally, the regulatory liability of $206 million (US$151 million) as at December 31, 2018, related to the Second Complaint, was reversed in 2019. The net impact of the November 2019 FERC Order was an increase in revenue and a decrease in interest expense resulting in an increase in net earnings of $79 million of which Fortis' share was $63 million. The favourable impact was comprised of: (i) $83 million related to the net reversal of liabilities established in prior periods; partially offset by (ii) $20 million related to the 2019 impact of a reduced ROE.

Based on the outcome of the request for rehearing, it is possible the ROE and refunds could materially change from those recognized in 2019.

Notices of Inquiry

In March 2019 FERC issued a NOI seeking comments on whether and how to improve its electric transmission incentives policy. The outcome may impact the existing incentive adders that are included in transmission rates charged by transmission owners, including ITC. Also in March 2019, FERC issued a second NOI seeking comments on whether and how recent policies concerning the determination of the base ROE for electric utilities should be modified. The comment period for both NOI proceedings has ended. The outcome may impact ITC's future ROE and incentive adders.

UNS Energy

General Rate Application

In April 2019 TEP filed a general rate application with the Arizona Corporation Commission requesting an increase in non-fuel revenue of US$99 million, effective May 1, 2020, with electricity rates based on a 2018 historical test year. Intervenor testimony in relation to TEP's revenue requirement and rate design was filed in October 2019. The application, adjusted for rebuttal testimony filed by TEP in November 2019, includes a request to increase TEP's allowed ROE to 10.00% from 9.75% and the equity component of its capital structure to 53% from 50% on a Rate Base of US$2.7 billion. Hearings before the ALJ commenced in January and a decision is expected by mid-2020.

FortisBC Energy and FortisBC Electric

MANAGEMENT DISCUSSION AND ANALYSIS	14	December 31, 2019

FortisAlberta

Second-Term Performance-Based Rate-Setting Proceeding

Generic Cost of Capital Proceeding

2018 Alberta 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's customer contribution policy is accounted for between distribution facility owners, such as FortisAlberta, and transmission facility owners. The decision prevents any future investment by FortisAlberta under the policy and directs that the 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 transmission facility owner in FortisAlberta's service area.

FINANCIAL POSITION

Significant Changes between December 31, 2019 and 2018
	Increase (Decrease)
	FX	Other
Balance Sheet Account	($ millions)	($ millions)	Explanation
Assets held for sale	—	(766)	Due to the disposition of the Waneta Expansion.
Regulatory assets (including current and long-term)	(55)	363	Due primarily to the operation of rate stabilization accounts and the normal deferral of derivative losses, energy management costs, income tax expense and employee future benefits.
Property, plant and equipment, net	(974)	2,205	Due primarily to capital expenditures, partially offset by depreciation.
Goodwill	(527)	1	The other increase was not significant.
Short-term borrowings	(2)	454	Due primarily to the issuance of commercial paper at ITC and short-term borrowings at UNS Energy.
MANAGEMENT DISCUSSION AND ANALYSIS	15	December 31, 2019
---	---	---

Significant Changes between December 31, 2019 and 2018
	Increase (Decrease)
	FX	Other
Balance Sheet Account	($ millions)	($ millions)	Explanation
Other liabilities	(32)	340	Due primarily to higher employee future benefits mainly at FortisBC Energy, and finance lease reclassifications and the balance sheet recognition of operating leases in accordance with the new lease standard (see "New Accounting Policies" on page 33). The increase was also due to higher derivative balances and asset retirement obligations primarily at UNS Energy.
Regulatory liabilities (including current and long-term)	(130)	(138)	Due primarily to the ROE complaints liability at ITC and lower deferred taxes.
Deferred income tax liabilities	(70)	353	Due primarily to the timing differences related to capital expenditures.
Long-term debt (including current portion)	(791)	(1,103)	Due primarily to the repayment of Corporate debt (see "Significant Items" on page 3), partially offset by the issuance of debt at the regulated utilities.
Finance leases (including current portion)	(12)	(193)	Due primarily to the purchase of Gila River Unit 2, partially offset by the recognition of a finance lease for Springerville Common Facilities at TEP. The decrease was also due to reclassifications to other liabilities as noted above.
Shareholders' equity	(585)	2,583	Due primarily to: (i) the issuance of common shares (see "Significant Items" on page 3); and (ii) Common Equity Earnings for 2019, less dividends declared on common shares.
Non-controlling interests	(75)	(266)	Due primarily to the disposition of the Waneta Expansion.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOW REQUIREMENTS

At the subsidiary level, it is expected that operating and interest costs will be paid from Operating Cash Flows, with varying levels of residual cash flows available for capital expenditures and/or dividend payments to Fortis. Capital expenditures are expected to be financed primarily from borrowings under credit facilities, long-term debt offerings and equity injections from Fortis. Borrowings under credit facilities may be required periodically to support seasonal working capital requirements.

Cash required of Fortis to support subsidiary capital expenditures is expected to be derived from borrowings under the Corporation's committed credit facility, proceeds from the DRIP and issuances of common shares, preference shares and long-term debt. Depending on the timing of subsidiary dividend receipts, borrowings under the Corporation's credit facility may be required periodically to support debt servicing and dividend payments.

MANAGEMENT DISCUSSION AND ANALYSIS	16	December 31, 2019

Within this dynamic, the subsidiaries pay dividends to Fortis and receive equity injections from Fortis when required, and both Fortis and its subsidiaries initially borrow through their committed credit facilities and periodically replace these borrowings with long-term debt. Financing needs also arise periodically for acquisitions.

Credit facilities are syndicated primarily with large banks in Canada and the US, with no one bank holding more than 20% of the total facilities. Approximately $5.1 billion of the total credit facilities are committed with maturities ranging from 2020 through 2024. Available credit facilities are summarized in the following table.

Credit Facilities
As at December 31	Regulated		Corporate
($ millions)	Utilities		and Other		2019		2018
Total credit facilities ^(1)^	4,209		1,381		5,590		5,165
Credit facilities utilized:
Short-term borrowings	(512	)	—		(512	)	(60	)
Long-term debt (including current portion)	(640	)	—		(640	)	(1,066	)
Letters of credit outstanding	(64	)	(50	)	(114	)	(119	)
Credit facilities unutilized	2,993		1,331		4,324		3,920
^(1)^	Additional information about these credit facilities is provided in Note 15 in the 2019 Annual Financial Statements.
---	---

The Corporation's ability to service debt and pay dividends is dependent on the financial results of, and the related cash payments from, its subsidiaries. Certain regulated subsidiaries are subject to restrictions that limit their ability to distribute cash to Fortis, including restrictions by certain regulators limiting annual dividends and restrictions by certain lenders limiting debt to total capitalization. There are also practical limitations on using the net assets of the regulated subsidiaries to pay dividends, based on management's intent to maintain the subsidiaries' regulator-approved capital structures. Fortis does not expect that maintaining such capital structures will impact its ability to pay dividends in the foreseeable future.

In December 2018 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 $2.5 billion. In December 2018 Fortis re-established its ATM Program, which allowed the issuance of up to $500 million of common shares from treasury to the public at the Corporation's discretion, effective until January 2021.

During 2019 the Corporation issued approximately 4.1 million common shares under its ATM 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 in 2019, the Corporation issued approximately 22.8 million common shares under a common equity offering at a price of $52.15 per share for gross proceeds of $1,190 million ($1,167 million net of commissions). See "Significant Items" on page 3. Following this issuance, the Corporation terminated the ATM Program. As at December 31, 2019, $1,098 million remained available under the short-form base shelf prospectus.

As at December 31, 2019: (i) consolidated fixed-term debt maturities/repayments are expected to average $945 million annually over the next five years; (ii) approximately 80% of the Corporation's consolidated long-term debt, excluding credit facility borrowings, had maturities beyond five years; and (iii) available credit facilities were $5.6 billion with $4.3 billion unutilized.

This combination of available credit facilities and manageable annual debt maturities/repayments provides flexibility in the timing of access to capital markets. Given current credit ratings and capital structures, the Corporation and its subsidiaries expect to continue to have reasonable access to long-term capital in 2020.

Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2019 and are expected to remain compliant in 2020.

MANAGEMENT DISCUSSION AND ANALYSIS	17	December 31, 2019

CASH FLOW SUMMARY

Summary of Cash Flows
Years ended December 31
($ millions)	2019		2018		Variance
Cash, beginning of year	332		327		5
Cash provided by (used in):
Operating activities	2,663		2,604		59
Investing activities	(2,768	)	(3,252	)	484
Financing activities	154		644		(490	)
Effect of exchange rate changes on cash and cash equivalents	(26	)	24		(50	)
Cash and change in cash associated with assets held for sale	15		(15	)	30
Cash, end of year	370		332		38

Operating Activities

See "Performance at a Glance - Operating Cash Flow" on page 5.

Investing Activities

Cash used in investing activities reflects a higher capital spending level in 2019. See "Performance at a Glance - Capital Expenditures" on page 5 and "Capital Plan" on page 21. Cash used in investing activities was partially offset by proceeds from the disposition of the Waneta Expansion.

Financing Activities

Cash flows related to financing activities will fluctuate from year to year as a result of changes in the subsidiaries' capital expenditures, the amount of Operating Cash Flows available to fund those capital expenditures and the amount of funding required from debt and common equity issuances.

Net proceeds from the disposition of the Waneta Expansion were used to repay credit facility borrowings and repurchase, via a tender offer, US$400 million of its outstanding 3.055% unsecured senior notes due in 2026.

MANAGEMENT DISCUSSION AND ANALYSIS	18	December 31, 2019

Debt Financing

Long-Term Debt Issuances		Interest
Year ended December 31, 2019	Month	Rate					Use of
($ millions, except %)	Issued	(%)		Maturity	Amount		Proceeds
ITC
Secured notes	January	4.55		2049	US	50	^(1) (2) (3)^
Unsecured term loan credit agreement ^(4)^	June	^(5)^		2021	US	200	^(6)^
Secured notes	July	4.65		2049	US	50	^(1) (2) (3)^
First mortgage bonds	August	3.30		2049	US	75	^(1) (2) (3)^
Central Hudson
Unsecured notes	October	3.89		2049	US	50	^(2) (3) (6)^
Unsecured notes	October	3.99		2059	US	50	^(2) (3) (6)^
FortisBC Energy
Unsecured debentures	August	2.82		2049	200		^(1)^
FortisTCI
Unsecured non-revolving term loan	February	^(7^	^)^	2025	US	5	^(2) (3)^
Caribbean Utilities
Unsecured notes	May	4.14		2049	US	40	^(1) (3) (6)^
Unsecured notes	August	4.14		2049	US	20	^(2) (3) (6)^
Unsecured notes	August	3.83		2039	US	20	^(2) (3) (6)^
^(1)^	Repay credit facility borrowings
---	---
^(2)^	Finance capital expenditures
---	---
^(3)^	General corporate purposes
---	---
^(4)^	Maximum amount of borrowings under this agreement was US$400 million; in January 2020 the remaining US$200 million was drawn to repay outstanding commercial paper balances
---	---
^(5)^	Floating rate of a one-month LIBOR plus a spread of 0.60%
---	---
^(6)^	Repay maturing long-term debt
---	---
^(7)^	Floating rate of a one-month LIBOR plus a spread of 1.75%
---	---

Common Equity Financing

Common Equity Issuances and Dividends Paid
Years Ended December 31
($ millions, except as indicated)	2019		2018		Variance
Number of common shares issued^(1)^ (# millions)	34.8		7.4		27.4
Amount of common shares issued ^(2)^	1,756		307		1,449
Non-cash issuances ^(3)^	(314	)	(273	)	(41	)
Cash proceeds from common shares issued	1,442		34		1,408
Dividends paid per common share ($)	1.8275		1.7250		0.1025
Total dividends paid	793		731		62
Non-cash DRIP	(299	)	(272	)	(27	)
Cash dividends paid	494		459		35
^(1)^	Mainly related to the Corporation's issuance of shares in the fourth quarter of 2019, DRIP and ATM Program
---	---
^(2)^	Net of commissions of $26 million (2018 - $nil)
---	---
^(3)^	Related to DRIP and stock options
---	---

On February 12, 2020, Fortis declared a dividend of $0.4775 per common share payable on June 1, 2020. The payment of dividends is at the discretion of the Board of Directors and depends on the Corporation's financial condition and other factors.

MANAGEMENT DISCUSSION AND ANALYSIS	19	December 31, 2019

CONTRACTUAL OBLIGATIONS

Contractual Obligations
As at December 31, 2019		Due
($ millions)	Total	Year 1	Year 2	Year 3	Year 4	Year 5	Thereafter
Long-term debt:
Principal ^(1)^	22,320	690	872	1,146	1,553	1,106	16,953
Interest	15,483	929	910	879	846	786	11,133
Finance leases ^(2)^	1,359	56	121	33	33	33	1,083
Other obligations	450	134	120	94	20	19	63
Other commitments ^(3)^
Waneta Expansion capacity agreement	2,628	51	52	53	54	55	2,363
Gas and fuel purchase obligations	2,398	606	424	349	255	140	624
Power purchase obligations	1,743	244	183	168	163	119	866
Renewable PPAs	1,513	104	104	104	103	103	995
Build-transfer agreement - Oso Grande	438	438	—	—	—	—	—
ITC easement agreement	401	13	13	13	13	13	336
Renewables energy credit purchase agreements	124	26	18	17	10	10	43
Debt collection agreement	116	3	3	3	3	3	101
Other	299	36	26	24	25	29	159
	49,272	3,330	2,846	2,883	3,078	2,416	34,719
^(1)^	Total is not reduced by unamortized deferred financing and discount costs of $129 million.
---	---
^(2)^	Additional information is provided in Note 16 in the 2019 Annual Financial Statements.
---	---
^(3)^	Additional information is provided in Note 29 in the 2019 Annual Financial Statements.
---	---

Other Contractual Obligations

The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. Consolidated capital expenditures are forecast to be approximately $4.3 billion for 2020 and approximately $18.8 billion over the five-year period from 2020 through 2024. See "Capital Plan" on page 21.

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 such construction 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.

As at December 31, 2019, FortisBC Holdings Inc., a non-regulated holding company, had $78 million of parental guarantees outstanding to support storage optimization activities at Aitken Creek.

Off-Balance Sheet Arrangements

With the exception of letters of credit outstanding of $114 million as at December 31, 2019 and the unrecorded commitments in the table above, the Corporation had no off-balance sheet arrangements.

CAPITAL STRUCTURE AND CREDIT RATINGS

Fortis requires ongoing access to capital and, therefore, targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. The regulated utilities maintain their own capital structures in line with those reflected in customer rates.

MANAGEMENT DISCUSSION AND ANALYSIS	20	December 31, 2019

Consolidated Capital Structure ^(1)^ (%)
As at December 31	2019	2018
Debt ^(2)^	53.1	57.0
Preference shares	3.8	3.8
Common shareholders' equity and minority interest^(3)^	43.1	39.2
	100.0	100.0
^(1)^	Reflects the repayment of debt using proceeds from the disposition of the Waneta Expansion and the $1.2 billion common equity offering (see "Significant Items" on page 3)
---	---
^(2)^	Includes long-term debt and finance leases, including current portion, and short-term borrowings, net of cash
---	---
^(3)^	Includes minority interest of 3.7% as at December 31, 2019 (December 31, 2018 - 4.5%)
---	---

Outstanding Share Data

As at February 12, 2020, the Corporation had issued and outstanding 463.5 million common shares and the following First Preference Shares: 5.0 million Series F; 9.2 million Series G; 7.0 million Series H; 3.0 million Series I; 8.0 million Series J; 10.0 million Series K; and 24.0 million Series M.

Only the common shares of the Corporation have voting rights. The Corporation's first preference shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive or declared.

If all outstanding stock options were converted as at February 12, 2020, an additional 3.2 million common shares would be issued and outstanding.

Credit Ratings

The Corporation's credit ratings shown below reflect its low risk profile, diversity of operations, the stand-alone nature and financial separation of each regulated subsidiary, and level of holding company debt.

Credit Ratings
As at December 31, 2019	Rating	Type	Outlook
S&P	A-	Corporate	Negative
	BBB+	Unsecured debt
DBRS Morningstar	BBB (high)	Corporate	Stable
	BBB (high)	Unsecured debt
Moody's	Baa3	Issuer	Stable
	Baa3	Unsecured debt

CAPITAL PLAN

Capital investment in energy infrastructure is required to ensure the continued and enhanced performance, reliability and safety of the electricity and gas systems, and to meet customer growth. See "Performance at a Glance - Capital Expenditures" on page 5.

2019 Capital Expenditures ^(1)^
	Regulated Utilities
($ millions, except %)	ITC	UNS<br><br>Energy	Central<br><br>Hudson	FortisBC<br><br>Energy	Fortis<br><br>Alberta	FortisBC<br><br>Electric	Other Electric	Total<br><br>Regulated<br><br>Utilities	Non-Regulated ^(2)^	Total	(%)
Generation	—	442	2	—	—	29	57	530	6	536	14
Transmission	951	83	55	194	—	18	146	1,447	—	1,447	38
Distribution	—	255	174	191	385	42	160	1,207	—	1,207	32
Other ^(3)^	197	135	86	78	38	17	30	581	47	628	16
Total	1,148	915	317	463	423	106	393	3,765	53	3,818	100
(%)	31	24	8	12	11	3	10	99	1	100
^(1)^	Reflects cash outlay for property, plant and equipment and intangible assets as shown on the consolidated statements of cash flows in the 2019 Annual Financial Statements, as well as Fortis' share of development costs and capital spending for the Wataynikaneyap Transmission Power Project of $98 million
---	---
^(2)^	Includes Energy Infrastructure and Corporate and Other segments
---	---
^(3)^	Includes facilities, equipment, vehicles and information technology assets, as well as AESO transmission-related capital expenditures at FortisAlberta
---	---
MANAGEMENT DISCUSSION AND ANALYSIS	21	December 31, 2019
---	---	---

Planned capital expenditures are based on detailed forecasts of energy demand, labour and material costs, general economic conditions, foreign exchange rates and other factors. These could change and cause actual expenditures to differ from forecast or plan.

Forecast 2020 Capital Expenditures ^(1)^
	Regulated Utilities
($ millions, except %)	ITC	UNS<br><br>Energy	Central<br><br>Hudson	FortisBC<br><br>Energy	Fortis<br><br>Alberta	FortisBC<br><br>Electric	Other Electric	Total<br><br>Regulated<br><br>Utilities	Non-Regulated	Total	(%)
Generation	—	715	1	—	—	33	120	869	11	880	20
Transmission	914	189	44	221	—	4	254	1,626	—	1,626	37
Distribution	—	274	167	153	365	77	158	1,194	—	1,194	28
Other	62	212	80	133	71	27	34	619	21	640	15
Total	976	1,390	292	507	436	141	566	4,308	32	4,340	100
(%)	22	32	7	12	10	3	13	99	1	100
^(1)^	Excludes the non-cash equity component of AFUDC
---	---
Five-Year Capital Plan ^(1)^
---	---	---	---	---	---	---
($ billions)	2020	2021	2022	2023	2024	Total
	4.3	3.8	3.8	3.7	3.2	18.8
^(1)^	Excludes the non-cash equity component of AFUDC
---	---

The Corporation's five-year 2020-2024 capital plan of $18.8 billion is $0.5 billion higher than the $18.3 billion capital plan disclosed in the Q3 2019 MD&A due to a $0.5 billion shift in spending to 2020 and 2021 (see "Performance at a Glance - Capital Expenditures" on page 5).

The $18.8 billion five-year capital plan is $1.5 billion higher than the $17.3 billion for 2019-2023, as disclosed in the 2018 annual MD&A, largely due to: (i) expected grid enhancements and cleaner energy resources at ITC and Caribbean Utilities; (ii) expected expansion of the Tilbury LNG site at FortisBC Energy; (iii) an increase in the forecast foreign exchange rate from US$1.00=CAD$1.28 to US$1.00=CAD$1.32; and (iv) the above-noted shift in spending from 2019 to 2020 and 2021.

The capital plan is low risk and highly executable, with 99% of planned expenditures to occur at the regulated utilities and only 20% related to Major Capital Projects. Geographically, 55% of planned expenditures are expected in the US, including 26% at ITC, with 41% in Canada and the remaining 4% in the Caribbean.

Nature of Capital Expenditures	Actual	Forecast	Five-Year Plan
(%)	2019	2020	2020-2024
Growth ^(1)^	23	25	28
Sustaining ^(2)^	60	62	59
Other ^(3)^	17	13	13
Total	100	100	100
^(1)^	Relates to the connection of new customers and infrastructure upgrades required to meet load growth, including AESO transmission‑related investment at FortisAlberta
---	---
^(2)^	Relates to the continued and enhanced performance, reliability and safety of generation, transmission and distribution assets
---	---
^(3)^	Facilities, equipment, vehicles, information technology and other assets
---	---
MANAGEMENT DISCUSSION AND ANALYSIS	22	December 31, 2019
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Midyear Rate Base ^(1)^	Actual	Forecast	Forecast
($ billions)	2019	2020	2024
ITC	8.7	9.5	12.0
UNS Energy	5.1	5.8	6.9
Central Hudson	1.9	2.1	2.8
FortisBC Energy	4.5	5.0	6.6
FortisAlberta	3.5	3.7	4.3
FortisBC Electric	1.3	1.4	1.5
Other Electric	3.0	3.2	4.3
Total	28.0	30.7	38.4
^(1)^	Simple average of Rate Base at beginning and end of the year
---	---

Total midyear Rate Base is forecast to grow to $38.4 billion by 2024 under the five-year capital plan, representing a CAGR of 6.5%, which is supportive of continuing growth in earnings and dividends.

Major Capital Projects ^(1)^				Forecast
		Pre-	Actual		2021-	Expected
($ millions)	Project	2019	2019	2020	2024	Completion
ITC ^(2)^	Multi-Value Regional Transmission Projects	581	44	11	265	2023
	34.5 to 69 kV Transmission Conversion Project	225	127	92	176	Post-2024
UNS Energy	Gila River Unit 2	—	212	—	—	2019
	Southline Transmission Project	—	—	19	373	Post-2024
	Oso Grande Wind Project	—	65	453	—	2020
FortisBC Energy	Lower Mainland Intermediate Pressure System Upgrade	208	180	72	—	2020
	Eagle Mountain Woodfibre Gas Line Project ^(3)^	—	—	—	350	2023
	Transmission Integrity Management Capabilities Project	—	13	23	494	Post-2024
	Inland Gas Upgrades Project	3	6	57	262	Post-2024
	Tilbury 1B	—	8	37	315	2024
Other Electric	Wataynikaneyap Transmission Power Project ^(4)^	25	98	230	271	2023
Total		1,042	753	994	2,506
^(1)^	Includes applicable AFUDC
---	---
^(2)^	Pre-2019 capital expenditures are from the date of the ITC acquisition on October 14, 2016
---	---
^(3)^	Net of forecast customer contributions
---	---
^(4)^	Fortis' share of estimated capital spending, including deferred development costs. Under the funding framework, Fortis will be funding its equity component only.
---	---

Multi-Value Regional Transmission Projects

Consists of four regional electric transmission projects that have been identified by MISO to address system capacity needs and reliability in various states. Three projects have been completed, one in 2018 and two in 2019. The fourth project is expected to be placed in service in 2023.

34.5 to 69kV Transmission Conversion Project

Consists of multiple capital initiatives designed to construct new 69-kV lines, and upgrade existing 34.5-kV lines to 69 kV, with in-service dates ranging from 2019 to post-2024.

Gila River Unit 2

In 2017 UNS Energy entered into a 20-year tolling PPA that included a three-year option to purchase Gila River Unit 2. The purchase of Gila River Unit 2 was completed in December 2019 and replaces the early retirement of coal-fired generation.

MANAGEMENT DISCUSSION AND ANALYSIS	23	December 31, 2019

Southline Transmission Project

UNS Energy continues to evaluate the cost and timelines associated with the different phases of this project. The first phase, referred to as "Vail-to-Tortolita", is a joint effort between Western Area Power Administration and TEP that will result in new construction and upgrades to connect existing TEP substations. Construction of this phase is expected to commence in 2020.

The second phase of the project relates to the construction of a 600-MW transmission line across southern New Mexico and southern Arizona. The line will improve regional reliability and facilitate the connection of renewable energy resources to the grid, including the Oso Grande Wind Project. UNS Energy expects to purchase a 250-MW ownership in the project. The timing, share and cost of this phase of the project will depend on subscription of the remaining wind available at Oso Grande.

Oso Grande Wind Project

Relates to the construction of a 750-MW wind-powered electric generating facility that will complement UNS Energy's existing renewable solar generation portfolio, of which UNS Energy will own 250 MW. Construction on Oso Grande commenced in the third quarter of 2019 and in January 2020 UNS Energy took ownership of its share under a build-transfer contract. Construction is expected to be completed for operation by December 2020.

Lower Mainland Intermediate Pressure System Upgrade

Addresses system capacity and pipeline condition issues for the gas supply system in the Lower Mainland of British Columbia. The Burnaby and Coquitlam sections of the project were gasified during 2018 and 2019. A short pipeline segment in South Vancouver will be replaced in 2020. Final allowable project costs are subject to review by the BCUC.

Eagle Mountain Woodfibre Gas Line Project

Consists of a pipeline expansion to a proposed LNG site in Squamish, British Columbia. Cost estimates are subject to final project scoping and determination of customer capital contributions. An Order in Council from the Government of British Columbia effectively exempts the project from further regulatory approval. FortisBC Energy and Woodfibre LNG Limited have entered into a pre-execution work agreement enabling FortisBC Energy to incur project feasibility and development costs.

Transmission Integrity Management Capabilities Project

Project to improve gas line safety and transmission system integrity, including gas line modifications and looping. In December 2018 a regulatory deferral account was approved by the BCUC to capture approximately $40 million of development costs to be incurred through 2020 to enable the filing for a CPCN.

Inland Gas Upgrades Project

Relates to gas line modifications and replacements to enable in-line integrity inspection capabilities. In January 2020 the CPCN application was approved by the BCUC.

Tilbury 1B Project

Consists of construction of additional liquefaction and dispensing in support of optimizing the existing investment in Tilbury Phase 1A Expansion Project. The project has received an Order in Council from the Government of British Columbia. Pre-front-end engineering design and related studies will continue in 2020.

Wataynikaneyap Transmission Power Project

Consists of the construction of a $1.6 billion, 1,800 kilometre, OEB-regulated transmission line to connect 17 remote First Nations communities in Northwestern Ontario to the main electricity grid. FortisOntario is responsible for construction management and operation of the transmission line. The initial phase to connect the Pikangikum First Nation was fully funded by the Canadian government and completed in late 2018. In the fourth quarter of 2019, the project received financial close and a notice to proceed for construction was issued. The project is targeted for completion by the end of 2023.

Additional Investment Opportunities

Fortis is pursuing additional investment opportunities within existing service territories that are not yet included in the base five-year capital plan.

MANAGEMENT DISCUSSION AND ANALYSIS	24	December 31, 2019

ITC - Lake Erie Connector

Relates to a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line to directly link the markets of the Ontario Independent Electricity System Operator and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets. The major application process is complete. The project continues to advance through regulatory, operational and economic milestones. Ongoing activities include completing project cost refinements and securing transmission service agreements. Completion would take approximately three years from the commencement of construction.

FortisBC Energy - LNG

Relates to FortisBC's pursuit of additional LNG infrastructure opportunities in British Columbia, including further expansion of the Tilbury LNG facility, which is uniquely positioned to meet customer demand for clean-burning natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment and is relatively close to international shipping lanes. Fortis continues to have discussions with potential export customers.

Other Opportunities

Includes incremental regulated transmission investment, contracted transmission and grid modernization projects at ITC; renewable energy investments, energy storage projects, grid modernization, infrastructure resiliency, and transmission investments at UNS Energy; and further gas infrastructure opportunities at FortisBC Energy.

BUSINESS RISKS

Fortis has established an ERM process to help identify and evaluate risks by both severity of impact and probability of occurrence. Materiality thresholds are reviewed and, if necessary, updated annually. Non-financial risks that may impact the safety of employees, customers or the general public, as well as reputational risks, are also evaluated. Systems of internal controls are established to monitor and manage identified risks. The ERM process at the subsidiary level is overseen by each subsidiary’s board and any material risks identified are communicated to Fortis management and form part of Fortis' ERM program. The Fortis board, through the audit committee, oversees Fortis' ERM program, ensuring strategic objectives are achieved.

A summary of the Corporation's current significant business risks follows.

Regulation

Regulated utility assets represented approximately 99% of the Corporation's total assets as at December 31, 2019. Regulatory jurisdictions include five Canadian provinces, nine US states and three Caribbean countries, as well FERC regulation for transmission assets in the US.

Regulators administer legislation covering material aspects of the utilities' business, including: customer rates and the underlying allowed ROEs and deemed capital structures; capital expenditures; the terms and conditions for the provision of energy and capacity, ancillary services and affiliate services; securities issuances; and certain accounting matters. Regulatory or legislative changes and decisions, and delays in the recovery of costs in rates due to regulatory lag, could have a Material Adverse Effect. The risk of regulatory lag is particularly significant for UNS Energy given the use of historical test years in setting rates.

The ability to recover the actual cost of service and earn the approved ROE or ROA typically depends on achieving the forecasts established in the rate-setting process. Failure to do so could have a Material Adverse Effect. For those utilities subject to PBR mechanisms, rates reflect assumed inflation rates and productivity improvement factors, and variances therefrom could have a Material Adverse Effect. Under FortisAlberta's PBR mechanism there is an added risk that incremental incurred capital expenditures may not be approved for recovery in rates.

For transmission operations, the underlying elements of FERC-established formula rates can be, and have been, challenged by third parties which could result in, and has resulted in, lowered rates and customer refunds. These underlying elements include the assumed ROE and deemed capital structure as well as operating and capital expenditures. These challenges could have a Material Adverse Effect. Recent challenges are described under "Regulatory Highlights - ITC" on page 13.

MANAGEMENT DISCUSSION AND ANALYSIS	25	December 31, 2019

Additionally, the US Congress periodically considers enacting energy legislation that could assign new responsibilities to FERC, modify provisions of the U.S. Federal Power Act or the Natural Gas Act, or provide FERC or another entity with increased authority to regulate US federal energy matters. Such changes could have a Material Adverse Effect.

The political and economic environments as well as their effect on energy laws and governmental energy policies have had, and may continue to have, negative impacts on regulatory decisions. While Fortis is well positioned to maintain constructive regulatory relationships through local management teams and boards comprised mostly of independent local members, it cannot predict future legislative or regulatory changes, whether caused by economic, political or other factors, or its ability to respond thereto in an effective and timely manner, or resulting compliance costs. These dynamics could have a Material Adverse Effect.

Climate Change and Physical Risks

The provision of electric and gas service is subject to customary industry risks, including severe weather and natural disasters, wars, terrorism, critical equipment failure and other catastrophic events within and outside the Corporation's service territories. Resultant service disruption and repair and replacement costs could have a Material Adverse Effect if not resolved in a timely and effective manner and/or mitigated through insurance policies or regulatory cost recovery.

Climate change is predicted to lead to more frequent and intense weather events, changing air temperatures, changing seasonal variations, and regulatory responses (see "Environmental Matters" on page 31), each of which could have a Material Adverse Effect. Severe weather impacts the Corporation’s service territories, primarily when thunderstorms, flooding, wildfires, hurricanes and snow or ice storms occur. Increased frequency of extreme weather events could increase the cost of providing service. Changes in precipitation that result in droughts could increase the risk of wildfire caused by the Corporation’s electricity assets or may cause water shortages that could adversely affect operations. Extreme weather conditions in general require system backup and can contribute to increased system stress, including service interruptions. Changing air temperatures could also result in system stress and decreased efficiencies over time to operating facilities. Longer-term climate change impacts, such as sustained higher temperatures, higher sea levels and larger storm surges, could result in service disruption, repair and replacement costs, and costs associated with strengthened design standards and systems, each of which could have a Material Adverse Effect if not resolved in a timely and effective manner and/or mitigated through insurance policies or regulatory cost recovery.

Generating equipment and facilities are subject to risks, including equipment breakdown and flood and fire damage, that may result in the uncontrolled release of water, interruption of fuel supply, lower-than-expected operational efficiency or performance, and service disruption. There is no assurance that generating equipment and facilities will continue to operate in accordance with expectations.

The operation of transmission and distribution assets is subject to risks, including the potential to cause fires, mainly as a result of equipment failure, falling trees and lightning strikes to lines or equipment. Certain utilities operate in remote and mountainous terrain that can be difficult to access for timely repairs and maintenance, or otherwise face risk of loss or damage from forest fires, floods, washouts, landslides, earthquakes, avalanches and other acts of nature with a potential Material Adverse Effect.

The gas utilities are exposed to operational risks associated with natural gas, including fires, explosions, pipeline corrosion and leaks, accidental damage to mains and service lines, equipment failure, damage and destruction from earthquakes, fires, floods and other natural disasters, and other accidents and issues that can lead to service disruption, spills and commensurate environmental liability, or other liability with a Material Adverse Effect.

Risks associated with fire damage vary depending on weather, forestation, the proximity of habitation and third-party facilities to utility facilities, and other factors. The utilities may become liable for fire-suppression costs, regeneration and timber value costs, and third-party claims if their facilities are held responsible for a fire, and such claims, if successful, could have a Material Adverse Effect.

MANAGEMENT DISCUSSION AND ANALYSIS	26	December 31, 2019

Electricity and gas systems require ongoing maintenance, improvement and replacement. Service disruption, other effects and liability caused by the failure to properly implement or complete approved maintenance and capital expenditures, or the occurrence of significant unforeseen equipment failures despite maintenance programs, or the inability to recover requisite costs in customer rates, could have a Material Adverse Effect.

The electricity and gas systems are designed to service customers under various contingencies in accordance with good utility practice. The utilities are responsible for operating and maintaining their assets in a safe manner, including the development and application of appropriate standards, system processes and/or procedures to ensure the safety of employees, contractors and the general public. The impacts of climate change may necessitate the acceleration of these standards, processes and procedures. Failure to do so may disrupt the ability of the utilities to safely provide service, which could cause reputational harm and other impacts with a Material Adverse Effect.

Interest Rates

The market price of the Corporation's common shares is inversely sensitive to interest rate changes.

Additionally, allowed ROEs are exposed to changes in long-term interest rates. A low interest rate environment could reduce allowed ROEs. Alternatively, if interest rates rise, regulatory lag may cause delays in any compensatory ROE increases. Borrowings under variable-rate credit facilities and long-term debt, as well as new debt issuances, are also exposed to interest rate changes.

Weather Variability and Seasonality

Electricity consumption varies significantly in response to climate change and seasonal weather changes. In central and western Canada, Arizona and New York State, cool summers may reduce the use of air conditioning and other cooling equipment, while less severe winters may reduce heating load. Alternatively, severe weather could unexpectedly increase heating and cooling loads, negatively impacting system reliability.

Weather and seasonality have a significant impact on gas distribution volumes as a major portion of the gas is used for space heating by residential customers. The earnings of the Corporation's gas utilities and Aitken Creek are typically highest in the first and fourth quarters.

Hydroelectric generation is sensitive to rainfall levels.

Regulatory deferral and revenue decoupling mechanisms are in place at certain of the Corporation's utilities to minimize the volatility in earnings that would otherwise be caused by variations in weather conditions. Both the discontinuance of key regulatory mechanisms and their absence at other Fortis entities could result in significant and prolonged weather variations from seasonal norms having a Material Adverse Effect.

Growth

Fortis has a history of growth through acquisitions and organic growth from capital expenditures in existing service territories. Acquisitions include inherent risks that some or all of the expected benefits may fail to materialize, or may not occur within the time periods anticipated, and material unexpected costs may arise.

The Corporation's dividend growth guidance is significantly dependent upon achieving the Rate Base growth expected from the execution of the five-year capital plan described under "Capital Plan" on page 21. Projects, particularly Major Capital Projects, are subject to risks of delay and cost overruns during construction caused by inflation, supply and labour costs, supplier non-performance, weather, geologic conditions or other factors beyond the Corporation’s control. There is no assurance that regulators will approve (i) all of the planned projects or their amounts or timing, (ii) permits in a timely manner, or with reasonable terms and conditions, or (iii) the recovery of overruns in customer rates. These risks could impact the successful execution of a project by preventing the project from proceeding, delaying its completion, increasing its projected costs or negatively impacting its financing.

MANAGEMENT DISCUSSION AND ANALYSIS	27	December 31, 2019

Talent Management

The delivery of safe, reliable and cost-effective service depends on the attraction, development and retention of skilled workforces. Like its peers, Fortis faces demographic challenges and competitive markets relating to trades, technical and professional staff, particularly considering its significant consolidated capital plan. ITC relies heavily on agreements with third parties to provide services for the construction, maintenance and operation of certain aspects of its business. Although Fortis has a robust talent management program, there is no assurance it will be able to continue to attract sufficient and appropriate talent. Significant failures in these regards could have a Material Adverse Effect.

Tax Laws

Fortis and its subsidiaries are subject to changes in income tax rates and other tax legislation in Canada, the US and other international jurisdictions. These changes could have a Material Adverse Effect. Although income taxes at the regulated utilities are generally recovered in customer rates, regulatory lag can result in recovery delays or non-recovery for certain periods. A variety of other impacts are also possible. At the non-regulated level, changes in income tax rates and other tax legislation could materially affect the after-tax cost of existing and future debt which is not recoverable in customer rates.

The nature, timing or impact of any future changes in tax laws cannot be predicted. Additionally, certain aspects of US tax reform are still subject to interpretation and clarification, including proposed regulations regarding certain hybrid arrangements.

Cybersecurity

As operators of critical energy infrastructure, the Corporation's utilities face the risk of cybercrime, which has increased in frequency, scope and potential impact in recent years. Their ability to operate effectively is dependent upon developing and maintaining complex information systems and infrastructure that support the operation of electric generation, transmission and distribution facilities, including gas facilities; provide customers with billing, consumption and load settlement information, where applicable; and support financial and general operations.

Despite risk-based cybersecurity programs that have been implemented and are continuously monitored for effectiveness, information and operations technology systems may be vulnerable to unauthorized access due to hacking, viruses, acts of war or terrorism, acts of vandalism and other causes. This can result in the disruption of energy service and other business operations, system failures and grid disturbances, property damage, corruption or unavailability of critical data, and the misappropriation and/or disclosure of sensitive, confidential and proprietary business, customer and employee information.

A material breach could adversely affect the financial performance of the Corporation, its reputation and standing with customers, regulators and financial markets, and expose it to claims for third-party damage. The resultant financial impacts may not be fully covered by insurance policies or, in the case of utilities, through regulatory cost recovery, and could have a Material Adverse Effect.

Technology Advances

The emergence of initiatives designed to reduce GHG emissions and control or limit the effects of climate change has increased the incentive for the development of new technologies that produce power, enable more efficient storage of energy or reduce power consumption.

New technology developments in distributed generation, particularly solar, and energy efficiency products and services, as well as the implementation of renewable energy and energy efficiency standards, will continue to impact retail sales. Heightened awareness of energy costs and environmental concerns have increased demand for products that reduce energy consumption. The Corporation's utilities are also promoting demand-side management programs.

New technologies include energy derived from renewable sources, customer-owned generation, energy-efficient appliances, battery storage and control systems. Advances in these or other technologies could have a significant impact on retail sales with a potential Material Adverse Effect.

MANAGEMENT DISCUSSION AND ANALYSIS	28	December 31, 2019

Foreign Exchange Exposure

The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, BECOL and Belize Electricity is, or is pegged to, the US dollar. The earnings and cash flows from, and net investments in, these entities are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate.

Fortis has limited this exposure through hedging. As at December 31, 2019, US$2.2 billion (December 31, 2018 - US$3.4 billion) of corporately issued US dollar-denominated long-term debt had been designated as an effective hedge of foreign net investments, leaving US$9.7 billion (December 31, 2018 - US$8.0 billion) in foreign net investments unhedged. Fortis has also entered into foreign exchange contracts to manage a portion of its exposure to foreign currency risk.

Given only partial hedging, consolidated earnings and cash flows continue to be impacted by exchange rate fluctuations. On average, Fortis estimates that a five-cent increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.33 as at December 31, 2019 would increase or decrease annual EPS by approximately 6 cents, which reflects the Corporation's hedging program.

There is no assurance that existing hedging strategies will continue to be effective. They could also have the effect of limiting or reducing the Corporation's total returns if management's expectations concerning future events or market conditions prove to be incorrect, in which case the costs associated with the hedging strategies may outweigh their benefits.

Natural Gas Competitiveness

Approximately 19% of the Corporation's revenue is derived from natural gas. A decrease in the competitiveness of natural gas due to pricing or other factors could have a Material Adverse Effect.

In British Columbia, which accounts for 79% of the Corporation's natural gas revenue, natural gas primarily competes with electricity for space and hot water heating. Upfront capital costs for gas service continue to present competitive challenges for natural gas compared to electricity service. If gas becomes less competitive, the ability to add new customers could be impaired. Existing customers could also reduce their consumption or switch to electricity, placing further pressure on rates, whereby system costs must be recovered from a smaller customer and sales base, and leading to further reductions in competitiveness.

Government policy could also impact the competitiveness of natural gas in British Columbia. The provincial government has introduced changes to energy policy, including GHG emission reduction targets and a consumption tax on carbon-based fuels, but has not yet introduced a carbon tax on imported electricity generated through the combustion of carbon-based fuels. The impact of these changes to energy policy may have a material impact on the competitiveness of natural gas relative to non-carbon based energy sources or other energy sources.

In addition, all levels of government have become more active in the development of policies to address climate change. For example, municipal governments have developed policies and bylaws to support the transition to a lower-carbon economy. Government policy may put upward pressure on the cost of natural gas and potentially affect its competitiveness. Government policy may also impose limitations on energy sources permitted to be used in new and existing developments.

Reliability Standards

The Energy Policy Act requires owners, operators and users of the bulk electric system in the US to meet mandatory reliability standards developed by the North American Electric Reliability Corporation and its regional entities, which are approved and enforced by FERC. Many of these, or similar, standards have been adopted in certain Canadian provinces including British Columbia, Alberta and Ontario. The failure to develop, implement and maintain appropriate operating practices/systems and capital plans to address reliability obligations could lead to compliance violations and a Material Adverse Effect, such as the exclusion from customer rates of related costs including potentially significant penalties.

MANAGEMENT DISCUSSION AND ANALYSIS	29	December 31, 2019

General Economic Conditions

Fluctuations in general economic conditions, energy prices, employment levels, personal disposable incomes, housing starts, industrial activity and other factors may lower energy demand and reduce sales both directly and through reduced capital spending, particularly that related to new customer growth, which would affect Rate Base growth. A severe and prolonged economic downturn could have a Material Adverse Effect despite compensatory regulatory measures, including making it more difficult for customers to pay their bills.

Access to Capital

Ongoing access to cost-effective capital is required to fund, among other things, capital expenditures and the repayment of maturing debt.

Operating Cash Flows may not be sufficient to fund the repayment of all outstanding liabilities when due or anticipated capital expenditures. The ability to meet long-term debt repayments is dependent upon obtaining sufficient and cost-effective financing to replace maturing indebtedness.

The ability to arrange such financing is subject to numerous factors, including the results of operations and financial condition of Fortis and its subsidiaries, the regulatory environments including regulatory decisions regarding capital structure and allowed ROEs, capital market conditions, general economic conditions and credit ratings. Changes in credit ratings could affect credit risk spreads on new long-term debt and credit facilities, as well as their availability.

There is no assurance that sufficient capital will continue to be available on acceptable terms. For further information see "Liquidity and Capital Resources" on page 16.

Commodity Price Volatility

Purchased power and generation fuel costs are subject to commodity price volatility, which is managed through regulator-approved: (i) mechanisms that permit the flow through in customer rates of commodity price changes and/or that provide for rate-stabilization and other deferral accounts (see "Business Unit Performance" on page 8); and (ii) price-risk management strategies such as the use of derivative contracts that effectively fix costs (see "Financial Instruments - Derivatives" on page 37).

There is no assurance that current regulator-approved mechanisms will continue to exist in the future. Additionally, despite these mechanisms, severe and prolonged commodity price increases could result in rates that customers are unable to pay and/or could affect consumption and thus sales growth. These could have a Material Adverse Effect.

Counterparty Credit Risk

ITC has a concentration of credit risk as approximately 70% of its revenue is derived from three customers. These customers have investment-grade credit ratings and credit risk is further managed 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 its 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.

UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and Fortis may be exposed to credit risk from 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.

There is no assurance that management strategies will continue to be effective. Significant counterparty defaults could have a Material Adverse Effect.

Purchased Power Supply

A significant portion of electricity and gas sold by the Corporation's utilities is purchased through the wholesale energy markets or pursuant to contracts with energy suppliers rather than being generated. A disruption in the wholesale energy markets, or a failure on the part of energy or fuel suppliers or operators of energy delivery systems that connect to the Corporation's utilities, could have a Material Adverse Effect.

MANAGEMENT DISCUSSION AND ANALYSIS	30	December 31, 2019

Post-Retirement Obligations

Fortis and most of its subsidiaries maintain a combination of defined benefit pension and/or OPEB plans for certain employees and retirees. The most significant cost drivers for these plans are investment performance and interest rates, which are affected by global financial markets. Market disruptions, significant declines in the market values of investments held to meet plan obligations, discount rate changes, participant demographics, and changes in laws and regulations may require additional plan funding. Significant increases in plan expenses and funding could have a Material Adverse Effect.

Joint-Ownership Interests and Third-Party Operators

Certain generating facilities from which TEP receives power are jointly owned with, or are operated by, third parties. TEP may not have sole discretion or any ability to affect the management or operations of such facilities, including how to best address changing economic conditions or environmental requirements that may affect the facilities. A divergence in the interests of TEP and those of the joint owners or operators could have a Material Adverse Effect.

Wataynikaneyap Partnership is a partnership, owned 51% by 24 First Nations communities and 49% by a partnership between Fortis (80%) and Algonquin Power & Utilities Corp. (20%), responsible for the Wataynikaneyap Transmission Power Project. Fortis does not have sole discretion on decisions for the project and divergence in the interest of Fortis and the other partners could delay the project’s completion, increase its anticipated cost, or adversely affect the reputation of Fortis.

Environmental Matters

The Corporation's businesses are subject to environmental risks and environmental laws and regulations, including those which: (i) impose limitations or restrictions on the discharge of pollutants into the air, soil and water; (ii) establish standards for the management, treatment, storage, transportation and disposal of hazardous wastes; and/or (iii) impose obligations to investigate and remediate contamination.

The risk of contamination of air, soil and water at the electric businesses primarily relates to: (i) the transportation, handling, storage and combustion of fuel; (ii) the use of petroleum-based products, mainly transformer and lubricating oil; (iii) the management and disposal of coal combustion residuals and other wastes; and (iv) accidents resulting in hazardous release at or from coal mines that supply generating facilities. Contamination risks at the gas businesses primarily relate to gas and propane leaks and other accidents involving these substances. The key environmental risks for hydroelectric generation operations include the creation of artificial water flows that may disrupt natural habitats and dam failures.

Liabilities relating to contamination investigation and remediation, and claims for personal injury or property damage, may arise at many locations, including formerly and currently owned/operated properties and waste treatment or disposal sites, and regardless of whether such contamination was caused by the business at the time it owned the property or whether it resulted from non-compliance with applicable environmental laws. Under some environmental laws, such liabilities may be joint and several, meaning that a party can be held responsible for more than its share of the liability involved or even the entire liability. These liabilities could lead to litigation and administrative proceedings that could result in substantial monetary judgments for clean-up costs, damages, fines and/or penalties. To the extent not fully covered by insurance, these costs could have a Material Adverse Effect.

The Corporation's businesses have incurred substantial expenses for environmental compliance, and they anticipate continuing to do so in the future. In particular, the management of GHG emissions is a major concern due to new and emerging federal, state and provincial GHG laws, regulations and guidelines.

The Corporation's businesses continue to develop compliance strategies and assess the impact of emerging legislative changes, but significant uncertainties remain. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a Material Adverse Effect.

Some coal-fired generation facilities utilized by UNS Energy have closed before the end of their useful lives due to economic conditions and/or recent or expected changes in environmental regulations, including those relating to GHG emissions. Early closures have necessitated regulatory relief to recover any remaining net book values and decommissioning costs, and potential accelerated depreciation could cause rate pressure. Significant unrecovered costs or rate pressures could have a Material Adverse Effect.

MANAGEMENT DISCUSSION AND ANALYSIS	31	December 31, 2019

Insurance

Insurance is maintained with reputable industry insurers for property damage, potential liabilities and business interruption for coverage considered appropriate and in accordance with industry practice.

A significant portion of transmission and distribution assets is uninsured, as is customary in North America, as the cost is prohibitive. Insurance is subject to coverage limits and deductibles as well as time-sensitive claims discovery and reporting provisions. There is no assurance that: (i) the amounts and types of actual damage, liabilities or business interruption will be fully covered; (ii) regulatory relief would be obtained for coverage shortfalls; (iii) adequate insurance at reasonable rates will continue to be available; or (iv) insurers will fulfill their obligations. Significant actual shortfalls could have a Material Adverse Effect.

Required Approvals

The acquisition, ownership and operation of electric and gas businesses require numerous licences, permits, agreements, orders, certificates and other approvals from various levels of government, regulators, government agencies and/or third parties. There is no assurance that: (i) all of these will be obtained, continuously maintained or renewed without delay; and (ii) the terms and conditions thereof will be fully complied with at all times and will not change in a material adverse manner. Significant failures in these regards could prevent the operation of the businesses and have a Material Adverse Effect.

Reputation, Relationships and Stakeholder Activism

The Corporation’s operations and growth prospects require strong relationships with key stakeholders, including governments and agencies, Indigenous communities, landowners, and environmental organizations. Inadequately managing expectations and issues important to stakeholders, including those arising during construction, could affect the Corporation’s reputation as well as have a significant impact on its operations and infrastructure development.

Additionally, external stakeholders are increasingly challenging utilities regarding climate change, sustainability, diversity, returns including ROEs, executive compensation and other matters. Public opposition to larger infrastructure projects is becoming increasingly common, which can challenge capital plans and resultant organic growth. While the Corporation actively monitors such activism and is committed to developing stronger relationships with its external stakeholders, failure to effectively maintain or respond to stakeholder activism could have a Material Adverse Effect.

Indigenous Peoples' Land Claims

The Corporation's British Columbia utilities provide service to customers on Indigenous Peoples' lands and maintain facilities on lands that are subject to Indigenous Peoples' land claims. A treaty negotiation process involving Indigenous Peoples and the Governments of British Columbia and Canada is underway, but the basis for potential settlements is unclear and not all Indigenous Peoples are participating in the process. To date, the policy of the Government of British Columbia has been to structure settlements without prejudicing existing third-party rights. However, there is no assurance that the settlement process will not have a Material Adverse Effect.

FortisAlberta has distribution assets on Indigenous Peoples' lands in Alberta with access permits held by TransAlta Utilities Corporation. To acquire these permits, FortisAlberta requires approval from First Nations and Crown-Indigenous Relations and Northern Affairs Canada. FortisAlberta may be unable to obtain such approvals or negotiate land-use agreements with reasonable terms. Significant failures in these regards could have a Material Adverse Effect.

Labour Relations

Most of the Corporation's utilities employ members of labour unions or associations under collective bargaining agreements. Fortis considers its labour relationships to be satisfactory but there is no assurance that this will continue or that existing collective bargaining agreements will be renewed on reasonable terms without work disruption or other job action. Significant failures in these regards could cause service interruptions and/or labour cost increases for which the regulator disallows full recovery in rates, and could have a Material Adverse Effect.

MANAGEMENT DISCUSSION AND ANALYSIS	32	December 31, 2019

Legal, Administrative and Other Proceedings

These proceedings arise in the ordinary course of business and may include environmental claims, employment-related claims, securities-based litigation, contractual disputes, personal injury or property damage claims, actions by regulatory or tax authorities, and other matters. Unfavourable outcomes such as judgments or settlements for monetary or other damages, injunctions, denial or revocation of permits, reputational harm, and other results could have a Material Adverse Effect.

ACCOUNTING MATTERS

New Accounting Policies

Leases

Effective January 1, 2019, the Corporation adopted ASU No. 2016-02, Leases, that requires lessees to recognize a right-of-use asset and lease liability for all leases with a lease term greater than 12 months, along with additional disclosures.

Hedging

Fair Value Measurement Disclosures

Pensions and Other Post-Retirement Plan Disclosures

MANAGEMENT DISCUSSION AND ANALYSIS	33	December 31, 2019

Future Accounting Pronouncements

Income Taxes

Critical Accounting Estimates

General

The preparation of the 2019 Annual Financial Statements required management to make estimates and judgments that affect the reported amounts of, and disclosures related to, assets, liabilities, revenues, expenses, gains, losses and contingencies. 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 recognized in the period they become known. Actual results may differ significantly from these estimates.

Regulatory Assets and Liabilities

As at December 31, 2019, Fortis recognized regulatory assets of $3.4 billion (December 31, 2018 - $3.1 billion) and regulatory liabilities of $3.4 billion (December 31, 2018 - $3.6 billion).

Regulatory assets represent future revenues and/or receivables associated with incurred costs 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) an obligation to provide future service that customers have paid for in advance.

The recognition of regulatory assets and liabilities and the period(s) of settlement are often estimates based on past, existing or expected regulatory orders in relation to the nature of the underlying amounts and are subject to regulatory approval. Historically, actual settlement amounts and periods have generally not differed materially from those estimated, but there is no assurance that this will always be the case. Differences arising from the regulator's orders would be recognized in accordance with those orders, whereby any amounts disallowed would be immediately recognized in earnings with the remainder recognized in earnings in accordance with their inclusion in customer rates.

MANAGEMENT DISCUSSION AND ANALYSIS	34	December 31, 2019

Employee Future Benefits

Key Estimates and Assumptions				OPEB Plans
Years Ended December 31		2018		2019		2018
Funded status (1) ( millions)
Benefit obligation (2)	)	(3,207	)	(712	)	(655	)
Plan assets		2,830		343		293
	)	(377	)	(369	)	(362	)
Net benefit cost (2) ( millions)		83		28		34
Key assumptions: (weighted average %)
Discount rate (3)
During the year		3.56		4.10		3.57
As at December 31		4.07		3.25		4.13
Expected long-term rate of return on plan assets (4)		5.80		5.50		5.48
Rate of compensation increase		3.35		—		—
Health care cost trend increase rate (5)		—		4.62		4.61

All values are in US Dollars.

^(1)^	Periodic actuarial valuations determine funding contributions for the pension plans and US OPEB plans, while Canadian OPEB plans are unfunded
^(2)^	Actuarially determined using the projected benefits method prorated on service and management's best estimate of expected plan investment performance, salary escalation, average remaining service life of employees, mortality rates and, for OPEB plans, expected health care costs
---	---
^(3)^	Reflects market interest rates on high‑quality bonds with cash flows that match the timing and amount of expected pension payments
---	---
^(4)^	Developed using best estimates of expected returns, volatilities and correlations for each class of asset. Estimates are based on historical performance, future expectations and periodic portfolio rebalancing among the diversified asset classes.
---	---
^(5)^	Actuarially determined, the projected 2020 rate is 6.15% and is assumed to decrease over the next 12 years to the ultimate rate of 4.62% in 2031 and thereafter.
---	---
Sensitivity Analysis								Health Care Cost<br><br>Trend Rate -<br><br>1% change
---	---	---	---	---	---	---	---	---	---	---
	Rate of Return -<br><br>1% change				Discount Rate -<br><br>1% change			Trend Rate -
Year ended December 31, 2019	1% change				1% change			1% change
($ millions)	Increase		Decrease		Increase		Decrease	Increase	Decrease
Defined benefit pension plans
Net benefit cost	(25	)	23		(29	)	55	n/a	n/a
Projected benefit obligation	25		(80	)	(482	)	612	n/a	n/a
OPEB plans
Net benefit cost	(3	)	3		(7	)	10	24	(18	)
Accumulated benefit obligation	n/a		n/a		(100	)	128	104	(83	)

At the regulated utilities, changes in net benefit cost are generally expected to be reflected in customer rates, subject to regulatory lag and forecast risk at certain utilities.

At FortisAlberta, cash contributions are expensed and reflected in customer rates with any difference between the cash contributions and the net benefit cost deferred as a regulatory asset/liability. ITC, Central Hudson, FortisBC Energy, FortisBC Electric and Newfoundland Power have regulator‑approved mechanisms to defer variations between actual net pension cost and that forecast and reflected in customer rates. There is no assurance that these deferral mechanisms will continue in the future.

MANAGEMENT DISCUSSION AND ANALYSIS	35	December 31, 2019

Depreciation and Amortization

As at December 31, 2019, Fortis recognized property, plant and equipment and intangible assets of $35.2 billion (December 31, 2018 - $34.0 billion) representing 66% of total assets (December 31, 2018 - 64%). Depreciation and amortization totalled $1.4 billion for 2019 (2018 - $1.2 billion).

Depreciation and amortization reflect the estimated useful lives of the underlying assets, which considers historical experience, manufacturers' ratings and specifications, the past and expected future pattern and nature of usage, and other factors.

At the regulated utilities, depreciation rates require regulatory approval and include a provision for estimated future asset removal costs not identified as a legal obligation. Estimates primarily reflect historical experience and expected cost trends. The provision is recognized as a long-term regulatory liability against which actual removal costs are netted when incurred. As at December 31, 2019, this regulatory liability was $1.2 billion (December 31, 2018 - $1.2 billion).

Depreciation rates at the regulated utilities are typically determined through periodic depreciation studies performed by external experts. Where actual experience differs from previous estimates, resultant differences are generally reflected in future depreciation rates and thereby recovered or refunded through customer rates in the manner prescribed by the regulator.

Goodwill Impairment

As at December 31, 2019, Fortis recognized goodwill of $12.0 billion (December 31, 2018 - $12.5 billion), representing 22% of total assets (December 31, 2018 - 24%).

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 for certain reporting units 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. Otherwise, the primary method for estimating fair value of the reporting units is the income approach, whereby net cash flow projections are discounted using an enterprise value method. 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.

The recognition of impairment losses could have a Material Adverse Effect. Such losses are not recoverable in regulated utility rates. To the extent impairment losses signal lower expected future cash flows to support interest payments on unregulated holding company debt and dividends on common shares, they could adversely affect the future cost of such capital, expressed as higher interest rates on such debt, which is not recoverable in regulated utility rates, and lower common share market prices.

Income Tax

As at December 31, 2019, deferred income tax liabilities, current income tax receivable included in accounts receivable, deferred income taxes included in regulatory assets, and deferred income taxes included in regulatory liabilities totalled $3.0 billion, $35 million, $1.6 billion and $1.4 billion, respectively (December 31, 2018 - $2.7 billion, $91 million, $1.5 billion and $1.6 billion, respectively). Income tax expense was $289 million in 2019 (2018 - $165 million).

Current income taxes reflect the estimated taxes payable/receivable in the current year based on enacted tax rates and laws, and the estimated proportion of taxable earnings/loss attributable to various jurisdictions.

Deferred income tax assets/liabilities reflect temporary differences between the tax and accounting basis of assets/liabilities. A deferred income tax asset or liability is determined for each temporary difference based on enacted income tax rates and laws in effect when the temporary differences are expected to be recovered or settled. To the extent future tax recovery is not assessed as "more likely than not", a valuation allowance is recognized in earnings when created or adjusted.

MANAGEMENT DISCUSSION AND ANALYSIS	36	December 31, 2019

At the regulated utilities, differences between the tax expense/recovery normally recognized under US GAAP and that reflected in customer rates, which is expected to be recovered from/refunded to customers in future rates, are recognized as regulatory assets/liabilities. These regulatory assets/liabilities are subsequently amortized to earnings in accordance with their inclusion in customer rates pursuant to the regulator's orders. Otherwise, changes in expectations and resultant estimates arising from changes in tax rates, tax laws, jurisdictional earnings allocations and other factors are recognized in earnings upon occurrence.

Derivatives

The fair values of derivatives are based on estimates that cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting future earnings or cash flows. See "Financial Instruments - Derivatives" below.

Contingencies

The Corporation and its subsidiaries are subject to various legal proceedings and claims arising in the ordinary course of business, including those generally described under "Business Risks - Indigenous Peoples' Land Claims" on page 32, for which no amounts have been accrued because the outcomes currently cannot be reasonably determined. Further information is provided in Note 29 in the 2019 Annual Financial Statements.

While Fortis currently believes that these matters are unlikely to have a Material Adverse Effect, there is no assurance that this will be the case.

FINANCIAL INSTRUMENTS

LONG-TERM DEBT AND OTHER

As at December 31, 2019, the carrying value of long-term debt, including the current portion, was $22.3 billion (December 31, 2018 - $24.2 billion) compared to an estimated fair value of $25.3 billion (December 31, 2018 - $25.1 billion). Since Fortis does not intend to settle long-term debt prior to maturity, the excess of fair value over carrying value does not represent an actual liability.

The consolidated carrying value of the remaining financial instruments, other than derivatives, approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature.

DERIVATIVES

Fortis generally limits derivative usage to those qualifying as accounting, economic or cash flow hedges, or those that are otherwise approved for regulatory recovery. Derivatives are recorded at fair value, with certain exceptions, including those derivatives that qualify for the normal purchase and normal sale exception.

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.

MANAGEMENT DISCUSSION AND ANALYSIS	37	December 31, 2019

Unrealized gains/losses associated with changes in the fair value of these energy contracts are deferred as a regulatory asset/liability for recovery from/refund to customers in future rates, as permitted by the regulators. As at December 31, 2019, unrealized losses of $119 million (December 31, 2018 - $57 million) were recognized as regulatory assets and unrealized gains of $2 million (December 31, 2018 - $9 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 utilizing independent third-party information, where possible.

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/losses associated with changes in the fair value of these energy contracts are recognized in revenue. During 2019 unrealized losses of $16 million (2018 - unrealized losses of $12 million) were recognized in revenue.

Total return swaps

The Corporation holds total return swaps to manage the cash flow risk associated with forecasted future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $111 million and terms of one to three years expiring in January 2020, 2021 and 2022. Fair values are measured using an income valuation approach based on forward pricing curves. During 2019 unrealized gains of $11 million (2018 - unrealized gains of less than $1 million) were recognized in other income, net.

Foreign exchange contracts

The Corporation holds US dollar foreign exchange contracts to help mitigate exposure to volatility of foreign exchange rates. The contracts expire in 2020 and have a combined notional amount of $166 million. Fair values are measured using independent third-party information. During 2019 unrealized gains of $11 million (2018 - unrealized losses of $11 million) were recognized in other income, net.

Interest rate swaps

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/losses on these funds are recognized in other income, net and were not material for 2019 and 2018.

MANAGEMENT DISCUSSION AND ANALYSIS	38	December 31, 2019

Derivative Fair Values
($ millions)	Level 1 ^(1)^		Level 2 ^(1)^		Level 3 ^(1)^		Total
As at December 31, 2019
Assets ^(2)^
Energy contracts subject to regulatory deferral	—		22		—		22
Energy contracts not subject to regulatory deferral	—		8		—		8
Foreign exchange contracts, interest rate and total return swaps	14		4		—		18
Other investments	121		—		—		121
	135		34		—		169
Liabilities ^(3)^
Energy contracts subject to regulatory deferral	(1	)	(138	)	—		(139	)
Energy contracts not subject to regulatory deferral	—		(12	)	—		(12	)
	(1	)	(150	)	—		(151	)
As at December 31, 2018
Assets ^(2)^
Energy contracts subject to regulatory deferral	—		33		8		41
Energy contracts not subject to regulatory deferral	—		13		3		16
Other investments	155		—		—		155
	155		46		11		212
Liabilities ^(3)^
Energy contracts subject to regulatory deferral	—		(86	)	(3	)	(89	)
Energy contracts not subject to regulatory deferral	—		(1	)	—		(1	)
Foreign exchange contracts, interest rate and total return swaps	(8	)	(1	)	—		(9	)
	(8	)	(88	)	(3	)	(99	)
^(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 measurement. At December 31, 2019, all level 3 assets and liabilities transferred to level 2 because observable market data became available.
---	---
^(2)^	Current portion is included in accounts receivable and other current assets, with the remainder included in other assets.
---	---
^(3)^	Current portion is included in accounts payable and other current liabilities, with the remainder included in other liabilities.
---	---
Derivative Volumes ^(1)^
---	---	---
As at December 31	2019	2018
Energy contracts subject to regulatory deferral
Electricity swap contracts (GWh)	628	774
Electricity power purchase contracts (GWh)	3,198	651
Gas swap contracts (PJ)	168	203
Gas supply contract premiums (PJ)	241	266
Energy contracts not subject to regulatory deferral
Wholesale trading contracts (GWh)	1,855	1,440
Gas swap contracts (PJ)	43	37
^(1)^	Energy contracts settle on various dates through 2029.
---	---
MANAGEMENT DISCUSSION AND ANALYSIS	39	December 31, 2019
---	---	---

SELECTED ANNUAL FINANCIAL INFORMATION

Years ended December 31
( millions, except as indicated)	2018	2017
Revenue	8,390	8,301
Net earnings	1,286	1,125
Common Equity Earnings	1,100	963
EPS: ()
Basic	2.59	2.32
Diluted	2.59	2.31
Total assets	53,051	47,822
Long-term debt (excluding current portion)	23,159	20,691
Dividends declared: ()
Per common share	1.750	1.650
Per first preference share:
Series F	1.2250	1.2250
Series G (1)	1.0345	0.9708
Series H	0.6250	0.6250
Series I (2)	0.7116	0.5262
Series J	1.1875	1.1875
Series K (3)	1.0000	1.0000
Series M (4)	1.0250	1.0250

All values are in US Dollars.

^(1)^	The annual dividend per share was reset from $0.9708 to $1.0983 for the five-year period from September 1, 2018 up to but excluding September 1, 2023.
^(2)^	Floating quarterly dividend rate is reset every quarter based on the then current three-month Government of Canada Treasury Bill rate plus the applicable reset dividend yield.
---	---
^(3)^	The annual dividend per share was reset from $1.0000 to $0.9823 for the five-year period from March 1, 2019 up to but excluding March 1, 2024.
---	---
^(4)^	The annual dividend per share was reset from $1.0250 to $0.9783 for the five-year period from December 1, 2019 up to but excluding December 1, 2024.
---	---

2019/2018

For a discussion of the changes in revenue, net earnings, Common Equity Earnings, EPS, total assets and long-term debt refer to "Performance at a Glance" on page 3, "Operating Results" on page 7, and "Financial Position" on page 15.

2018/2017

The 2018/2017 increase in revenue reflects: (i) higher wholesale electricity sales at UNS Energy driven by an increase in system capacity; and (ii) the flow through in 2018 customer rates of higher overall energy supply costs. The increase was partially offset by: (i) the recovery of lower income tax expense due to US tax reform; (ii) mark-to-market accounting adjustments for natural gas derivatives at Aitken Creek; and (iii) a change in presentation of certain revenues to a net basis upon implementation of ASC 606, Revenue from Contracts with Customers, in 2018.

The 2018/2017 increase in earnings primarily reflects growth at both the regulated and non-regulated businesses, as well as lower income tax expense, partially offset by one-time favourable adjustments recognized in 2017. Earnings in 2018 were also tempered by the ongoing impact of US tax reform and a lower ROE incentive adder at ITC effective April 2018.

The 2018/2017 increase in EPS reflects the above-noted earnings increases, partially offset by a 9.2 million increase in the weighted average number of common shares outstanding associated with the Corporation's DRIP.

The 2018/2017 increase in total assets was due to the impact of 2018 capital expenditures and foreign exchange on the translation of US dollar-denominated assets.

MANAGEMENT DISCUSSION AND ANALYSIS	40	December 31, 2019

FOURTH QUARTER RESULTS

Sales
Fourth quarters ended December 31	2019	2018	Variance
Regulated utilities
UNS Energy
Retail Electricity (GWh)	2,223	2,225	(2	)
Wholesale Electricity (GWh)	1,814	2,526	(712	)
Gas (PJ)	5	5	—
Central Hudson
Electricity (GWh)	1,188	1,250	(62	)
Gas (PJ)	6	7	(1	)
FortisBC Energy (PJ)	71	63	8
FortisAlberta (GWh)	4,279	4,343	(64	)
FortisBC Electric (GWh)	888	839	49
Other Electric (GWh)	2,427	2,450	(23	)
Non-regulated - Energy Infrastructure (GWh)	14	85	(71	)

The decrease in wholesale electricity sales was due primarily to a decrease in system capacity at Gila River Unit 2 resulting from an outage. The increase in gas volumes at FortisBC Energy was due to higher average consumption by residential and commercial customers due to colder temperatures that increased heating load and higher consumption by transportation customers.

Revenue and Common Equity Earnings
Fourth quarters ended December 31					Common Equity Earnings
( millions, except as indicated)	2018		Variance		2019		2018		Variance
Regulated utilities
ITC	390		110		171		92		79
UNS Energy	541		(31	)	38		27		11
Central Hudson	234		(8	)	30		24		6
FortisBC Energy	371		57		77		72		5
FortisAlberta	140		10		33		22		11
FortisBC Electric	111		1		12		13		(1	)
Other Electric	372		9		22		22		—
Non-regulated
Energy Infrastructure	50		(31	)	6		22		(16	)
Corporate and Other	—		—		(43	)	(33	)	(10	)
Inter-segment eliminations	(3	)	3		—		—		—
Total	2,206		120		346		261		85
Weighted average number of common shares outstanding (millions)					447.1		427.5		19.6
Basic EPS ()					0.77		0.61		0.16

All values are in US Dollars.

The increase in revenue was driven by the $91 million favourable adjustment to revenue at ITC associated with the November 2019 FERC Order (see "Regulatory Highlights" on page 13) and higher revenue at FortisBC Energy due to overall higher flow-through costs. The increase was partially offset by lower revenue at UNS Energy due to lower short-term wholesale sales and lower revenue in the Energy Infrastructure segment due to the disposition of the Waneta Expansion in April 2019 (see "Significant Items" on page 3) and lower hydroelectric production in Belize.

The increase in Common Equity Earnings was due primarily to the November 2019 FERC Order at ITC, along with Rate Base growth at the regulated utilities.

MANAGEMENT DISCUSSION AND ANALYSIS	41	December 31, 2019

The increase in basic EPS reflects higher Common Equity Earnings, partially offset by a 19.6 million increase in the weighted average number of common shares outstanding associated with the Corporation's common equity offering (see "Significant Items" on page 3), DRIP and ATM Program.

Cash Flows
Fourth quarters ended December 31
($ millions)	2019		2018		Variance
Cash, beginning of period	228		195		33
Cash provided by (used in):
Operating activities	634		537		97
Investing activities	(1,104	)	(999	)	(105	)
Financing activities	627		598		29
Foreign exchange	(15	)	16		(31	)
Cash associated with assets held for sale	—		(15	)	15
Cash, end of period	370		332		38

Operating Activities

The variance was due to higher cash earnings at the regulated subsidiaries, led by ITC, partially offset by unfavourable changes in working capital due primarily to timing differences.

Investing Activities

The variance reflects higher capital spending, mainly at UNS Energy, in accordance with the Corporation's capital plan.

Financing Activities

The variance reflects the issuance of common shares and redemption of Corporate debt (see "Cash Flow Summary" on page 18).

SUMMARY OF QUARTERLY RESULTS

		Common Equity
	Revenue	Earnings	Basic EPS	Diluted EPS
Quarter Ended	($ millions)	($ millions)	($)	($)
December 31, 2019	2,326	346	0.77	0.77
September 30, 2019	2,051	278	0.64	0.63
June 30, 2019	1,970	720	1.66	1.66
March 31, 2019	2,436	311	0.72	0.72
December 31, 2018	2,206	261	0.61	0.61
September 30, 2018	2,040	276	0.65	0.65
June 30, 2018	1,947	240	0.57	0.57
March 31, 2018	2,197	323	0.77	0.76

Generally, within each calendar year, quarterly results fluctuate primarily in accordance with seasonality.

Given the diversified nature of the Corporation's subsidiaries, seasonality varies. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric distribution utilities in the US are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.

Generally, from one calendar year to the next, quarterly results reflect: (i) continued organic growth driven by the Corporation's capital plan; (ii) acquisitions and dispositions; (iii) any significant temperature fluctuations from seasonal norms; (iv) the timing and significance of any regulatory decisions; (v) for revenue, the flow through in customer rates of commodity costs; and (vi) for EPS, increases in the weighted average number of common shares outstanding.

MANAGEMENT DISCUSSION AND ANALYSIS	42	December 31, 2019

December 2019/December 2018

See "Fourth Quarter Results" on page 41.

September 2019/September 2018

Common Equity Earnings increased by $2 million and basic EPS decreased by $0.01, due mainly to Rate Base growth at the regulated utilities, led by ITC, tempered by: (i) the unfavourable impact of the mark-to-market accounting of natural gas derivatives at Aitken Creek; (ii) lower hydroelectric production in Belize; and (iii) for EPS, an 11.8 million increase in the weighted average number of common shares outstanding due to the ATM Program and DRIP.

June 2019/June 2018

Common Equity Earnings increased by $480 million and basic EPS increased by $1.09, due mainly to: (i) a $484 million gain on the disposition of the Waneta Expansion; (ii) the favourable impact of the mark-to-market accounting of natural gas derivatives at Aitken Creek; (iii) Rate Base growth at the regulated utilities, led by ITC; and (iv) favourable foreign exchange of $7 million. The increase was tempered by: (i) lower retail sales, driven by weather, and higher depreciation and interest expense at UNS Energy; (ii) lower earnings contribution from the Energy Infrastructure segment due to lower hydroelectric production in Belize; (iii) lower realized margins at Aitken Creek; and (iv) for EPS, a 9.3 million increase in the weighted average number of common shares outstanding due to the ATM Program and DRIP.

March 2019/March 2018

Common Equity Earnings decreased by $12 million and basic EPS decreased by $0.05, due mainly to: (i) a favourable $30 million remeasurement of deferred income tax liabilities in 2018 resulting from an election to file a consolidated state income tax return, which offset earnings growth in 2019. Earnings growth was driven by: (i) strong performance at the regulated utilities due primarily to Rate Base growth; (ii) increased earnings at Central Hudson associated with its rate order effective July 1, 2018; (iii) higher electricity and gas sales at UNS Energy due largely to weather; and (iv) favourable foreign exchange of $9 million. The increase was tempered by: (i) lower earnings contribution from the Energy Infrastructure segment due to lower realized margins and higher unrealized losses on the mark-to-market accounting of natural gas derivatives at Aitken Creek, along with lower hydroelectric production in Belize; (ii) a lower ROE incentive adder at ITC; and (iii) for EPS, a 7.5 million increase in the weighted average number of common shares outstanding due mainly to the DRIP.

RELATED-PARTY 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 2019 or 2018. Inter-company balances, transactions and profit are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. These related-party transactions include: (i) the lease of gas storage capacity and gas sales by Aitken Creek to FortisBC Energy; and (ii) the sale of capacity by the Waneta Expansion to FortisBC Electric up to the April 16, 2019 disposition of the Waneta Expansion. These transactions, which are not eliminated on consolidation, did not have a material impact on consolidated earnings, financial position or cash flows.

MANAGEMENT DISCUSSION AND ANALYSIS	43	December 31, 2019

MANAGEMENT'S EVALUATION OF CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

DCP are designed to provide reasonable assurance that information required to be disclosed in reports filed with, or submitted to, securities regulatory authorities is recorded, processed, summarized and reported within the time periods specified under Canadian and US securities laws. As of December 31, 2019, an evaluation was carried out under the supervision of, and with the participation of, the Corporation's management, including the CEO and CFO, of the effectiveness of the Corporation's DCP, as defined in the applicable Canadian and United States securities laws. Based on that evaluation, the CEO and CFO concluded that such DCP are effective as of December 31, 2019.

Internal Control over Financial Reporting

ICFR is designed by, or under the supervision of, the Corporation's CEO and 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 US GAAP. 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 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.

The Corporation's management, including the Corporation's CEO and CFO, assessed the effectiveness of the Corporation's ICFR as of December 31, 2019, 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, 2019, the Corporation's ICFR was effective.

During the year ended December 31, 2019, there have been no changes in the Corporation's ICFR that have materially affected, or are reasonably likely to materially affect, the Corporation's ICFR.

OUTLOOK

The Corporation's $18.8 billion five-year capital plan is expected to increase Rate Base from $28.0 billion in 2019 to $34.5 billion by 2022 and $38.4 billion by 2024, translating into three- and five-year CAGRs of 7.2% and 6.5%, respectively. The five-year capital plan reflects the continuation of key industry trends including grid modernization and the delivery of cleaner energy. Beyond the base capital plan, Fortis continues to pursue additional energy infrastructure opportunities. Key opportunities not yet included in the five-year capital plan include: further expansion of LNG infrastructure in British Columbia; the fully permitted, cross-border, Lake Erie connector electric transmission project in Ontario; and the acceleration of cleaner energy goals in Arizona.

Fortis expects long-term growth in Rate Base to support continuing growth in earnings and dividends. Fortis is targeting average annual dividend growth of approximately 6% through 2024. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence.

MANAGEMENT DISCUSSION AND ANALYSIS	44	December 31, 2019

FORWARD-LOOKING INFORMATION

Fortis includes forward-looking information in the MD&A within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, (collectively referred to as "forward-looking information"). Forward-looking information reflects expectations of Fortis management regarding future growth, results of operations, performance, business prospects and opportunities. Wherever possible, words such as anticipates, believes, budgets, could, estimates, expects, forecasts, intends, may, might, plans, projects, schedule, should, target, will, would and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which includes, without limitation: targeted average annual dividend growth through 2024; forecast capital expenditures for 2020 and the period 2020 through 2024, and potential funding sources for the capital plan; forecast Rate Base for 2020 and 2024; the expectation that Fortis will remain at the forefront of the industry by leveraging its strengths and partnerships; expected timing, outcome and impact of regulatory filings and decisions; expected or potential funding sources for operating expenses, interest costs and capital plans; the expectation that maintaining the targeted capital structure of the regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will continue to have access to long-term capital and will remain compliant with debt covenants throughout 2020; the nature, timing, benefits and expected costs of certain capital projects including the Multi-Value Regional Transmission Projects, Transmission Conversion Project, Southline Transmission Project, Oso Grande Wind Project, Transmission Integrity Management Capabilities Project, Inland Gas Upgrades Project, Wataynikaneyap Transmission Power Project and additional opportunities beyond the base plan, including the Lake Erie Connector Project; the expectation that the adoption of future accounting pronouncements will not have a material adverse impact; and the expectation that capital investment will support growth in earnings and dividends.

Forward-looking information involves significant risks, uncertainties and assumptions. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from those discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risks" in this MD&A and in other continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2020 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation's utilities; risks associated with climate change and physical risks; the impact of fluctuations in interest rates; the impact of weather variability and seasonality on heating and cooling loads, gas distribution volumes and hydroelectric generation; and risks associated with acquisitions and capital projects.

All forward-looking information herein is given as of February 12, 2020. Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.

MANAGEMENT DISCUSSION AND ANALYSIS	45	December 31, 2019

GLOSSARY

2019 Annual Financial Statements: the Corporation's audited consolidated financial statements and notes thereto for the year ended December 31, 2019

Actual Payout Ratio: dividends per common share divided by basic EPS

Adjusted Basic EPS: Adjusted Common Equity Earnings divided by the basic weighted average number of common shares outstanding

Adjusted Common Equity Earnings: net earnings attributable to common equity shareholders adjusted as shown under "Non-US GAAP Financial Measures" on page 12

Adjusted Payout Ratio: dividends per common share divided by Adjusted Basic EPS as shown under "Non-US GAAP Financial Measures" on page 12

AESO: Alberta Electric System Operator

AFUDC: allowance for funds used during construction

Aitken Creek: Aitken Creek Gas Storage ULC, a direct 93.8%-owned subsidiary of FortisBC Holdings Inc.

ALJ: administrative law judge

ASU: Accounting Standards Update

ATM Program: at-the-market common equity program

AUC: Alberta Utilities Commission

BCUC: British Columbia Utilities Commission

BECOL: Belize Electric Company Limited, an indirect wholly owned subsidiary of Fortis

Belize Electricity: Belize Electricity Limited, in which Fortis indirectly holds a 33% equity interest

CAGR(s): compound average growth rate of a particular item. CAGR = (EV/BV) ^1-N^ -1, where: (i) EV is the ending value of the item; (ii) BV is the beginning value of the item; and (iii) N is the number of periods

Caribbean Utilities: Caribbean Utilities Company, Ltd., an indirect approximately 60%-owned (as at December 31, 2019) subsidiary of Fortis, together with its subsidiary

Central Hudson: CH Energy Group Inc., an indirect wholly owned subsidiary of Fortis, together with its subsidiaries, including Central Hudson Gas & Electric Corporation

CEO: Chief Executive Officer of Fortis

CFO: Chief Financial Officer of Fortis

Common Equity Earnings: net earnings attributable to common equity shareholders

Corporation: Fortis Inc.

COS Regulation: cost of service regulation

CPCN: Certificate of Public Convenience and Necessity

DBRS Morningstar: DBRS Limited

DCP: disclosure controls and procedures

DRIP: dividend reinvestment plan

EPS: earnings per common share

ERM: enterprise risk management

FERC: Federal Energy Regulatory Commission

Fortis: Fortis Inc.

FortisAlberta: FortisAlberta Inc., an indirect wholly owned subsidiary of Fortis

FortisBC Electric: FortisBC Inc., an indirect wholly owned subsidiary of Fortis, together with its subsidiaries

FortisBC Energy: FortisBC Energy Inc., an indirect wholly owned subsidiary of Fortis, together with its subsidiaries

FortisOntario: FortisOntario Inc., a direct wholly owned subsidiary of Fortis, together with its subsidiaries

FortisTCI: FortisTCI Limited, an indirect wholly owned subsidiary of Fortis, together with its subsidiary

FX: foreign exchange associated with the translation of US dollar-denominated amounts

GHG: greenhouse gas

Gila River Unit 2: UNS Energy's Gila River natural gas generation station unit 2

GWh: gigawatt hour(s)

ICFR: internal controls over financial reporting

ITC: ITC Investment Holdings Inc., an indirect 80.1%-owned subsidiary of Fortis, together with its subsidiaries, including International Transmission Company, Michigan Electric Transmission Company, LLC, ITC Midwest LLC, and ITC Great Plains, LLC

ITC's MISO Subsidiaries: International Transmission Company, Michigan Electric Transmission Company, LLC, and ITC Midwest LLC

LIBOR: London Interbank Offered Rate

LNG: liquefied natural gas

kV: kilovolt

MANAGEMENT DISCUSSION AND ANALYSIS	46	December 31, 2019

Major Capital Projects: projects, other than ongoing maintenance projects, individually costing $200 million or more

Maritime Electric: Maritime Electric Company, Limited, an indirect wholly owned subsidiary of Fortis

Material Adverse Effect: a material adverse effect on the Corporation's business, results of operations, financial position or liquidity, on a consolidated basis

MD&A: the Corporation's management discussion and analysis for the year ended December 31, 2019

MISO: Midcontinent Independent System Operator, Inc.

Moody's: Moody's Investor Services, Inc.

MW: megawatt(s)

Newfoundland Power: Newfoundland Power Inc., a direct wholly owned subsidiary of Fortis

NOI: notice of inquiry

Non-US GAAP Financial Measures: financial measures that do not have a standardized meaning prescribed by US GAAP

November 2019 FERC Order: a FERC order issued in November 2019 that reduced the base ROE for ITC's MISO Subsidiaries

NYSE: New York Stock Exchange

OEB: Ontario Energy Board

OPEB: other post-employment benefits

Operating Cash Flows: cash from operating activities

PBR: performance-based rate-setting

PJ: petajoule(s)

PPA: power purchase agreement

Q3 2019 MD&A: interim management discussion and analysis for the three and nine months ended September 30, 2019

Rate Base: the stated value of property on which a regulated utility is permitted to earn a specified return in accordance with its regulatory construct

ROA: rate of return on Rate Base

ROE: rate of return on common equity

S&P: Standard & Poor's Financial Services LLC

SEDAR: Canadian System for Electronic Document Analysis and Retrieval

TEP: Tucson Electric Power Company, a direct wholly owned subsidiary of UNS Energy

TSR: total shareholder return, which is a measure of the return to common equity shareholders in the form of share price appreciation and dividends (assuming reinvestment) over a specified time period in relation to the share price at the beginning of the period

TSX: Toronto Stock Exchange

UNS Energy: UNS Energy Corporation, an indirect wholly owned subsidiary of Fortis, together with its subsidiaries, including TEP, UNS Electric, Inc. and UNS Gas, Inc.

US: United States of America

US GAAP: accounting principles generally accepted in the US

Waneta Expansion: Waneta Expansion hydroelectric generation facility, in which Fortis held a 51% controlling interest prior to April 2019

Wataynikaneyap Partnership: Wataynikaneyap Power Limited Partnership

MANAGEMENT DISCUSSION AND ANALYSIS	47	December 31, 2019

		Exhibit

Exhibit 99.4

Rule 13a-14(a) or Rule 15d-14(a) Certification - Chief Executive Officer

I, Barry V. Perry, certify that:

1.	I have reviewed this annual report on Form 40-F of Fortis Inc.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
---	---
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
---	---
4.	The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
---	---
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
---	---
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
---	---
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
---	---
5.	The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
---	---
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
---	---
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.
---	---

/s/ Barry V. Perry

Barry V. Perry

President and Chief Executive Officer

St. John’s, Canada

February 13, 2020

		Exhibit

Exhibit 99.5

Rule 13a-14(a) or Rule 15d-14(a) Certification - Chief Financial Officer

I, Jocelyn H. Perry, certify that:

1. I have reviewed this annual report on Form 40-F of Fortis Inc.;

2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;
---	---
4.	The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:
---	---
(a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
---	---
(b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;
---	---
(c)	Evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
---	---
(d)	Disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting; and
---	---
5.	The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of the issuer’s board of directors (or persons performing the equivalent functions):
---	---
(a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information; and
---	---
(b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.
---	---

/s/ Jocelyn H. Perry

Jocelyn H. Perry

Executive Vice President, Chief Financial Officer

St. John’s, Canada

February 13, 2020

		Exhibit

Exhibit 99.6

Rule 13a-14(b) Certification Chief Executive Officer

In connection with the annual report of Fortis Inc. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Barry V. Perry, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
---	---

/s/ Barry V. Perry

Barry V. Perry

President and Chief Executive Officer

St. John’s, Canada

February 13, 2020

		Exhibit

Exhibit 99.7

Rule 13a-14(b) Certification Chief Financial Officer

In connection with the annual report of Fortis Inc. (the “Company”) on Form 40-F for the fiscal year ended December 31, 2019 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jocelyn H. Perry, Executive Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. §1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.	The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and
2.	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.
---	---

/s/ Jocelyn H. Perry

Jocelyn H. Perry

Executive Vice President, Chief Financial Officer

St. John’s, Canada

February 13, 2020

		Exhibit

Exhibit 99.8

Consent of Report of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in Registration Statement Nos. 333-215777, 333-226663 and 333-236213 on Form S-8, 333-228593 on Form F-10, and 333-218032 on Form F-3 and to the use of our reports dated February 13, 2020 relating to the consolidated financial statements of Fortis Inc. and subsidiaries and the effectiveness of Fortis Inc.'s internal control over financial reporting appearing in this Annual Report on Form 40-F of Fortis Inc. for the year ended December 31, 2019.

/s/ Deloitte LLP

Chartered Professional Accountants

St. John’s, Canada

February 13, 2020

		Exhibit

Exhibit 99.9

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 40-F

☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934

☒ ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-37915

FORTIS INC.

Fortis Place, Suite 1100

5 Springdale Street

St. John's, Newfoundland and Labrador

Canada A1E 0E4

James R. Reid

(709) 737-2800

(Address and telephone number of Registrant's principal executive offices)

CT Corporation System

111 Eighth Avenue

New York, New York 10011

(212) 590‑9070

Securities registered or to be registered pursuant to Section 12(b) of the Act:

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

None

☒ Annual information form ☒ Audited annual financial statements

463,274,945 Common Shares as of December 31, 2019

Emerging growth company ☐

EXPLANATORY NOTE

FORWARD LOOKING INFORMATION

CURRENCY

CERTIFICATIONS

DISCLOSURE CONTROLS AND PROCEDURES

MANAGEMENT'S ANNUAL REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

ATTESTATION REPORT OF THE INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

CHANGES IN INTERNAL CONTROL OVER FINANCIAL REPORTING

NOTICES PURSUANT TO REGULATION BTR

IDENTIFICATION OF THE AUDIT COMMITTEE

AUDIT COMMITTEE FINANCIAL EXPERT

PRINCIPAL ACCOUNTANT FEES AND SERVICES

AUDIT COMMITTEE PRE‑APPROVAL POLICIES AND PROCEDURES

CODE OF ETHICS

OFF‑BALANCE SHEET ARRANGEMENTS

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

COMPARISON OF NYSE CORPORATE GOVERNANCE RULES

UNDERTAKING

DISCLOSURE PURSUANT TO SECTION 13(r) OF THE EXCHANGE ACT

INCORPORATION BY REFERENCE

EXHIBIT INDEX

SIGNATURES

Exhibit 99.2

FORTIS INC.

TABLE OF CONTENTS

Management's Report on Internal Control over Financial Reporting

Barry V. Perry

Jocelyn H. Perry

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Opinion on the Financial Statements

Basis for Opinion

Critical Audit Matters

Assessment for Impairment of Goodwill - Refer to Notes 3 and 13 to the financial statements

Critical Audit Matter Description

How the Critical Audit Matter was Addressed in the Audit

Impact of Rate Regulation on the Financial Statements - Refer to Notes 2, 3 and 9 to the Financial Statements

Critical Audit Matter Description

How the Critical Audit Matter was Addressed in the Audit

Report of Independent Registered Public Accounting Firm

Opinion on Internal Control over Financial Reporting

Basis for Opinion

Definition and Limitations of Internal Control over Financial Reporting

1. DESCRIPTION OF BUSINESS

Regulated Utilities

80.1%

19.9%

3,143

135

225

39%

60%

33%