# EDGAR Filing Document

**Accession Number:** 0001666175
**File Stem:** 0001666175-23-000014
**Filing Date:** 2023-2
**Character Count:** 621886
**Document Hash:** 3faeabbd22c9a1807eabb097a5dfb7c2
**Contains OCR:** False
**Source Format:** 

## Filing Content

## Filing Summary
**0001666175-23-000014.hdr.sgml**: 20230210

**ACCESSION NUMBER**: 0001666175-23-000014

**CONFORMED SUBMISSION TYPE**: 40-F

**PUBLIC DOCUMENT COUNT**: 165

**CONFORMED PERIOD OF REPORT**: 20221231

**FILED AS OF DATE**: 20230210

**DATE AS OF CHANGE**: 20230210

**FILER**: 

**COMPANY DATA:**
- **COMPANY CONFORMED NAME:** Fortis Inc.
- **CENTRAL INDEX KEY:** 0001666175
- **STANDARD INDUSTRIAL CLASSIFICATION:** ELECTRIC SERVICES [4911]
- **IRS NUMBER:** 980352146
- **STATE OF INCORPORATION:** A4
- **FISCAL YEAR END:** 1231

**FILING VALUES:**
- **FORM TYPE:** 40-F
- **SEC ACT:** 1934 Act
- **SEC FILE NUMBER:** 001-37915
- **FILM NUMBER:** 23608422

**BUSINESS ADDRESS:**
- **STREET 1:** 5 SPRINGDALE STREET
- **STREET 2:** FORTIS PLACE, SUITE 1100
- **CITY:** ST. JOHN'S
- **STATE:** A4
- **ZIP:** A1B 3T2
- **BUSINESS PHONE:** 709 737-2800

**MAIL ADDRESS:**
- **STREET 1:** 5 SPRINGDALE STREET
- **STREET 2:** FORTIS PLACE, SUITE 1100
- **CITY:** ST. JOHN'S
- **STATE:** A4
- **ZIP:** A1B 3T2

?xml version="1.0" ? fts-20221231

    

**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**

**OR**

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

**For the fiscal year ended December 31, 2022** 

**Commission file number: 001-37915** 

_______________________

**FORTIS INC.** 

*(Exact name of Registrant as specified in its charter)*

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| | | |
|:---|:---|:---|
| **Newfoundland and Labrador, Canada** | **4911** | **98-0352146** |
| &nbsp;&nbsp;*(Province of other jurisdiction of<br>incorporation or organization)* | *(Primary Standard Industrial Classification<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** 

**(709) 737-2800** 

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

_______________________

**CT Corporation System** 

**28 Liberty Street**

**New York, New York 10015** 

**(212) 894-8940**

*(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.

482,150,634 Common Shares as of December 31, 2022

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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 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.&nbsp;&nbsp;&nbsp;&nbsp;☐

† 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.

Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.&nbsp;&nbsp;&nbsp;&nbsp;☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.&nbsp;&nbsp;&nbsp;&nbsp;☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b).&nbsp;&nbsp;&nbsp;&nbsp;☐

**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 2023-2027, including cleaner energy investments; forecast rate base and rate base growth for 2023 and through 2027; targeted annual dividend growth through 2027; the expectation that Fortis is well-positioned to capitalize on evolving industry opportunities, including additional investment opportunities beyond the capital plan; the expectation that volatility in energy prices, global supply chain constraints and persistent inflation will not have a material impact on operations or financial results in 2023 or the 2023-2027 capital plan; the 2030 greenhouse gas emissions reduction target; the 2035 greenhouse gas emissions reduction target and projected asset mix; the expectation to achieve the 2030 and 2035 greenhouse gas emissions reduction targets without the use of carbon offsets; the 2050 net-zero direct greenhouse gas emissions target and how that target is expected to be achieved; Tucson Electric Power's Integrated Resource Plan and the

------

expectation to exit coal by 2032; Tucson Electric Power's estimated mine reclamation costs; the expected timing, outcome and impact of regulatory proceedings and decisions; the expected or potential funding sources for operating expenses, interest costs and capital expenditures; the expectation that maintaining the targeted capital structure of the regulated operating subsidiaries will not have an impact on the Corporation's ability to pay dividends in the foreseeable future; the 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 in 2023; the expected uses of proceeds from debt financings; the targeted capital structure; the nature, timing, benefits and expected costs of certain capital projects, including ITC's transmission projects associated with the Midcontinent Independent System Operator, Inc. long-range transmission plan, renewable generation projects at UNS Energy, Vail-to-Tortolita Transmission Project, Tilbury Liquefied Natural Gas Storage Expansion, Advanced Metering Infrastructure Project, Eagle Mountain Woodfibre Gas Line Project, Tilbury 1B Project, Okanagan Capacity Upgrade, and Wataynikaneyap Transmission Power Project, and additional opportunities beyond the capital plan, including investments associated with the Inflation Reduction Act, the Midcontinent Independent System Operator, Inc. long-range transmission plan, Tucson Electric Power's Integrated Resource Plan, climate adaptation and grid resiliency, and renewable gas solutions and liquefied natural gas infrastructure in British Columbia; the expected in-service dates for certain projects; the expectation that the introduction of a corporate alternative minimum income tax will not have a material impact on financial results, operating cash flow or credit ratings; the expectation that long-term growth in rate base will drive earnings that support dividend growth guidance of 4-6% annually through 2027; and the expectation that the dividend growth guidance will provide flexibility to fund more capital internally.

Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: no material impact from volatility in energy prices, global supply chain constraints and rising inflation; reasonable regulatory decisions and the expectation of regulatory stability; the successful execution of the capital plan; no material capital project or financing cost overrun; sufficient human resources to deliver service and execute the capital plan; the realization of additional opportunities beyond the capital plan; no significant variability in interest rates; the Corporation's board of directors (the "Board") exercising its discretion to declare dividends, taking into account the financial performance and condition of the Corporation; 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 the Annual MD&A (as defined below), 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 2023 include, but are not limited to:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks associated with changes in utility regulation, including the outcome of regulatory proceedings at the Corporation's utilities;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• physical risks related to the provision of electric and gas service, which can be intensified by the impacts of climate change;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks related to environmental laws and regulations;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks associated with capital projects and the impact on the Corporation's continued growth;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks associated with cybersecurity and information and operations technology, including disruption to electric and gas service, consumption and load settlement systems, and financial or general operations, as well as the risk of misappropriation and/or disclosure of confidential or proprietary information;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• the impact of weather variability and seasonality on heating and cooling loads, gas distribution volumes and hydroelectric generation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks associated with commodity price volatility and supply of purchased power; and,

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;• risks related to general economic conditions, including inflation, interest rate and foreign exchange risks.

------

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 9, 2023, 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$1.34.

**CANADIAN ANNUAL DISCLOSURE DOCUMENTS**

The following documents are filed as exhibits to this Form 40-F:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.The Annual Information Form for the fiscal year ended December 31, 2022, which is filed as Exhibit 99.1 to this Form 40-F and incorporated by reference herein (the "AIF");

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.Audited Consolidated Financial Statements for the fiscal year ended December 31, 2022, which are filed as Exhibit 99.2 to this Form 40-F and incorporated by reference herein (the "Annual Financial Statements"); and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.Management's Discussion and Analysis for the fiscal year ended December 31, 2022, which is filed as Exhibit 99.3 to this Form 40-F and incorporated by reference herein (the "Annual MD&A").

**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, 2022, 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, 2022.

**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 U.S. 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, 2022, 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, 2022, the Corporation's internal control over financial reporting was effective.

------

Deloitte LLP, an independent registered public accounting firm, has audited 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 2 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 5 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, 2022, 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, 2022 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 Maura J. Clark (Chair), Tracey C. Ball, Lawrence T. Borgard, Margarita K. Dilley, Lisa L. Durocher, Douglas J. Haughey, Gianna M. Manes and Jo Mark Zurel, as described under "Audit Committee - Members" on page 26 of 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.

**CODE OF ETHICS**

The Corporation has a "code of ethics" (as defined in paragraph (9)(b) of General Instruction B to Form 40-F) that applies to all the Corporation's employees, officers and directors, including the Chief Executive Officer, Chief Financial Officer, principal accounting officer or controller, and persons performing similar functions. The Corporation's code of ethics (referred to as the "Code of Conduct") 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, 2022 there have not been any amendments to, or waivers of, including implicit waivers of, any provision of the Code of Conduct which is applicable to the Corporation's Chief Executive Officer, Chief Financial Officer, principal accounting officer or controller, or persons performing similar functions and that relates to any element of the code of ethics definition enumerated in paragraph (9)(b) of General Instruction B to Form 40-F.

**PRINCIPAL ACCOUNTANT FEES AND SERVICES**

Deloitte LLP served as the Corporation's independent public accountant for the fiscal years ended December 31, 2022 and 2021. 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 27 of the AIF.

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**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 27 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.

**OFF**-**BALANCE SHEET ARRANGEMENTS**

Except for letters of credit outstanding of $128 million as at December 31, 2022 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 only as described herein. 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, 2022.

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**INCORPORATION BY REFERENCE**

The Corporation's 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 the Corporation's Registration Statements on Form S-8 (File No. 333-226663), Form S-8 (File No. 333-236213), Form F-3 (File No. 333-249039), Form F-10 (File No. 333-268493), and Form S-8 (File No. 333-264838).

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**EXHIBIT INDEX**

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| | |
|:---|:---|
| **Exhibit** | **Description** |
| <u>[99.1](a2022annual-991aif.htm)</u> | <u>[Annual Information Form of the Corporation dated February](a2022annual-991aif.htm)[9, 2023](a2022annual-991aif.htm)</u> |
| <u>[99.2](fts-20221231_d2.htm)</u> | <u>[Audited Consolidated Financial Statements for the fiscal year ended December 31, 20](fts-20221231_d2.htm)[2](fts-20221231_d2.htm)[2](fts-20221231_d2.htm)</u> |
| <u>[99.3](a2022annual-993mda.htm)</u> | <u>[Management's Discussion and Analysis for the fiscal year ended December 31, 2022](a2022annual-993mda.htm)</u> |
| <u>[99.4](a2022annual-994certificati.htm)</u> | <u>[Chief Executive Officer certification required by Rule 13a-14(a)](a2022annual-994certificati.htm)</u> |
| <u>[99.5](a2022annual-995certificati.htm)</u> | <u>[Chief Financial Officer certification required by Rule 13a-14(a)](a2022annual-995certificati.htm)</u> |
| <u>[99.6](a2022annual-996certificati.htm)</u> | <u>[Chief Executive Officer certification required by Rule 13a-14(b)](a2022annual-996certificati.htm)</u> |
| <u>[99.7](a2022annual-997certificati.htm)</u> | <u>[Chief Financial Officer certification required by Rule 13a-14(b)](a2022annual-997certificati.htm)</u> |
| <u>[99.8](a2022annual-998consentofde.htm)</u> | <u>[Consent of Deloitte LLP](a2022annual-998consentofde.htm)</u> |
| 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 |

---

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**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.

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| |
|:---|
| **FORTIS INC.** |
| /s/ Jocelyn H. Perry |
| Jocelyn H. Perry<br>Executive Vice President, Chief Financial Officer |
| Date: February 10, 2023 |

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## Exhibit 99.1

**Exhibit 99.1**

![aif2022cover.jpg](aif2022cover.jpg)

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<u>Annual Information Form</u>

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| | | | |
|:---|:---|:---|:---|
| **Table of Contents** | **Table of Contents** | **Table of Contents** | **Table of Contents** |
| Forward-Looking Information | **2** | Legal Proceedings and Regulatory Actions | **20** |
| Glossary | **3** | Risk Factors | **20** |
| Corporate Structure | **5** | Focus on Sustainability | **20** |
| &nbsp;&nbsp;&nbsp;&nbsp;Name and Incorporation | **5** | &nbsp;&nbsp;&nbsp;&nbsp;Sustainability Regulation and Environmental Contingencies | **20** |
| &nbsp;&nbsp;&nbsp;&nbsp;Inter-Corporate Relationships | **5** | Capital Structure and Dividends | **21** |
| General Development of the Business | **5** | &nbsp;&nbsp;&nbsp;&nbsp;Description of Capital Structure | **21** |
| &nbsp;&nbsp;&nbsp;&nbsp;Overview | **5** | &nbsp;&nbsp;&nbsp;&nbsp;Dividends and Distributions | **21** |
| &nbsp;&nbsp;&nbsp;&nbsp;Three-Year History | **6** | &nbsp;&nbsp;&nbsp;&nbsp;Debt Covenant Restrictions on Dividend Distributions | **21** |
| &nbsp;&nbsp;&nbsp;&nbsp;Outlook | **7** | &nbsp;&nbsp;&nbsp;&nbsp;Credit Ratings | **22** |
| Description of the Business | **8** | Directors and Officers | **24** |
| &nbsp;&nbsp;&nbsp;&nbsp;Regulated Utilities | **9** | Audit Committee | **26** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;ITC | **9** | &nbsp;&nbsp;&nbsp;&nbsp;Members | **26** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;UNS Energy | **11** | &nbsp;&nbsp;&nbsp;&nbsp;Education and Experience | **26** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Central Hudson | **13** | &nbsp;&nbsp;&nbsp;&nbsp;Pre-Approval Policies and Procedures | **27** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;FortisBC Energy | **14** | &nbsp;&nbsp;&nbsp;&nbsp;External Auditor Service Fees | **27** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;FortisAlberta | **15** | Transfer Agent and Registrar | **27** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;FortisBC Electric | **16** | Interests of Experts | **27** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Other Electric | **17** | Additional Information | **27** |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-Regulated | **19** | Exhibit A: Summary of Terms and Conditions of Authorized Securities | **29** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Energy Infrastructure | **19** | Exhibit B: Market for Securities | **31** |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Corporate and Other | **19** | Exhibit C: Audit Committee Mandate | **33** |
| Human Resources | **19** | Exhibit D: Material Contracts | **40** |

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**Dated February 9, 2023**

Financial information in this AIF has been prepared in accordance with U.S. GAAP and is presented in Canadian dollars ($) based, as applicable, on the following U.S.-to-Canadian dollar exchange rates: (i) average of 1.30 and 1.25 for the years ended December 31, 2022 and 2021, respectively; (ii) 1.36 and 1.26 as at December 31, 2022 and 2021, respectively; and (iii) 1.30 for all forecast periods.

Except as otherwise expressly noted, the information in this AIF is given as of December 31, 2022.

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| | |
|:---|:---|
| **1** | **December 31, 2022** |

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<u>Annual Information Form</u>

**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 2023-2027, including cleaner energy investments; forecast rate base and rate base growth rate to 2027; the expectation that long-term growth in rate base will support earnings and dividend growth guidance of 4-6% annually through 2027; the expectation that the dividend guidance will provide flexibility to fund more capital internally; the expectation that volatility in energy prices, global supply chain constraints and persistent inflation will not have a material impact on operations or financial results in 2023; the nature, timing, benefits and expected costs of certain capital projects, including the Wataynikaneyap Transmission Power Project, and additional opportunities beyond the capital plan, including investments related to the IRA, the MISO LRTP, climate adaptation and grid resiliency, and renewable gas solutions and LNG infrastructure in British Columbia; the 2035 GHG emissions reduction target and projected asset mix; the 2050 net-zero direct GHG emissions target; TEP's carbon emissions reduction plan, including TEP's exit from coal by 2032; the expected in-service dates for certain projects; and TEP's estimated mine reclamation costs.*

*Forward-looking information involves significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: no material impact from volatility in energy prices, global supply chain constraints and persistent inflation; reasonable regulatory decisions and the expectation of regulatory stability; the successful execution of the capital plan; no material capital project or financing cost overrun; sufficient human resources to deliver service and execute the capital plan; the realization of additional opportunities beyond the capital plan; no significant variability in interest rates; the Board exercising its discretion to declare dividends, taking into account the business performance and financial condition of the Corporation; 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.* 

*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 in the MD&A under the heading "Business Risks" and in other continuous disclosure materials filed from time to time 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. 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.*

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| **2** | **December 31, 2022** |

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<u>Annual Information Form</u>

**GLOSSARY**

Certain terms used in this 2022 Annual Information Form are defined below:

**2022 Annual Information Form or AIF:** this annual information form of the Corporation in respect of the year ended December 31, 2022

**ACGS:** Aitken Creek Gas Storage ULC

**AECO/NIT:** Alberta Energy Company/Nova Inventory Transfer

**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, an indirect wholly owned**

**subsidiary of Fortis (now known as Fortis Belize)**

**Belize Electricity:** Belize Electricity Limited

**Board:** Board of Directors of the Corporation

**CAGR:** compound annual growth rate. Calculated on a constant U.S. dollar to Canadian dollar exchange rate

**Canadian Niagara Power:** Canadian Niagara Power Inc.

**Capital Expenditures:** cash outlay for additions to property, plant and equipment and intangible assets as shown in the Financial Statements, as well as the Corporation's 39% share of capital spending for the Wataynikaneyap Transmission Power Project. See the "Non-U.S. GAAP Financial Measures" section of the MD&A

**Capital Plan:** forecast Capital Expenditures. Represents a non-U.S. GAAP financial measure calculated in the same manner as Capital Expenditures

**Caribbean Utilities:** Caribbean Utilities Company, Ltd.

**CBT:** Columbia Basin Trust

**Central Hudson:** Central Hudson Gas & Electric Corporation

**CMS:** Consumers Energy Company

**Common Equity Earnings:** Net earnings attributable to common equity shareholders

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

**Corporation:** Fortis Inc.

**CPA:** Canal Plant Agreement

**CPC:** Columbia Power Corporation

**CUPE:** Canadian Union of Public Employees

**DBRS Morningstar:** DBRS Limited

**DTE:** DTE Electric Company

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

**Eiffel Investment:** Eiffel Investment Pte Ltd.

**EPS: earnings per common share**

**FHI:** FortisBC Holdings Inc.

**Financial Statements:** the Corporation's Audited Consolidated Financial Statements in respect of the year ended December 31, 2022

**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.

**Fortis Belize:** Fortis Belize Limited, an indirect wholly owned subsidiary of Fortis (formerly known as BECOL)

**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

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| **3** | **December 31, 2022** |

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<u>Annual Information Form</u>

**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

**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

**IRA:** U.S. *Inflation Reduction Act of 2022*

**LNG:** liquefied natural gas

**LRTP:** Long-Range Transmission Plan

**Maritime Electric:** Maritime Electric Company, Limited

**MD&A:** the Corporation's Management Discussion and Analysis in respect of the year ended December 31, 2022

**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

**NYSE:** New York Stock Exchange

**PEI:** Prince Edward Island, Canada

**PNM:** Public Service Company of New Mexico

**PPA:** power purchase agreement

**PSC:** New York Public Service Commission

**PUB:** Newfoundland and Labrador Board of Commissioners of Public Utilities

**PWU:** Power Workers' Union

**RNG: renewable natural gas**

**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

**TC Energy:** TC Energy Corporation

**TCFD:** Task Force for Climate-Related Financial Disclosures

**TEP:** Tucson Electric Power Company

**TSX:** Toronto Stock Exchange

**UNS Electric** and **UNSE:** UNS Electric, Inc.

**UNS Energy:** UNS Energy Corporation

**UNS Gas:** UNS Gas, Inc.

**U.S.:** United States of America

**U.S. GAAP:** accounting principles generally accepted in the U.S.

**UUWA:** United Utility Workers' Association of Canada

**Waneta Expansion:** 335-MW Waneta Expansion hydroelectric generating facility

**Wataynikaneyap Partnership:** Wataynikaneyap Power Limited Partnership

**Measurements:**

GW&nbsp;&nbsp;&nbsp;&nbsp;Gigawatt(s)

GWh&nbsp;&nbsp;&nbsp;&nbsp;Gigawatt hour(s)

km&nbsp;&nbsp;&nbsp;&nbsp;Kilometer(s)

MW&nbsp;&nbsp;&nbsp;&nbsp;Megawatt(s)

TJ&nbsp;&nbsp;&nbsp;&nbsp;Terajoule(s)

PJ&nbsp;&nbsp;&nbsp;&nbsp;Petajoule(s)

**Conversions:**

1 litre = 0.22 imperial gallons

1 kilometer = 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.

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| **4** | **December 31, 2022** |

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<u>Annual Information Form</u>

**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 9, 2023. The principal subsidiaries together comprise approximately 90% of the Corporation's consolidated assets as at December 31, 2022 and approximately 86% of the Corporation's 2022 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, 2022.

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| **Subsidiary** | **Jurisdiction of Incorporation** | **Votes attaching to voting securities beneficially owned, controlled or directed by the Corporation** *(%)* |
| ITC <sup>(1)</sup> | Michigan, United States | **80.1** |
| UNS Energy <sup>(2)</sup> | Arizona, United States | **100** |
| Central Hudson <sup>(3)</sup> | New York, United States | **100** |
| FortisBC Energy <sup>(4)</sup> | British Columbia, Canada | **100** |
| FortisAlberta <sup>(5)</sup> | Alberta, Canada | **100** |
| Newfoundland Power <sup>(6)</sup> | Newfoundland and Labrador, Canada | **100** |

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<sup>(1)</sup> *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, holds an 80.1% interest in 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 securities of ITC Investment Holdings are owned by an affiliate of GIC, but are held as a passive investment, retaining only those rights necessary to protect its passive minority investment.*

<sup>(2)</sup> *UNS Energy, an Arizona corporation, owns all of the shares of TEP, UNS Electric and UNS Gas. FortisUS owns all of the shares of UNS Energy.* 

<sup>(3)</sup> *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.*

<sup>(4)</sup> *FHI, a British Columbia corporation, owns all of the shares of FortisBC Energy. Fortis owns all of the shares of FHI.*

<sup>(5)</sup> *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.*

<sup>(6)</sup> *Fortis owns all of the shares of Newfoundland Power.*

**GENERAL DEVELOPMENT OF THE BUSINESS** 

**Overview**

Fortis is a well-diversified leader in the North American regulated electric and gas utility industry, with 2022 revenue of $11 billion and total assets of $64 billion as at December 31, 2022.

Regulated utilities account for 99% of the Corporation's assets with the remainder primarily attributable to non-regulated energy infrastructure. The Corporation's 9,200 employees serve 3.4 million utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries. As at December 31, 2022, 67% of the Corporation's assets were located outside Canada and 59% of 2022 revenue was derived from foreign operations.

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| **5** | **December 31, 2022** |

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<u>Annual Information Form</u>

**Three-Year History**

Over the past three years, Fortis has continued to experience significant growth. Total assets have increased from $53.4 billion at the start of 2020 to $64.3 billion as at December 31, 2022. Consolidated Capital Expenditures totalled $11.8 billion from 2020 through 2022, resulting in a three-year CAGR of 7.1% in midyear rate base. The Corporation's shareholders' equity has also grown from $18.5 billion at the start of 2020 to $21.0 billion as at December 31, 2022. Common Equity Earnings for 2020 was $1,209 million compared to $1,330 million in 2022. The growth in financial results over the three-year period reflects the Corporation's organic growth strategy for its regulated utilities.

An overview of the Corporation's performance for the past three years follows:

**2020**

Fortis performed well as it navigated through the global COVID-19 pandemic through 2020. Excluding the impact of the delay in TEP's general rate application, the pandemic did not have a material impact on the Corporation's financial results in 2020.

In September 2020, the Corporation announced a five-year Capital Plan of $19.6 billion for the period 2021 to 2025. The Capital Plan focused on a diverse mix of low-risk, highly executable projects needed to maintain and upgrade existing infrastructure to expand capacity, improve reliability and support a cleaner energy future.

Also in September 2020, the Corporation announced its intent to build on its low emissions profile by establishing a corporate-wide target to reduce carbon emissions by 75% by 2035 from a 2019 base year.

Barry V. Perry retired as President and Chief Executive Officer of Fortis at the end of 2020, and David G. Hutchens was appointed to the role and as a member of the Board effective January 1, 2021.

**2021**

The Corporation's utilities continued to reliably and safely deliver an essential service through 2021. The COVID-19 pandemic did not have a significant impact on the Corporation's financial performance in 2021.

In July 2021, the Corporation's sustainability update was released and included information on the Corporation's progress on reducing carbon emissions, and support of TCFD, among other things.

In September 2021, Fortis announced a five-year Capital Plan of $20.0 billion for the period 2022 to 2026. The Capital Plan included $1 billion of additional capital investment at the Corporation's regulated utilities in comparison to the Capital Plan released in 2020. The increase largely reflected customer growth, enhancements to transmission reliability and capacity, and investments in cleaner energy. This growth was tempered by $600 million associated with the lower assumed foreign exchange rate of 1.25, down from a rate of 1.32 assumed in the Corporation's previous five-year Capital Plan.

**2022**

Fortis' utilities continued to reliably and safely deliver electricity and gas service in 2022, outperforming industry averages in Canada and the U.S. for reliability and safety.

The Corporation made progress on its commitment as a TCFD supporter in March 2022, with the release of its first TCFD and Climate Assessment Report, which included an analysis of four climate-related scenarios and associated risks and opportunities. This report provides information on the Corporation's strategy and actions to combat climate change, identifies new opportunities associated with decarbonization, and guides investment in resilient and adaptable infrastructure. In July 2022, Fortis released the 2022 Sustainability Report, highlighting progress on a number of sustainability priorities, including adding more renewable energy, reducing GHG emissions and improving diversity. The report also provided enhanced information on the Corporation's sustainability strategy, significantly expanded the scope of performance indicators, and was fully aligned with applicable Sustainability Accounting Standards Board standards.

In October 2022, Fortis announced its 2023-2027 Capital Plan of $22.3 billion. The Capital Plan reflects $2.3 billion of additional investment at the Corporation's regulated utilities in comparison to the previous 5-year Capital Plan released in 2021. The increase is driven by organic growth, largely reflecting regional transmission projects associated with the MISO LRTP at ITC, additional cleaner energy investments in Arizona to support TEP's planned exit from coal by 2032, and enhancements to distribution infrastructure reliability and capacity, as well as investments to support customer growth, across the Corporation's regulated utilities. Approximately $500 million of the increase is driven by a higher assumed U.S.-to-Canadian dollar exchange rate over the five-year period.

In total, Fortis expects to invest $5.9 billion in cleaner energy over the next five-years. These investments will focus on connecting renewables to the grid, including Tranche 1 of MISO's LRTP, renewable and storage investments in Arizona and the Caribbean, and cleaner fuel solutions in British Columbia. The plan incorporates customer affordability considerations, recognizing the impacts of inflation and elevated commodity costs on customer rates, while ensuring reliable and resilient energy delivery service as we transition to a cleaner energy future.

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| **6** | **December 31, 2022** |

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<u>Annual Information Form</u>

The investments included in the 2023-2027 Capital Plan are summarized as follows.

![chart-68a82005242344de80ba.jpg](chart-68a82005242344de80ba.jpg)

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Includes clean generation and battery storage*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Includes RNG and LNG*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Includes facilities, equipment and vehicles not included in other categories*

The Corporation reported Common Equity Earnings of $1.3 billion in 2022, or $2.78 per common share, compared to $1.2 billion, or $2.61 per common share in 2021. Our businesses performed well in 2022, delivering approximately 7% annual EPS growth. The increase was primarily driven by rate base growth across our utilities. The increase was also due to higher electricity sales and transmission revenue in Arizona, and higher earnings at Aitken Creek, reflecting market conditions. A higher U.S.-to-Canadian dollar foreign exchange rate and lower stock based compensation costs also contributed to results.

Capital Expenditures of $4.0 billion were consistent with the 2022 Capital Plan, with over $600 million of capital investment focused on delivering cleaner energy to customers. Capital Expenditures were $0.5 billion higher than 2021, primarily due to continued investment in various smaller transmission and distribution projects at the Corporation's regulated utilities, as well as the impact of the higher average foreign exchange rate.

**Outlook**

Fortis continues to enhance shareholder value through the execution of its capital plan, the balance and strength of its diversified portfolio of regulated utility businesses, and growth opportunities within and proximate to its service territories. While energy price volatility, global supply chain constraints and persistent inflation are issues of potential concern that continue to evolve, the Corporation does not currently expect there to be a material impact on its operations or financial results in 2023.

Fortis is executing on the transition to a cleaner energy future and is on track to achieve its corporate-wide targets to reduce GHG emissions by 50% by 2030 and 75% by 2035. Upon achieving this target, 99% of the Corporation's assets will support energy delivery and renewable, carbon-free generation. The Corporation's additional 2050 net-zero direct GHG emissions target reinforces Fortis' commitment to decarbonize over the long-term, while preserving customer reliability and affordability.

The Corporation's $22.3 billion five-year Capital Plan is expected to increase midyear rate base from $34.1 billion in 2022 to $46.1 billion by 2027, translating into a five-year CAGR of 6.2%.

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| **7** | **December 31, 2022** |

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<u>Annual Information Form</u>

Beyond the five-year Capital Plan, additional opportunities to expand and extend growth include: further expansion of the electric transmission grid in the U.S. to facilitate the interconnection of cleaner energy, including infrastructure investments associated with the IRA and the MISO LRTP; climate adaptation and grid resiliency investments; renewable gas solutions and LNG infrastructure in British Columbia; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.

Fortis expects its long-term growth in rate base will drive earnings that support dividend growth guidance of 4-6% annually through 2027. This dividend growth guidance will also provide flexibility to fund more capital with internally-generated funds and is premised on the assumptions and material factors listed under "Forward-Looking Information".

**DESCRIPTION OF THE BUSINESS**

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.

The Corporation's regulated utility businesses are: ITC (electric transmission - Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma, and assets under construction in Wisconsin); UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas distribution - New York State); 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 consists of Fortis Belize (three hydroelectric generation facilities - Belize) and Aitken Creek (natural gas storage facility - British Columbia).

Fortis has a unique operating model with a small corporate 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 board of directors, with most having a majority of independent board 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.

Fortis strives to provide safe, reliable and cost-effective energy service to customers while focusing on sustainability policies and practices. The Corporation has established delivering a cleaner energy future as its core purpose. In addition, management is focused on delivering long-term profitable growth for shareholders through the execution of its Capital Plan and the pursuit of investment opportunities within and proximate to its service territories.

**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 customers, particularly solar. 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. Government policy could further impact the competitiveness of natural gas in British Columbia, which accounts for 82% of the Corporation's natural gas revenue. As governments develop policies to address climate change, any resultant changes to energy policy may impact the competitiveness of natural gas relative to other energy sources.

**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. Earnings for electric distribution utilities in the U.S. are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.

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| **8** | **December 31, 2022** |

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<u>Annual Information Form</u>

**Summary of Operations**

The following table and sections describe the Corporation's operations and reportable segments.

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| | **Customers** | **Peak** <br>**Demand** <sup>(1)</sup> | **Peak** <br>**Demand** <sup>(1)</sup> | **Electric T&D Lines** *(circuit km)* | **Gas T&D Lines** *(km)* | **Generating Capacity** *(MW)* | **Revenue**<br>*($ millions)* | **GWh Sales** | **Gas Volumes** *(PJ)* | **Employees** |
| **Regulated Utilities** | | | | | | | | | | |
| ITC | **—** | **22971** | **MW** | **25800** | **—** | **—** | **1906** | **—** | **—** | **726** |
| UNS Energy | **712000** | **2949** | **MW** | **23500** | **5100** | **3328** | **2758** | **16059** | **16** | **1994** |
|  |  | **111** | **TJ** |  |  |  |  |  |  |  |
| Central Hudson | **380000** | **1109** | **MW** | **15100** | **2400** | **65** | **1325** | **5002** | **25** | **1130** |
|  |  | **149** | **TJ** |  |  |  |  |  |  |  |
| FortisBC Energy | **1076000** | **1562** | **TJ** | **—** | **51200** | **—** | **2084** | **—** | **231** | **2061** |
| FortisAlberta | **584000** | **2767** | **MW** | **90200** | **—** | **—** | **680** | **16923** | **—** | **1138** |
| FortisBC Electric | **188000** | **835** | **MW** | **7300** | **—** | **225** | **487** | **3542** | **—** | **556** |
| Other Electric |  |  |  |  |  |  |  |  |  |  |
| Newfoundland Power | **274000** | **1254** | **MW** | **11500** | **—** | **143** | **735** | **5785** | **—** | **660** |
| Maritime Electric | **88000** | **292** | **MW** | **6600** | **—** | **90** | **236** | **1391** | **—** | **219** |
| FortisOntario | **68000** | **257** | **MW** | **3500** | **—** | **5** | **224** | **1343** | **—** | **222** |
| Caribbean Utilities | **33000** | **114** | **MW** | **810** | **—** | **166** | **354** | **674** | **—** | **253** |
| FortisTCI | **17000** | **46** | **MW** | **700** | **—** | **86** | **103** | **277** | **—** | **155** |
| **Non-Regulated** |  |  |  |  |  |  |  |  |  |  |
| Energy Infrastructure | **—** | **—** |  | **—** | **—** | **51** | **151** | **225** | **—** | **76** |
| Corporate and Other | **—** | **—** |  | **—** | **—** | **—** | **—** | **—** | **—** | **52** |
| **Total** | **3420000** | **32594** | **MW** | **185010** | **58700** | **4159** | **11043** | **51221** | **272** | **9242** |
|  |  | **1822** | **TJ** |  |  |  |  |  |  |  |

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<sup>(1)</sup> *Electric (MW) or gas (TJ)*

**Regulated Utilities**

**ITC**

ITC's business consists mainly of electric transmission operations. ITC's Regulated Operating Subsidiaries own and operate 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. In addition, ITC has electric transmission system assets under construction in Wisconsin.

The primary operating responsibilities of ITC's Regulated Operating Subsidiaries' include maintaining, improving and expanding transmission systems to meet their customers' ongoing needs, managing and scheduling maintenance and construction, maintaining appropriate system voltages and monitoring flows over transmission lines and other facilities to ensure physical limits are not exceeded. ITC owns and operates approximately 25,800 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 by the Federal Energy Regulatory Commission. 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 revenues. Nearly all of ITC's revenues are from transmission customers in the U.S.

**Market and Sales**

*Revenues*

Revenue was $1,906 million in 2022 compared to $1,691 million in 2021.

ITC derives nearly all of its revenues from transmission, scheduling, control and dispatch services and other related services over ITC's Regulated Operating Subsidiaries' transmission systems to DTE, CMS, IPL and other entities, such as alternative energy suppliers, power marketers and other wholesale customers that provide electricity to end-use 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 transmission service revenues. As the billing agents for ITC's MISO Regulated Operating Subsidiaries and ITC Great Plains, MISO and SPP collect fees for the use of ITC's transmission systems, invoicing DTE, CMS, IPL and other customers on a monthly basis.

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|:---|:---|
| **9** | **December 31, 2022** |

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<u>Annual Information Form</u>

The following table compares the composition of ITC's 2022 and 2021 revenue by customer class.

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| | | |
|:---|:---|:---|
| | **Revenue** *(%)*  | **Revenue** *(%)*  |
|  | **2022** | 2021 |
| Network revenues | **69.7** | **68.9** |
| Regional cost-sharing revenues | **25.6** | **26.5** |
| Point-to-point | **1.4** | **1.3** |
| Scheduling, control and dispatch | **1.3** | **1.4** |
| Other | **2.0** | **1.9** |
| **Total** | **100.0** | 100.0 |

---

Network revenues are generated from network customers for their use of ITC's electric transmission systems and are based on the actual revenue requirements under its cost-based formula rates that contain a true-up mechanism.

Network revenues from 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.

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, which have been determined by MISO to have regional value while meeting near-term needs. Additionally, certain projects at ITC Great Plains are eligible for recovery through a region-wide charge under provisions of the SPP tariff. Regional cost-sharing revenues are treated as a reduction to the net network 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 transmission 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 to ITC's MISO Regulated Operating Subsidiaries by MISO 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 revenues from providing ancillary services to customers. The majority of other revenues are treated as a revenue credit and taken as a reduction to the gross revenue requirement when calculating the net revenue requirement under ITC's cost-based formula rates.

**Contracts**

**ITCTransmission**

DTE operates an electric distribution system that is interconnected with ITCTransmission's transmission system. 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 of ITCTransmission and DTE. It 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 direct electricity interconnection of DTE's electricity generating assets with ITCTransmission's transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.

*Coordination and Interconnection Agreement -* governs the rights, obligations and responsibilities of ITCTransmission and DTE 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.

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|:---|:---|
| **10** | **December 31, 2022** |

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<u>Annual Information Form</u>

**METC**

CMS operates an electric distribution system that interconnects with METC's transmission system. 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.

*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 an electric distribution system that interconnects with ITC Midwest's transmission system. ITC Midwest is a party to a number of operating contracts with IPL that govern the operations and maintenance of its 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 in order to establish, re-establish and maintain the direct electricity interconnection of IPL's electricity generating assets with ITC Midwest's transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.

**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 712,000 retail electricity and gas customers. UNS Energy primarily consists 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 443,000 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 U.S.

UNS Electric is a vertically integrated regulated electric utility that generates, transmits and distributes electricity to approximately 102,000 retail customers in Arizona's Mohave and Santa Cruz counties.

TEP and UNS Electric own generation resources with an aggregate capacity of 3,328 MW, including 318 MW of renewable resources. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. As at December 31, 2022, approximately 27% of the generating capacity was fueled by coal.

TEP also owns transmission-related assets, approximating 14% of UNS Energy's total assets.

UNS Gas is a regulated gas distribution utility that serves approximately 167,000 retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties.

**Market and Sales**

UNS Energy's electricity sales were 16,059 GWh in 2022 compared to 16,842 GWh in 2021. Gas volumes were 16 PJ in 2022, consistent with 2021. Revenue was $2,758 million in 2022 compared to $2,334 million in 2021.

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|:---|:---|
| **11** | **December 31, 2022** |

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<u>Annual Information Form</u>

The following table provides the composition of UNS Energy's 2022 and 2021 revenue, electricity sales, and gas volumes by customer class.

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Revenue** *(%)* | **Revenue** *(%)* | **GWh Sales** *(%)* | **GWh Sales** *(%)* | **PJ Volumes** *(%)* | **PJ Volumes** *(%)* |
|  | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 |
| Residential | **35.3** | **37.3** | **30.6** | **28.6** | **57.5** | **55.1** |
| Commercial | **17.8** | **19.2** | **16.4** | **15.8** | **23.0** | **22.3** |
| Industrial | **12.8** | **13.4** | **19.3** | **18.2** | **1.7** | **1.7** |
| Wholesale | **18.2** | **14.5** | **33.6** | **37.3** | **—** | **—** |
| Other <sup>(1)</sup> | **15.9** | **15.6** | **0.1** | **0.1** | **17.8** | **20.9** |
| **Total** | **100.0** | 100.0 | **100.0** | 100.0 | **100.0** | 100.0 |

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<sup>(1)</sup> *Electricity sales include transmission, participant billings, alternative revenue and revenue from sources other than from the sale of electricity. Gas volumes include negotiated sales program customers.*

**Power Supply**

TEP meets the electricity supply requirements of its retail and wholesale customers with its owned electrical generating capacity of 3,027 MW and its T&D system consisting of approximately 16,500 circuit km of line. In 2022, TEP met a peak demand of 2,457 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.

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| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| **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 <sup>(1)</sup> | 2 | Springerville, AZ | 1990 | **406** | **TEP** | **100.0** | **406** |
| 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 | Gila Bend, AZ | 2003 | **550** | **SRP** | **100.0** | **550** |
| Gila River Power Station <sup>(2)</sup> | 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 <sup>(3)</sup> | 1-10 | Tucson, AZ | 2019-2020 | **188** | **TEP** | **100.0** | **188** |
| DeMoss Petrie | N/A | Tucson, AZ | 2001 | **75** | **TEP** | **100.0** | **75** |
| North Loop | N/A | Tucson, AZ | 2001 | **96** | **TEP** | **100.0** | **96** |
| **Renewable** |  |  |  |  |  |  |  |
| Utility-Owned Renewables <sup>(3)</sup> |  | Various | 2002-2022 | **307** | **TEP** | **100.0** | **307** |
| **Total Capacity**<sup>(4)</sup> |  |  |  |  |  |  | **3027** |

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<sup>(1)</sup> *Springerville Generating Station Unit 2 is owned by San Carlos Resources Inc., a wholly owned subsidiary of TEP.*

<sup>(2)</sup> *TEP owns 75% of Gila River Unit 2 and UNS Electric owns 25%.*

<sup>(3)</sup> *In June 2022, the 13 MW Raptor Ridge solar facility was placed into service.*

<sup>(4)</sup> *In June 2022, San Juan Generating Station Unit 1 was retired. TEP held a 50% share in the unit, equating to 170 MW of capacity.* 

UNS Electric meets the electricity supply requirements of its retail customers with its owned electrical generating capacity of 301 MW and purchasing power on the wholesale market, and its T&D system consisting of approximately 7,000 circuit km of line. In 2022, UNS Electric met a peak demand of 492 MW.

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|:---|:---|
| **12** | **December 31, 2022** |

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<u>Annual Information Form</u>

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

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| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| **Generation Source** | **Unit No.** | **Location** | **Date In** <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** |
| Owned Utility-Scale Renewables | N/A | Various | 2011-2017 | Solar | **11** | **UNSE** | **100.0** | **11** |
| **Total Capacity** |  |  |  |  |  |  |  | **301** |

---

*Owned Utility-Scale Renewable Resources*

TEP owns 307 MW of renewable generation resources and has 3 MW of solar generation resources under development at its Areva facility which is expected to be placed into service in 2023. UNS Electric owns 11 MW of solar generation capacity.

*Renewable Power Purchase Agreements*

TEP has renewable PPAs of 256 MW from solar resources and 179 MW from wind resources. The solar PPAs contain options that allow TEP to purchase all or part of the related facilities at a future date. The Babacomari North and South solar facilities are expected to be placed into service in 2023 and are expected to add 160 MW to TEP's capacity. UNS Electric has renewable PPAs of 83 MW from solar resources and 10 MW from wind resources.

**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 70-90% of expected monthly energy volumes prior to the beginning of each month.

UNS Gas met peak demand of 111 TJ in 2022.

**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. 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 approximately 15,100 circuit km of line and met a peak demand of 1,109 MW in 2022.

Central Hudson's natural gas system consists of approximately 2,400 km of T&D pipelines and met a peak demand of 149 TJ in 2022.

**Market and Sales**

Central Hudson's electricity sales were 5,002 GWh in 2022 compared to 5,000 GWh in 2021. Natural gas sales volumes were 25 PJ in 2022 compared to 23 PJ in 2021. Revenue was $1,325 million in 2022 compared to $1,000 million in 2021.

The following table compares the composition of Central Hudson's 2022 and 2021 revenue, electricity sales and natural gas volumes by customer class.

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **Revenue** *(%)* | **Revenue** *(%)* | **GWh Sales** *(%)* | **GWh Sales** *(%)* | **PJ Volumes** *(%)* | **PJ Volumes** *(%)* |
|  | **2022** | 2021 | **2022** | 2021 | **2022** | 2021 |
| Residential | **62.2** | **62.7** | **43.8** | **44.2** | **24.3** | **24.9** |
| Commercial | **28.5** | **28.6** | **37.8** | **36.8** | **31.5** | **32.7** |
| Industrial | **3.3** | **3.9** | **17.5** | **17.4** | **37.1** | **34.5** |
| Wholesale <sup>(1)</sup> | **1.6** | **1.3** | **0.9** | **1.6** | **7.1** | **7.9** |
| Other <sup>(2)</sup> | **4.4** | **3.5** | **—** | **—** | **—** | **—** |
| **Total** | **100.0** | 100.0 | **100.0** | 100.0 | **100.0** | 100.0 |

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<sup>(1)</sup> *Includes sales for resale.*

<sup>(2)</sup> *Other includes regulatory deferrals and revenue from sources other than from the sale of gas and electricity.* 

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|:---|:---|
| **13** | **December 31, 2022** |

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<u>Annual Information Form</u>

**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.

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 1,076,000 customers in over 135 communities. FortisBC Energy provides T&D services to customers, and obtains natural gas supplies on behalf of most of its residential, commercial and industrial customers. FortisBC Energy owns and operates approximately 51,200 km of natural gas pipelines and met a peak demand of 1,562 TJ in 2022.

**Market and Sales**

FortisBC Energy's natural gas sales volumes were 231 PJ in 2022 compared to 228 PJ in 2021. Revenue was $2,084 million in 2022 compared to $1,715 million in 2021.

The following table compares the composition of FortisBC Energy's 2022 and 2021 revenue and natural gas volumes by customer class.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Revenue** *(%)* | **Revenue** *(%)* | **PJ Volumes** *(%)* | **PJ Volumes** *(%)* |
|  | **2022** | 2021 | **2022** | 2021 |
| Residential | **56.9** | **57.2** | **37.7** | **36.4** |
| Commercial | **32.1** | **30.4** | **26.4** | **24.6** |
| Industrial | **7.1** | **6.7** | **8.2** | **7.9** |
| Other <sup>(1)</sup> | **3.9** | **5.7** | **27.7** | **31.1** |
| **Total** | **100.0** | 100.0 | **100.0** | 100.0 |

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<sup>(1)</sup> *Includes revenue and gas volumes from transportation customers. Due to the nature of transportation contracts, the percentage of revenue by customer category may not correlate with associated volumes.* 

**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 181 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 TC Energy'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 TC Energy pipeline, to transport gas supply from various market hubs to FortisBC Energy's system. These third-party pipelines are regulated by the Canada Energy Regulator. 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.

**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 demand; (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 parties in northeast British Columbia, Alberta and the Pacific Northwest of the U.S. One such party is ACGS, an indirect subsidiary of Fortis. On a combined basis, FortisBC Energy's Tilbury and Mount Hayes facilities, the contracted storage facilities and other peaking arrangements can deliver up to 0.85 PJs per day of supply to FortisBC Energy on the coldest days of the heating season. The heating season typically occurs during the period 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. Subject to the BCUC's approval, FortisBC Energy earned an incentive payment of approximately $4.6 million for the gas contract year ending October 31, 2022.

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|:---|:---|
| **14** | **December 31, 2022** |

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<u>Annual Information Form</u>

The current GSMIP program was approved by the BCUC following a comprehensive review in 2022. The BCUC has approved extensions of the program through October 31, 2025.

**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) 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 April 2022, FortisBC Energy filed its Winter 2022-2023 Sumas Risk Mitigation Application with the BCUC to implement the Sumas hedging strategy for the 2022-2023 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 2022, and the hedging strategies were implemented between June and August 2022.

In June 2022, FortisBC Energy filed its AECO/NIT Price Risk Mitigation Application to implement one-year hedges to mitigate the impact of rising prices at the AECO/NIT market hub, and provide increased pricing diversity to the commodity supply portfolio. The BCUC approved the application in July 2022 and the hedging strategies were implemented between July and October 2022.

**Unbundling**

A Customer Choice program at FortisBC Energy allows eligible commercial and residential customers a choice 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, 2022, approximately 8% of eligible commercial customers and 4% of eligible residential customers purchased their commodity supply from alternate providers.

**FortisAlberta**

FortisAlberta is a regulated electricity distribution utility operating in Alberta. Its business is the ownership and operation of electric 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 around and between the cities of Edmonton and Calgary, totalling approximately 90,200 circuit km of distribution lines. FortisAlberta's distribution network serves approximately 584,000 customers and met a peak demand of 2,767 MW in 2022.

**Market and Sales**

FortisAlberta's energy deliveries were 16,923 GWh in 2022 compared to 16,643 GWh in 2021. Revenue was $680 million in 2022 compared to $644 million in 2021.

The following table compares the composition of FortisAlberta's 2022 and 2021 revenue and energy deliveries by customer class.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Revenue** *(%)* | **Revenue** *(%)* | **GWh Deliveries** *(%)* <sup>(1)</sup> | **GWh Deliveries** *(%)* <sup>(1)</sup> |
|  | **2022** | 2021 | **2022** | 2021 |
| Residential | **44.3** | **43.5** | **28.5** | **29.5** |
| Commercial | **25.1** | **23.7** | **13.6** | **13.3** |
| Industrial | **18.3** | **20.5** | **57.9** | **57.2** |
| Other <sup>(2)</sup> | **12.3** | **12.3** | **—** | **—** |
| **Total** | **100.0** | 100.0 | **100.0** | 100.0 |

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<sup>(1)</sup> *GWh percentages exclude FortisAlberta's GWh deliveries to "transmission-connected" customers. These deliveries were 6,695 GWh in 2022 and 6,448 GWh in 2021, based on an interim settlement that is expected to be finalized in May 2023, and consisted primarily of energy deliveries to large-scale industrial customers directly connected to the transmission grid.*

<sup>(2)</sup> *Includes rate riders, deferrals and adjustments.*

**Franchise Agreements**

FortisAlberta customers located within a city, town, village or summer village boundary are served under franchise agreements between FortisAlberta and the respective customers' municipality of residence. FortisAlberta maintains standard franchise agreements with many municipalities throughout Alberta. Any franchise agreement that is not renewed at the expiry of the term continues in effect until either FortisAlberta or the municipality terminates it with the approval of the AUC. The *Municipal Government Ac*t (Alberta) provides municipalities an option to purchase FortisAlberta assets located within their municipal boundaries upon termination of a franchise agreement. FortisAlberta must be compensated if a franchise agreement is terminated, and the municipality subsequently exercises its option to purchase FortisAlberta distribution assets. In such a case, compensation would likely be determined based on a methodology approved by the AUC.

FortisAlberta holds franchise agreements with 159 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. Due to the amalgamation of certain municipalities within its service area, the number of agreements anticipated to be renewed has reduced. Franchise agreements that will expire by the end of 2023 have either been renewed or are in the process of renewal. Notices to extend franchise agreements will be provided to affected municipalities before those agreements expire.

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| | |
|:---|:---|
| **15** | **December 31, 2022** |

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<u>Annual Information Form</u>

**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 located in the southern interior of British Columbia. FortisBC Electric serves approximately 188,000 customers and met a peak demand of 835 MW in 2022. 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 ultimately owned by CBT and CPC.

**Market and Sales**

Electricity sales were 3,542 GWh in 2022 compared to 3,460 GWh in 2021. Revenue was $487 million in 2022 compared to $468 million in 2021.

The following table compares the composition of FortisBC Electric's 2022 and 2021 revenue and electricity sales by customer class.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Revenue** *(%)* | **Revenue** *(%)* | **GWh Sales** *(%)* | **GWh Sales** *(%)* |
|  | **2022** | 2021 | **2022** | 2021 |
| Residential | **50.0** | **51.0** | **39.5** | **40.3** |
| Commercial | **26.4** | **27.0** | **28.6** | **29.6** |
| Industrial | **11.0** | **9.0** | **15.3** | **13.1** |
| Wholesale | **12.6** | **13.0** | **16.6** | **17.0** |
| **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 41% of its energy needs and 25% 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.

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| | | |
|:---|:---|:---|
| **Plant** | **Capacity**<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** | **1902** |  |

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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 U.S., 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.

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| | |
|:---|:---|
| **16** | **December 31, 2022** |

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<u>Annual Information Form</u>

FortisBC Electric's remaining electricity supply is acquired primarily through long-term PPAs with a number of counterparties, including the Brilliant PPA, the BC Hydro PPA and the Waneta Expansion Capacity Agreement. Additionally, FortisBC Electric purchases capacity and energy from the market to meet its peak energy requirements and optimize its overall power supply portfolio. These market purchases provided approximately 22% of FortisBC Electric's energy supply requirements in 2022. 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 primarily in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario.

The 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%). FortisOntario, as project manager, is responsible for construction, management and operation of the transmission line. In August 2022, Phase 1 of the project was completed, energizing the 230 kV line from Dinorwic to Pickle Lake, Ontario. As at December 31, 2022, the project was 73% complete, with 700 kilometers of transmission line energized and three First Nation communities connected to the Ontario electric grid. Construction is expected to be completed in 2024.

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.

Both Wataynikaneyap Partnership and Belize Electricity are excluded from the following discussion as Fortis holds minority interests in these entities.

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

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | **Customers** | **Peak Demand** *(MW)* | **T&D Lines** *(circuit km)* | **Generating Capacity** *(MW)* | **Resource Type(s)** |
| Newfoundland Power | **274000** | **1254** | **11500** | **143** | Hydroelectric, Gas, Diesel |
| Maritime Electric | **88000** | **292** | **6600** | **90** | Diesel |
| FortisOntario <sup>(1)</sup> | **68000** | **257** | **3500** | **5** | Natural Gas Cogeneration |
| Caribbean Utilities <sup>(2)</sup> | **33000** | **114** | **810** | **166** | Diesel |
| FortisTCI | **17000** | **46** | **700** | **86** | Diesel, Solar |
| **Total** | **480000** | **1963** | **23110** | **490** |  |

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<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;FortisOntario also owns a 10% interest in certain regional electric distribution companies serving approximately 40,000 customers.*

<sup>(2)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Includes 24 km of high-voltage submarine cable.*

**Market and Sales**

Electricity sales attributable to Other Electric were 9,470 GWh in 2022 compared to 9,266 GWh in 2021. Revenue was $1,652 million in 2022 compared to $1,498 million in 2021.

The following table compares the composition of revenue and electricity sales by customer class for Other Electric in 2022 and 2021.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Revenue** *(%)* | **Revenue** *(%)* | **GWh Sales** *(%)* | **GWh Sales** *(%)* |
|  | **2022** | 2021 | **2022** | 2021 |
| Residential | **56.5** | **57.5** | **56.4** | **56.5** |
| Commercial | **38.3** | **38.4** | **40.3** | **40.2** |
| Industrial | **1.8** | **2.0** | **2.7** | **2.7** |
| Other <sup>(1)</sup> | **3.4** | **2.1** | **0.6** | **0.6** |
| **Total** | **100.0** | 100.0 | **100.0** | 100.0 |

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<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Includes revenue from sources other than from the sale of electricity.*

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| | |
|:---|:---|
| **17** | **December 31, 2022** |

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<u>Annual Information Form</u>

**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. 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.

Energy from the Muskrat Falls project is expected to supply a significant portion of NL Hydro's electricity requirements, and in turn, Newfoundland Power's electricity requirements. All units of NL Hydro's Muskrat Falls generating facility have been released for service. Commissioning of the associated Labrador Island Link transmission line, which is required for full commissioning of the Muskrat Falls project, continues to experience delays. It is uncertain when the Labrador Island Link will commence commercial operation at full capacity. The reliability of supply from the Muskrat Falls project is currently under review by the PUB, and evidence filed by NL Hydro suggests backup generation is required in the event of an extended outage to the Labrador Island Link. Uncertainty remains regarding supply adequacy and reliability of the province of Newfoundland and Labrador's electrical system after commissioning.

Future increases in supply costs from NL Hydro, including costs associated with the Muskrat Falls project, are expected to increase electricity rates that Newfoundland Power charges to its customers. In February 2022, the Government of Newfoundland and Labrador and the Government of Canada finalized term sheets related to the financial restructuring for the Muskrat Falls project, including a $1 billion federal loan guarantee and a $1 billion investment by the Government of Canada in the province's portion of the Labrador Island Link. The timing and impact of the project's financial restructuring on customer rates remains unknown. Any additional costs associated with extending the life of existing generating capacity or additional backup generating capacity on the island of Newfoundland could further increase supply costs from NL Hydro and, in turn, further increase electricity rates for Newfoundland Power's customers.

**Maritime Electric**

Maritime Electric is interconnected to the Province of New Brunswick via four provincially owned submarine cables with a total capacity of 560 MW. The company purchases its energy requirements through energy purchase agreements with NB Power, a New Brunswick Crown corporation, and from renewable energy facilities owned by the PEI Energy Corporation. Company-owned on-Island generation facilities totalling 90 MW are used primarily for peaking, submarine-cable loading issues and emergency purposes.

Maritime Electric has the following contracts with NB Power: (i) an energy supply agreement covering the period March 1, 2019 to December 31, 2026; (ii) a transmission capacity contract allowing Maritime Electric to reserve 30 MW of capacity to PEI expiring November 2032; and (iii) an entitlement agreement for approximately 4.55% of the output from NB Power's Point Lepreau Nuclear Generating Station for the life of the unit. Maritime Electric also has several renewable energy contracts with the PEI Energy Corporation for the purchase of energy for remaining periods ranging from one to 15 years.

As part of its entitlement agreement relating to the output of the Point Lepreau Nuclear Generating Station, Maritime Electric is required to pay its share of the unit's capital and operating costs.

**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 the IESO, purchases approximately 75% of energy requirements for the Gananoque region from Hydro One Networks Inc., and the remaining 25% from five hydroelectric generating plants owned by EO Generation LP. Algoma Power purchases its energy requirements primarily from the IESO. Under the Ontario Energy Board's Standard Supply Code, Canadian Niagara Power and Algoma Power must 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 a contract that expires in December 2030, and which 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. In December 2021, Caribbean Utilities exercised its option to renew for the second 18-month renewal term.

**FortisTCI**

FortisTCI relies upon in-house diesel-powered generation to produce electricity for its customers. FortisTCI has installed 2.76 MW of rooftop solar in partnership with customers under its Utility Owned Renewable Energy Program. FortisTCI continues to engage with the Government of the Turks and Caicos Islands on regulatory reform to enable further development of renewable energy resources.

FortisTCI has contracted with a major supplier for all its diesel fuel requirements for electricity generation. The current contract expires in August 2025.

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| | |
|:---|:---|
| **18** | **December 31, 2022** |

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<u>Annual Information Form</u>

**Non-Regulated** 

**Energy Infrastructure**

The Corporation's Energy Infrastructure segment consists of the Aitken Creek natural gas storage facility in British Columbia and three hydroelectric generation facilities in Belize with a combined capacity of 51 MW held through the Corporation's subsidiary, Fortis Belize.

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. ACGS contracts with third parties and with FortisBC Energy for leased storage transactions and also holds its own proprietary capacity.

Generation assets in Belize consist of three hydroelectric generating facilities, discussed above. 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 225 GWh in 2022 compared to 147 GWh in 2021. Revenue was $151 million in 2022 compared to $98 million in 2021.

**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 and non-regulated holding company expenses.

**HUMAN RESOURCES** 

Fortis and its subsidiaries have 9,242 employees, with 53% in Canada, 42% in the U.S. and 5% in other countries. The following table provides the breakdown of employees by reportable segment.

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| | | | | |
|:---|:---|:---|:---|:---|
| | **Employees** | **Participation in a Collective Agreement** | **Union(s)** | **Collective Agreement(s) Expiry Date(s)** |
| **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** |
| ITC | **726** |  | &nbsp;&nbsp;&nbsp;&nbsp;— |  |
| UNS Energy | **1994** | **48%** | &nbsp;&nbsp;&nbsp;&nbsp;IBEW | June 2023 – February 2025 |
| Central Hudson | **1130** | **55%** | &nbsp;&nbsp;&nbsp;&nbsp;IBEW | March 2024 – April 2026 |
| FortisBC Energy <sup>(1)</sup> | **2061** | **60%** | &nbsp;&nbsp;&nbsp;&nbsp;IBEW, MoveUP | March 2022 – March 2024 <sup>(2)</sup>  |
| FortisAlberta | **1138** | **76%** | &nbsp;&nbsp;&nbsp;&nbsp;UUWA | December 2022 <sup>(3)</sup> |
| FortisBC Electric | **556** | **68%** | &nbsp;&nbsp;&nbsp;&nbsp;IBEW, MoveUP | March 2022 – June 2023 <sup>(4)</sup> |
| Other Electric | **1509** | **40%** | &nbsp;&nbsp;&nbsp;&nbsp;CUPE, IBEW, PWU | June 2022 – December 2023 <sup>(5)</sup> |
| **Non-Regulated** |  |  |  |  |
| Energy Infrastructure  | **76** |  | &nbsp;&nbsp;&nbsp;&nbsp;— |  |
| Corporate and Other <sup>(6)</sup> | **52** |  | &nbsp;&nbsp;&nbsp;&nbsp;— |  |
| **Total** | **9242** | **50%** |  |  |

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<sup>(1)</sup> *Includes employees at FHI.*

<sup>(2)</sup> *The collective agreement between FortisBC Energy and MoveUP, representing customer service employees, expired in March 2022 and negotiations are ongoing.*

<sup>(3)</sup> *A tentative agreement was reached between FortisAlberta and the UUWA in December 2022 for a 3-year collective agreement expiring in December 2025. Employees represented by the UUWA ratified this agreement in February 2023.* 

<sup>(4)</sup> *The collective agreement between FortisBC Electric and MoveUP expired in March 2022 and negotiations are ongoing. The collective agreement between FortisBC Electric and the IBEW expired in January 2023 and negotiations are ongoing.*

<sup>(5)</sup> *The collective agreement between Newfoundland Power and the IBEW expired in June 2022 and negotiations are ongoing. The collective agreement between Maritime Electric and the IBEW expired in December 2022 and negotiations are ongoing.*

<sup>(6)</sup> *Employees at Fortis Inc.*

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 right to a fair wage, and strive to maintain positive and constructive relationships with labour associations and unions.

The Corporation's subsidiaries are required to develop and retain a skilled workforce 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. For information with respect to the Corporation's talent management strategy and practices, refer to the "Focus on Sustainability" section of the MD&A, which is incorporated by reference in this AIF and available on SEDAR and EDGAR.

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| | |
|:---|:---|
| **19** | **December 31, 2022** |

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<u>Annual Information Form</u>

**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, 2022, 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 26 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. During the year ended December 31, 2022, there have not been any: (i) penalties or sanctions imposed against the Corporation by a court relating to securities legislation or by a securities regulatory authority; (ii) 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 (iii) settlement agreements entered into by the Corporation before a court relating to securities legislation or with a securities regulatory authority.

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 8 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.

**FOCUS ON SUSTAINABILITY**

For further information with respect to the Corporation's sustainability program and practices, refer to the "Focus on Sustainability" section of the MD&A, which is incorporated by reference in this AIF and available on SEDAR and EDGAR.

**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. Fortis 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 environmental contingencies have been made as of December 31, 2022:

*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 customers and, accordingly, these costs are deferred as a regulatory asset for future recovery.

TEP is liable for a portion of final mine reclamation costs upon closure of the mines servicing the San Juan and Four Corners power stations. TEP's estimated share of final mine reclamation costs at Four Corners is $11 million upon expiration of the related coal supply agreement, which expires in 2031. At December 31, 2022, TEP's estimated share of final mine reclamation costs at the San Juan Generating Station, which was retired in June 2022, was $43 million.

*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, 2022, an obligation of $100 million was recognized. Central Hudson has notified its insurers and intends to seek reimbursement where insurance coverage exists. Further, as authorized by the PSC, 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.

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|:---|:---|
| **20** | **December 31, 2022** |

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<u>Annual Information Form</u>

**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 9, 2023, the Corporation had issued and outstanding 482.2 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.7 million First Preference Shares, Series H; 2.3 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.

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 2022, Fortis declared an increase in the 2022 fourth quarter dividend per common share by approximately 6.0% to $0.565 per share, or $2.26 on an annualized basis. In November 2022 and February 2023, the Board declared first and second quarter 2023 dividends, respectively, on the common shares of $0.565 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 and second quarter 2023 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 and June 1, 2023 to holders of record as of February 15 and May 17, 2023, respectively.

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

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| | | | |
|:---|:---|:---|:---|
| | **2022** | **2021** | **2020** |
| Common Shares | **2.2000** | 2.0800 | 1.9650 |
| First Preference Shares, Series F <sup>(1)</sup> | **1.2250** | 1.2250 | 1.2250 |
| First Preference Shares, Series G <sup>(2)</sup> | **1.0983** | 1.0983 | 1.0983 |
| First Preference Shares, Series H <sup>(3)</sup> | **0.4588** | 0.4588 | 0.5003 |
| First Preference Shares, Series I <sup>(4)</sup> | **0.9157** | 0.3926 | 0.4987 |
| First Preference Shares, Series J <sup>(1)</sup> | **1.1875** | 1.1875 | 1.1875 |
| First Preference Shares, Series K <sup>(5)</sup> | **0.9823** | 0.9823 | 0.9823 |
| First Preference Shares, Series M <sup>(6)</sup> | **0.9783** | 0.9783 | 0.9783 |

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<sup>(1)</sup> *The dividend rate on the First Preference Shares, Series F and First Preference Shares, Series J are fixed and do not reset.*

<sup>(2)</sup> *The annual dividend per share was reset to $1.0983 for the five-year period from September 1, 2018 up to but excluding September 1, 2023.*

<sup>(3)</sup> *The annual dividend per share was reset from $0.6250 to $0.4588 for the five-year period from June 1, 2020 up to but excluding June 1, 2025.*

<sup>(4)</sup> *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%.* 

<sup>(5)</sup> *The annual dividend per share was reset to $0.9823 for the five-year period from March 1, 2019 to but excluding March 1, 2024.* 

<sup>(6)</sup> *The annual dividend per share was reset to $0.9783 for the five-year period from December 1, 2019 to but excluding December 1, 2024.*

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.

**Debt Covenant Restrictions on Dividend Distributions**

The Trust Indenture pertaining to the Corporation's $200 million Unsecured Debentures contains a covenant which provides that Fortis shall not declare or pay any dividends (other than stock dividends or cumulative preferred dividends on preferred shares not issued as stock dividends) or make any other distribution on its shares or redeem any of its shares or prepay subordinated debt if, immediately thereafter, its consolidated funded obligations would be in excess of 75% of its total consolidated capitalization.

The Corporation has a $1.3 billion unsecured committed revolving corporate credit facility, maturing July 2027, and a US$500 million non-revolving term credit facility, maturing May 2023, that are available for general corporate purposes. The credit facilities contain a covenant that provides that Fortis shall not: (i) declare, pay or make any ordinary course dividend except that in giving effect to the payment of such ordinary course dividend, it would not result in the Corporation's consolidated debt to consolidated capitalization ratio exceeding 70%; or (ii) declare, pay or make any restricted payments (including special or extraordinary dividends) if, immediately thereafter, its consolidated debt to consolidated capitalization ratio would exceed 65%.

As at December 31, 2022 and 2021, the Corporation was in compliance with its debt covenant restrictions pertaining to dividend distributions, as described above.

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|:---|:---|
| **21** | **December 31, 2022** |

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<u>Annual Information Form</u>

**Credit Ratings** 

Credit ratings provide an opinion about the creditworthiness of an issuer and the issuer's capacity and willingness to meet its financial commitments on the obligation in accordance with its terms. Credit 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. The ratings assigned to securities issued by Fortis and its utilities are reviewed by the agencies on an ongoing basis. 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 9, 2023.

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| | | | |
|:---|:---|:---|:---|
| **Company/Security** | **DBRS Morningstar** | **S&P** | **Moody's** |
| *Fortis* |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured Debt | **A (low), Stable** | **BBB+, Stable** | **Baa3, Stable** |
| &nbsp;&nbsp;&nbsp;&nbsp;Preference Shares | **Pfd-2 (low), Stable** | **P-2, Stable** | **N/A** |
| *Caribbean Utilities* *-* Unsecured Debt | **A (low), Stable** | **BBB+, Stable** | **—** |
| *Central Hudson* *-* Unsecured Debt <sup>(1)</sup> | **—** | **BBB+, Stable** | **Baa1, Stable** |
| *FortisAlberta* - Unsecured Debt | **A (low), Stable** | **A-, Stable** | **Baa1, Stable** |
| *FortisBC Electric* |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Secured Debt | **A (low), Stable** | **—** | **—** |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured Debt | **A (low), Stable** | **—** | **Baa1, Stable** |
| &nbsp;&nbsp;&nbsp;&nbsp;Commercial Paper | **R-1 (low), Stable** | **—** | **—** |
| *FortisBC Energy* |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured Debt | **A, Stable** | **—** | **A3, Stable** |
| &nbsp;&nbsp;&nbsp;&nbsp;Commercial Paper | **R-1 (low), Stable** | **—** | **—** |
| *ITC Holdings* |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured Debt | **—** | **BBB+, Stable** | **Baa2, Stable** |
| &nbsp;&nbsp;&nbsp;&nbsp;Commercial Paper | **—** | **A-2, Stable** | **Prime-2, Stable** |
| *ITC Great Plains -* First Mortgage Bonds | **—** | **A, Stable** | **A1, Stable** |
| *ITC Midwest* - First Mortgage Bonds | **—** | **A, Stable** | **A1, Stable** |
| *ITCTransmission -* First Mortgage Bonds | **—** | **A, Stable** | **A1, Stable** |
| *Maritime Electric* - Secured Debt | **—** | **A, Stable** | **—** |
| *METC* - Secured Debt | **—** | **A, Stable** | **A1, Stable** |
| *Newfoundland Power* - First Mortgage Bonds | **A, Stable** | **—** | **A2, Stable** |
| *TEP* |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured Debt | **—** | **A-, Stable** | **A3, Stable** |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured Bank Credit Facility | **—** | **—** | **A3, Stable** |
| *UNS Electric* |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured Debt | **—** | **—** | **A3, Stable** |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured Bank Credit Facility | **—** | **—** | **A3, Stable** |
| *UNS Gas* - Unsecured Debt | **—** | **—** | **A3, Stable** |

---

<sup>(1)</sup> *Central Hudson's senior unsecured debt is also rated by Fitch at 'A-, negative'. Fitch rates long-term debt 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. According to Fitch, a long-term obligation rated A denotes the expectation of low credit risk, with strong capacity for payment of financial commitments. The capacity may, nevertheless, be more vulnerable to adverse business or economic conditions than is the case for higher ratings.*

In December 2022, S&P lowered Central Hudson's unsecured debt credit rating to BBB+ from A- and revised the rating outlook to stable from negative. S&P noted that the change was due to projected weakening in the company's financial measures due to the effects of rising inflation and higher interest rates combined with an elevated capital spending program and increasing operations and maintenance **costs**.

In January 2023, Fitch affirmed Central Hudson's senior unsecured debt at A- but revised the outlook from stable to negative. Fitch noted that the change reflects the concern that, absent a significantly improved outcome in the company's next rate case, Central Hudson's future credit metrics will no longer be consistent with the current rating.

---

| | |
|:---|:---|
| **22** | **December 31, 2022** |

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------

<u>Annual Information Form</u>

The table below highlights rating category ranges from highest to lowest quality of such securities for the issuer's credit rating agencies.

---

| | | | |
|:---|:---|:---|:---|
| **Security** | **DBRS Morningstar** | **S&P** | **Moody's** |
| Long-term debt | AAA to D <sup>(1)</sup> | AAA to D <sup>(2)</sup> | Aaa to C <sup>(5)</sup> |
| Short-term debt | R-1 to D <sup>(1)</sup> | A-1 to D <sup>(3)</sup> | Prime-1 to Not Prime <sup>(6)</sup> |
| Preference Shares | &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp; Pfd-1 to D | P-1 to D <sup>(4)</sup> | N/A |

---

<sup>(1)</sup> *All rating categories contain subcategories of '(high)' or '(low)' other than AAA and D for long-term debt and below R-2 for short-term debt. The absence of either a '(high)' or '(low)' designation indicates the rating is in the middle of a category.*

<sup>(2)</sup> *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 or ratings at AAA.*

<sup>(3)</sup> *Within only the A-1 category may certain obligations be designated with a '+', indicating that the issuer's capacity to meet its financial commitments under these obligations is extremely strong.*

<sup>(4)</sup> *S&P uses 'high' or 'low' designations to indicate the relative standing of securities within a particular rating category. Such modifiers are not added to ratings below P-5.*

<sup>(5)</sup> *Moody's applies numerical modifiers 1, 2 and 3 to 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 and the modifier 3 indicates a ranking in the lower end of that generic rating category.*

<sup>(6)</sup> *Short-term obligations with a Not Prime rating do not fall within any of the Prime rating categories.*

**DBRS**

*Long-term debt*

According to DBRS Morningstar, a rating of A is assigned to a long-term debt instrument that has good credit quality, with the issuer having substantial capacity to pay its financial obligations, but credit quality is less than AA-rated instruments and may be vulnerable to future events, but qualifying negative factors are considered manageable.

*Short-term debt*

According to DBRS Morningstar, a rating of R-1(low) means that the short-term debt obligation has good credit quality, with the issuer having substantial capacity to repay short-term debt obligations and may be vulnerable to future events, but qualifying negative factors are considered manageable. The overall strength of R-1 (low) rated instruments is not as favourable as those in higher rated categories.

*Preference shares*

According to DBRS Morningstar, a rating of Pfd-2 (low) means that the preference shares have good credit quality and although the protection of dividends and principal is substantial, earnings, the balance sheet and coverage ratios of Pfd-2 rated companies are not as strong as Pfd-1 rated companies.

**S&P**

*Long-term debt*

According to S&P, a rating of A is assigned to long-term debt instruments that are somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than those in higher-rated categories. However, the issuer's capacity to meet its financial obligations is still strong. 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 commitments on the obligation.

*Short-term debt*

According to S&P, a short-term obligation rated A-2 is somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher rating categories. However, the issuer's capacity to meet its financial commitments on the short-term obligation is satisfactory.

*Preference shares*

According to S&P, a rating of P-2 means that the preference shares have 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 commitments on the obligation.

**Moody's**

*Long-term debt*

According to Moody's, a rating of Baa is assigned to long-term 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.

*Short-term debt*

According to Moody's, a rating of Prime-2 means that an issuer has a strong ability to repay short-term debt obligations.

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.

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| | |
|:---|:---|
| **23** | **December 31, 2022** |

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------

<u>Annual Information Form</u>

**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.

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| | | | | |
|:---|:---|:---|:---|:---|
| **Name, Residence, Principal Occupation Within Five Preceding Years** | **Director Since** | **Committees** <sup>(1)</sup> | **Committees** <sup>(1)</sup> | **Committees** <sup>(1)</sup> |
| **Name, Residence, Principal Occupation Within Five Preceding Years** | **Director Since** | **AC** | &nbsp;&nbsp;**GS** | &nbsp;&nbsp;**HR** |
| **DOUGLAS J. HAUGHEY *(Chair*** <sup>(2)</sup>***),*** Alberta, Canada<br>Corporate Director. | 2009 | ● | ● | ● |
| **TRACEY C. BALL,** British Columbia, Canada<br>Corporate Director. | 2014 | ● | ● |  |
| **PIERRE J. BLOUIN,** Quebec, Canada<br>Corporate Director. | 2015 |  | **C** | ● |
| **PAUL J. BONAVIA,** Texas, United States of America<br>Corporate Director. | 2018 |  | ● | ● |
| **LAWRENCE T. BORGARD,** Florida, United States of America<br>Corporate Director.  | 2017 | ● |  | ● |
| **MAURA J. CLARK,** New York, United States of America<br>Corporate Director. | 2015 | **C** |  | ● |
| **LISA CRUTCHFIELD,** Pennsylvania, United States of America<br>Corporate Director. Managing Principal of Hudson Strategic Advisors, LLC since 2012.  | 2022 |  | ● |  |
| **MARGARITA K. DILLEY,** District of Columbia, United States of America<br>Corporate Director. | 2016 | ● |  | ● |
| **JULIE A. DOBSON,** Maryland, United States of America<br>Corporate Director. | 2018 |  | ● | **C** |
| **LISA L. DUROCHER,** Ontario, Canada<br>Executive Vice President, Financial and Emerging Services of Rogers Communications Inc. since January 2021, and prior to that, Chief Digital Officer from June 2017 to January 2021, and Senior Vice President, Digital from August 2016 to June 2017.  | 2021 | ● | ● |  |
| **DAVID G. HUTCHENS,** Arizona, United States of America<br>President and Chief Executive Officer of the Corporation. | 2021 | <sup>(3)</sup> | <sup>(3)</sup> | <sup>(3)</sup> |
| **GIANNA M. MANES,** South Carolina, United States of America<br>Corporate Director. President and Chief Executive Officer of ENMAX Corporation from 2012 to July 2020. | 2021 | ● |  | ● |
| **JO MARK ZUREL,** <sup>(2)</sup> Newfoundland and Labrador, Canada<br>Corporate Director. President of Stonebridge Capital Inc., a private investment company from 2006 to March 2019. | 2016 | ● |  | ● |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Audit Committee, Governance and Sustainability Committee and Human Resources Committee. "C" represents Chair.*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Effective January 1, 2023, Jo Mark Zurel succeeded Douglas Haughey as Chair of the Board.*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Mr. Hutchens does not serve on any of the committees because he is the President and Chief Executive Officer of the Corporation, but is invited to and attends all committee meetings.*

**Proceedings**

From October 2018 until April 2021, Maura J. Clark served on the board of directors of Garrett Motion Inc. (Garrett), a NYSE listed company. On September 20, 2020, Garrett and certain affiliated companies filed petitions in the United States Bankruptcy Court for the Southern District of New York seeking relief under Chapter 11 of the United States Bankruptcy Code. Garrett emerged from the Chapter 11 proceedings in April 2021.

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| | |
|:---|:---|
| **24** | **December 31, 2022** |

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------

<u>Annual Information Form</u>

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** |
| **DAVID G. HUTCHENS,** Arizona, United States of America<br>President and Chief Executive Officer since January 2021. Chief Operating Officer from January 2020 to December 2020 and Executive Vice President, Western Utility Operations from January 2018 to January 2020. Chief Executive Officer of UNS Energy from January 2020 to December 2020 and President and Chief Executive Officer of UNS Energy from May 2014 to January 2020. | President and Chief Executive Officer |
| **JOCELYN H. PERRY,** Newfoundland and Labrador, Canada<br>Executive Vice President, Chief Financial Officer since June 2018. President and Chief Executive Officer of Newfoundland Power from 2017 to May 2018.  | Executive Vice President, Chief Financial Officer |
| **JAMES R. REID,** Ontario, Canada<br>Executive Vice President, Sustainability and Chief Legal Officer since July 2022. Executive Vice President, Chief Legal Officer and Corporate Secretary from March 2018 to June 2022. Partner with Davies Ward Phillips & Vineberg LLP from 2003 to March 2018. | Executive Vice President, Sustainability and Chief Legal Officer |
| **GARY J. SMITH,** Newfoundland and Labrador, Canada<br>Executive Vice President, Operations and Innovation since January 2022, and Executive Vice President, Eastern Canadian and Caribbean Operations from June 2017 to December 2021.  | Executive Vice President, Operations and Innovation |
| **STUART I. LOCHRAY,** Ontario, Canada<br>Senior Vice President, Capital Markets and Business Development since September 2021. Various senior executive roles at Scotiabank in Houston, including Managing Director & Head, US Corporate Investment Banking from September 2019 to September 2021, Managing Director & Head, Power & Utilities, Corporate and Investment Banking from March 2019 to September 2019, and Managing Director & Co-Head, US Corporate Banking from April 2017 to March 2019. | Senior Vice-President, Capital Markets and Business Development |
| **STEPHANIE A. AMAIMO,** Michigan, United States of America<br>Vice President, Investor Relations since October 2017. | Vice President, Investor Relations |
| **JULIE M. AVERY,** Newfoundland and Labrador, Canada<br>Vice President, Controller since July 2022. Senior Director, Finance from September 2020 to June 2022. Director, Financial Planning & Strategic Initiatives from December 2019 to September 2020. Director, Executive Compensation from October 2017 to December 2019.  | Vice President, Controller |
| **KAREN J. GOSSE,** Newfoundland and Labrador, Canada<br>Vice President, Finance since July 2022. Vice President, Controller from September 2021 to June 2022. Vice President, Treasury and Planning from April 2018 to September 2021. Vice President, Planning and Forecasting from November 2015 to April 2018.  | Vice President, Controller until June 30, 2022 and thereafter Vice President, Finance |
| **RONALD J. HINSLEY,** Texas, United States of America<br>Vice President, Chief Information Officer since May 2019. Vice President, Information Technology and Chief Information Officer of ITC Holdings from 2013 to December 2021. | Vice President, Chief Information Officer |
| **KAREN M. MCCARTHY**, Newfoundland and Labrador, Canada<br>Vice President, Communications and Corporate Affairs since May 2018 and Director, Communications and Corporate Affairs from 2016 to May 2018. | Vice President, Communications and Corporate Affairs |
| **REGAN P. O'DEA,** Newfoundland and Labrador, Canada<br>Vice President, General Counsel since May 2017. | Vice President, General Counsel |
| **KEVIN D. WOODBURY,** Newfoundland and Labrador, Canada<br>Vice President, Innovation & Technology since July 2022. Director, Innovation & Technology from September 2021 to June 2022. Director, Business Development from November 2015 to September 2021.  | Vice President, Innovation and Technology |

---

The directors and executive officers of Fortis, as a group, beneficially own, directly or indirectly, or exercise control or direction over 334,627 common shares, representing 0.07% of the issued and outstanding common shares of Fortis. The common shares are the only voting securities of the Corporation.

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| | |
|:---|:---|
| **25** | **December 31, 2022** |

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<u>Annual Information Form</u>

**AUDIT COMMITTEE**

**Members**

The members of the Corporation's Audit Committee are Maura J. Clark (Chair), Tracey C. Ball, Lawrence T. Borgard, Margarita K. Dilley, Lisa L. Durocher, Douglas J. Haughey, Gianna M. Manes and Jo Mark Zurel. All members of the Audit Committee are independent and financially literate as those terms are defined by Canadian and U.S. 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 U.S. securities laws.

The Corporation's Audit Committee Mandate, effective as of January 1, 2023 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.

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| | |
|:---|:---|
| **Committee Member** | **Relevant Education and Experience** |
| **MAURA J. CLARK (*Chair*)** | 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 U.S. 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. |
| **TRACEY C. BALL** | 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. |
| **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. |
| **LISA L. DUROCHER** | Ms. Durocher leads Financial and Emerging Services at Rogers Communications. Prior to this role, Ms. Durocher was the Chief Digital Officer at Rogers. Prior to joining Rogers 7 years ago, Ms. Durocher held several senior leadership positions over 15 years at American Express in New York City, including leading global product and marketing organizations in digital payments, charge cards and travel. Ms. Durocher is a graduate of Wilfrid Laurier University's Business Administration program and also sits on the board of Rogers Bank. |
| **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. |
| **GIANNA M. MANES** | Ms. Manes was President and Chief Executive Officer of ENMAX Corporation, an electricity company with operations in Alberta and Maine, from 2012 until her retirement in July 2020. Before joining ENMAX, she worked for Duke Energy, one of the largest integrated utilities in North America, holding several executive positions including Senior Vice President and Chief Customer Officer from 2008 to 2012. She has over 30 years of experience in the energy sector in Canada, the United States and Europe. She graduated from Louisiana State University with a Bachelor of Science in industrial engineering and from the University of Houston with an MBA. She completed the Advanced Management Program at Harvard University and 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. |

---

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| | |
|:---|:---|
| **26** | **December 31, 2022** |

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------

<u>Annual Information Form</u>

**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** | **Deloitte LLP** |
| *($ thousands)* | **Description of Fee Category** | **2022** | 2021 |
| Audit Fees | Core audit services | **9837** | 9497 |
| 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 | **1398** | 1361 |
| Tax Fees | Services related to tax compliance, planning and advice | **92** | 269 |
| Other | Services which are not Audit Services, Audit-Related Fees or Tax Fees | **11** | 12 |
| **Total** |  | **11338** | 11139 |

---

**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 U.S. 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<sup>th</sup> 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

**INTERESTS OF EXPERTS**

Deloitte LLP is independent with respect to the Corporation within the meaning of the U.S. 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.

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| | |
|:---|:---|
| **27** | **December 31, 2022** |

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<u>Annual Information Form</u>

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 18, 2022 for the May 5, 2022 annual and special meeting of shareholders.

Requests for additional copies of the above-mentioned documents, as well as this 2022 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).

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| | |
|:---|:---|
| **28** | **December 31, 2022** |

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<u>Annual Information Form</u>

**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 classes 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 classes 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 classes 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 classes 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.

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| | |
|:---|:---|
| **29** | **December 31, 2022** |

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<u>Annual Information Form</u>

*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 9, 2023.

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| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Authorized** | **Issued and Outstanding** | **Initial Yield** *(%)* | **Annual Dividend** *($)* <sup>(1)</sup> | **Reset Dividend Yield**<br>*(%)* | **Redemption and/or Conversion Option Date** <sup>(2)</sup> | **Redemption Value** *($)* | **Right to Convert on a One for One Basis** |
| ***Perpetual Fixed Rate*** | | | | | | | | |
| Series F | **5000000** | **5000000** | **4.90** | **1.2250** | **—** | **Currently Redeemable** | **25.00** | **—** |
| Series J | **8000000** | **8000000** | **4.75** | **1.1875** | **—** | **Currently Redeemable** | **25.00** | **—** |
| ***Fixed Rate Reset*** <sup>(3)</sup> |  |  |  |  |  |  |  |  |
| Series G | **9200000** | **9200000** | **5.25** | **1.0983** | **2.13** | **September 1, 2023** | **25.00** | **—** |
| Series H <sup>(4)</sup> | **10000000** | **7665082** | **4.25** | **0.4588** | **1.45** | **June 1, 2025** | **25.00** | **Series I** |
| Series K <sup>(4)</sup> | **12000000** | **10000000** | **4.00** | **0.9823** | **2.05** | **March 1, 2024** | **25.00** | **Series L** |
| Series M <sup>(4)</sup> | **24000000** | **24000000** | **4.10** | **0.9783** | **2.48** | **December 1, 2024** | **25.00** | **Series N** |
| ***Floating Rate Reset*** <sup>(4) (5)</sup> |  |  |  |  |  |  |  |  |
| Series I | **10000000** | **2334918** | **2.10** | **—** | **1.45** | **June 1, 2025** | **25.00** | **Series H** |
| Series L | **12000000** | **—** | **—** | **—** | **—** | **—** | **—** | **Series K** |
| Series N | **24000000** | **—** | **—** | **—** | **—** | **—** | **—** | **Series M** |

---

<sup>(1)</sup> *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.*

<sup>(2)</sup> *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.*

<sup>(3)</sup> *On the redemption and/or conversion option date, and on each five-year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield.*

<sup>(4)</sup> *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.* 

<sup>(5)</sup> *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 9, 2023, there were no second preference shares issued and outstanding.

---

| | |
|:---|:---|
| **30** | **December 31, 2022** |

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<u>Annual Information Form</u>

**EXHIBIT B:**

**MARKET FOR SECURITIES**

**Common Shares**

The common shares are traded on the TSX in Canada, and on the NYSE in the U.S., 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, 2022, for the common shares on the TSX and NYSE in Canadian Dollars and U.S. Dollars, respectively.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **2022 Trading Prices and Volumes – Common Shares** | **2022 Trading Prices and Volumes – Common Shares** | **2022 Trading Prices and Volumes – Common Shares** | **2022 Trading Prices and Volumes – Common Shares** | **2022 Trading Prices and Volumes – Common Shares** | **2022 Trading Prices and Volumes – Common Shares** |
| | **TSX** | **TSX** | **TSX** | **NYSE** | **NYSE** | **NYSE** |
| **Month** | **High** *($)* | **Low** *($)* | **Volume** | **High** *($)* | **Low** *($)* | **Volume** |
| January | **61.13** | **57.59** | **27133958** | **48.20** | **45.58** | **10529439** |
| February | **60.49** | **56.64** | **39740361** | **47.64** | **44.58** | **10967232** |
| March | **62.28** | **57.87** | **31610193** | **49.86** | **45.48** | **13092500** |
| April | **65.13** | **61.39** | **27380986** | **51.66** | **48.55** | **10301774** |
| May | **65.26** | **60.77** | **54000756** | **50.89** | **47.33** | **16930384** |
| June | **63.32** | **57.56** | **29982755** | **50.42** | **44.32** | **15373152** |
| July | **61.89** | **58.81** | **23746336** | **48.23** | **45.58** | **13018536** |
| August | **61.73** | **57.92** | **38165385** | **47.89** | **44.11** | **17351724** |
| September | **59.16** | **52.43** | **26117969** | **45.58** | **37.93** | **15547207** |
| October | **54.14** | **48.45** | **39750263** | **39.81** | **34.76** | **20502251** |
| November | **54.23** | **52.29** | **55492348** | **40.70** | **38.07** | **20342073** |
| December | **56.69** | **53.67** | **29169463** | **41.78** | **39.48** | **11098489** |

---

**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, 2022.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **2022 Trading Prices and Volumes – First Preference Shares** | **2022 Trading Prices and Volumes – First Preference Shares** | **2022 Trading Prices and Volumes – First Preference Shares** | **2022 Trading Prices and Volumes – First Preference Shares** | **2022 Trading Prices and Volumes – First Preference Shares** | **2022 Trading Prices and Volumes – First Preference Shares** |
| | **First Preference Shares, Series F** | **First Preference Shares, Series F** | **First Preference Shares, Series F** | **First Preference Shares, Series G** | **First Preference Shares, Series G** | **First Preference Shares, Series G** |
| **Month** | **High** *($)* | **Low** *($)* | **Volume** | **High** *($)* | **Low** *($)* | **Volume** |
| January | **25.44** | **25.05** | **241131** | **23.20** | **22.03** | **188753** |
| February | **25.60** | **24.00** | **45558** | **23.17** | **21.55** | **67382** |
| March | **25.05** | **24.13** | **63944** | **22.05** | **20.25** | **123028** |
| April | **24.40** | **21.61** | **173838** | **22.04** | **18.99** | **117550** |
| May | **22.49** | **21.66** | **152977** | **20.97** | **19.40** | **127514** |
| June | **22.21** | **20.42** | **221442** | **21.81** | **19.50** | **92077** |
| July | **21.80** | **20.50** | **97262** | **20.47** | **17.97** | **111212** |
| August | **22.39** | **20.77** | **49415** | **19.97** | **18.47** | **114687** |
| September | **20.95** | **19.70** | **58871** | **19.01** | **17.32** | **111365** |
| October | **20.44** | **19.16** | **128135** | **18.00** | **16.33** | **118123** |
| November | **19.95** | **19.08** | **167339** | **18.77** | **16.85** | **266074** |
| December | **20.12** | **19.17** | **97208** | **17.30** | **16.70** | **294010** |

---

---

| | |
|:---|:---|
| **31** | **December 31, 2022** |

---

------

<u>Annual Information Form</u>

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **First Preference Shares, Series H** | **First Preference Shares, Series H** | **First Preference Shares, Series H** | **First Preference Shares, Series I** | **First Preference Shares, Series I** | **First Preference Shares, Series I** |
| **Month** | **High** *($)* | **Low** *($)* | **Volume** | **High** *($)* | **Low** *($)* | **Volume** |
| January | **17.92** | **16.74** | **89722** | **17.63** | **16.26** | **60997** |
| February | **18.00** | **16.29** | **30139** | **17.39** | **16.60** | **14976** |
| March | **16.81** | **15.40** | **73259** | **17.19** | **16.00** | **8286** |
| April | **16.75** | **14.10** | **96012** | **16.65** | **15.00** | **90116** |
| May | **15.88** | **14.40** | **88936** | **16.12** | **15.00** | **66359** |
| June | **16.30** | **14.52** | **235017** | **16.45** | **15.15** | **12424** |
| July | **15.01** | **13.22** | **51571** | **15.36** | **14.52** | **12634** |
| August | **14.72** | **13.72** | **20663** | **16.20** | **14.85** | **18772** |
| September | **14.50** | **13.25** | **70096** | **16.06** | **15.26** | **31597** |
| October | **13.37** | **11.57** | **498381** | **16.00** | **14.55** | **41740** |
| November | **12.75** | **12.03** | **95957** | **15.76** | **14.76** | **17698** |
| December | **13.01** | **12.20** | **56826** | **15.30** | **14.61** | **43203** |
|  | **First Preference Shares, Series J** | **First Preference Shares, Series J** | **First Preference Shares, Series J** | **First Preference Shares, Series K** | **First Preference Shares, Series K** | **First Preference Shares, Series K** |
| **Month** | **High** *($)* | **Low** *($)* | **Volume** | **High** *($)* | **Low** *($)* | **Volume** |
| January | **25.20** | **24.83** | **69211** | **22.30** | **21.03** | **105457** |
| February | **25.25** | **23.35** | **160930** | **22.10** | **20.52** | **43927** |
| March | **24.44** | **23.22** | **94833** | **20.99** | **18.90** | **84099** |
| April | **23.65** | **21.00** | **216786** | **21.35** | **17.82** | **158548** |
| May | **21.65** | **20.81** | **346042** | **19.84** | **18.11** | **78946** |
| June | **21.67** | **19.80** | **218676** | **20.67** | **18.23** | **47481** |
| July | **21.20** | **20.05** | **84104** | **19.30** | **16.88** | **68628** |
| August | **21.60** | **20.30** | **48453** | **18.99** | **17.56** | **84708** |
| September | **20.36** | **19.25** | **118283** | **18.31** | **16.79** | **87290** |
| October | **19.76** | **18.51** | **106548** | **17.16** | **15.52** | **162599** |
| November | **19.25** | **18.40** | **228147** | **17.50** | **15.75** | **92246** |
| December | **19.50** | **18.62** | **207691** | **16.25** | **15.19** | **128722** |
|  | **First Preference Shares, Series M** | **First Preference Shares, Series M** | **First Preference Shares, Series M** |  |  |  |
| **Month** | **High** *($)* | **Low** *($)* | **Volume** |  |  |  |
| January | **23.87** | **23.30** | **284938** |  |  |  |
| February | **23.78** | **22.25** | **145114** |  |  |  |
| March | **22.67** | **20.78** | **344427** |  |  |  |
| April | **22.60** | **18.76** | **139597** |  |  |  |
| May | **20.86** | **19.33** | **170114** |  |  |  |
| June | **21.70** | **19.65** | **115495** |  |  |  |
| July | **20.35** | **18.41** | **132673** |  |  |  |
| August | **20.10** | **18.75** | **215585** |  |  |  |
| September | **19.30** | **17.61** | **116535** |  |  |  |
| October | **17.99** | **16.38** | **133784** |  |  |  |
| November | **17.65** | **16.70** | **310877** |  |  |  |
| December | **17.32** | **15.92** | **353048** |  |  |  |

---

---

| | |
|:---|:---|
| **32** | **December 31, 2022** |

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------

<u>Annual Information Form</u>

**EXHIBIT C:**

**AUDIT COMMITTEE MANDATE** 

**(effective January 1, 2023)**

**1.0&nbsp;&nbsp;&nbsp;&nbsp;PURPOSE AND AUTHORITY**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.1&nbsp;&nbsp;&nbsp;&nbsp;The purpose of the Committee is to advise and assist the Board in fulfilling its oversight responsibilities relating to, among other things:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.the integrity of the Corporation's financial statements, financial disclosures and internal controls over financial reporting and disclosure controls and procedures;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.the Corporation's compliance with related legal and regulatory requirements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.the qualifications, independence and performance of the Independent Auditor and Internal Auditor, together with the compensation of the Independent Auditor;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.the Corporation's ERM Program and the management and mitigation of significant risks identified thereunder;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;e.the related policies of the Corporation set out herein; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;f.other matters set out herein or otherwise delegated to the Committee by the Board.

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;1.3&nbsp;&nbsp;&nbsp;&nbsp;To perform its duties and responsibilities, the Committee has the authority to: (i) conduct investigations into any matters within its scope of responsibility; (ii) have unrestricted access to information, management and employees and books and records of the Corporation and its affiliates; and (iii) directly access and communicate with the Independent Auditor and Internal Auditor.

**2.0&nbsp;&nbsp;&nbsp;&nbsp;DEFINITIONS**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;2.1&nbsp;&nbsp;&nbsp;&nbsp;In this Mandate:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a."**Board**" means the board of directors of the Corporation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b."**Chair**" means the Chair of the Committee;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c."**Committee**" means the audit committee of the Board;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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 condensed consolidated interim financial statements; and (iii) audit internal controls over financial reporting in accordance with the requirements of all applicable laws, regulations and professional standards;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;e."**Corporation**" means Fortis Inc.;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;f."**CPAB**" means the Canadian Public Accountability Board or its successor;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;g."**Director**" means a member of the Board;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;h."**ERM Program**" means the Corporation's Enterprise Risk Management Program that incorporates an effective risk management framework to identify, evaluate, manage, monitor and communicate key corporate risks;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;i."**Financial Expert**" means an "audit committee financial expert" as defined in SEC Regulation S-K;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;k."**Governance and Sustainability Committee**" means the governance and sustainability committee of the Board;

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| | |
|:---|:---|
| **33** | **December 31, 2022** |

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------

<u>Annual Information Form</u>

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;l."**Independent**" means, in the context of a Member and in accordance with all applicable laws and stock exchange requirements, being 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;n."**Internal Auditor**" means the person(s) employed or engaged by the Corporation to perform the internal audit function of the Corporation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;o."**Management**" means the senior officers of the Corporation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;p."**Mandate**" means this mandate of the Committee;

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;r."**Member**" means a Director appointed to the Committee;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;s."**NYSE**" means the New York Stock Exchange;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;t."**PCAOB**" means the Public Company Accounting Oversight Board or its successor;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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 and all applicable laws and stock exchange requirements which include, without limitation, transactions between: (i) executive officers, directors, principal shareholders or their immediate family members; and (ii) the Corporation or any of its subsidiaries; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;v."**SEC**" means the United States Securities and Exchange Commission.

**3.0&nbsp;&nbsp;&nbsp;&nbsp;ESTABLISHMENT AND COMPOSITION OF COMMITTEE**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.1&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall 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 shall appoint to the Committee at least one (1) Director who is a Financial Expert.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.2&nbsp;&nbsp;&nbsp;&nbsp;Members shall be appointed annually by the Board, or as otherwise necessary, provided, however, that each Director serving as a Member shall continue to serve until such Member resigns, is removed or has a successor appointed.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.3&nbsp;&nbsp;&nbsp;&nbsp;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 shall exercise all of the powers of the Committee so long as at least three (3) Members remain in office.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.4&nbsp;&nbsp;&nbsp;&nbsp;Any Member may be removed from the Committee or replaced by a resolution of the Board.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.5&nbsp;&nbsp;&nbsp;&nbsp;No Member shall serve on more than three (3) public company audit committees (inclusive of the Corporation) without the prior approval of the Board.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;3.6&nbsp;&nbsp;&nbsp;&nbsp;The Board shall appoint a Chair on the recommendation of the Corporation's Governance and Sustainability Committee, or such other committee as the Board may authorize. The Chair shall continue in that role until a successor is appointed. The Board shall periodically rotate the Chair and shall make reasonable efforts to rotate the Chair every four (4) years.

**4.0&nbsp;&nbsp;&nbsp;&nbsp;COMMITTEE MEETINGS**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.1&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall meet at least quarterly and at such other times as it deems appropriate. Meetings of the Committee shall be held at the call of: (i) the Chair; (ii) any two Members; or (iii) the Independent Auditor.

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.2&nbsp;&nbsp;&nbsp;&nbsp;The Chief Executive Officer, the Chief Financial Officer, the Independent Auditor and the Internal Auditor shall receive notice of and, unless otherwise determined by the Chair, shall be entitled to 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 unaudited condensed consolidated interim financial statements are reviewed.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.3&nbsp;&nbsp;&nbsp;&nbsp;A quorum at any meeting of the Committee shall be three (3) Members.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.4&nbsp;&nbsp;&nbsp;&nbsp;Each Member shall have the right to vote on matters that come before the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.5&nbsp;&nbsp;&nbsp;&nbsp;Matters to be determined by the Committee shall be decided by a majority of votes cast at a meeting of the Committee where such matter is considered. Actions of the Committee may also be taken by instruments in writing signed by all of the Members.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.6&nbsp;&nbsp;&nbsp;&nbsp;The Chair shall act as chair of all meetings of the Committee at which the Chair attends, otherwise the Members present at the meeting shall appoint one of their number to act as chair of the meeting.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.7&nbsp;&nbsp;&nbsp;&nbsp;Unless otherwise determined by the Chair, the Corporate Secretary of the Corporation shall act as secretary of all meetings of the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.8&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall 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. The Committee shall conduct *in camera* sessions without Management present at each meeting of the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.9&nbsp;&nbsp;&nbsp;&nbsp;The Committee may invite any Directors, officers or employees of the Corporation or any other person to attend the meetings of the Committee to assist in the discussion and examination of the matters under consideration by the Committee.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;4.10&nbsp;&nbsp;&nbsp;&nbsp;Subject to section 5.4, the Committee may delegate authority to individual Members or subcommittees, if deemed appropriate.

**5.0&nbsp;&nbsp;&nbsp;&nbsp;DUTIES AND RESPONSIBILITIES OF THE COMMITTEE**

**A.&nbsp;&nbsp;&nbsp;&nbsp;Independent Auditor**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.1&nbsp;&nbsp;&nbsp;&nbsp;In consultation and coordination with the subsidiary audit committees, the Committee shall be directly responsible for the selection and appointment (through a recommendation to the Board for the appointment by the shareholders), compensation and retention of the Independent Auditor.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.2&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall 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 shall report directly to the Committee and the Committee has the authority to communicate directly with the Independent Auditor.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.3&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall oversee the resolution of any disagreements between Management and the Independent Auditor. The Committee shall 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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.4&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall 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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.5&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall 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 and all applicable laws and stock exchange requirements and any other applicable regulations and professional standards. The Committee shall 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 applicable requirements and interpretative guidance of SEC Regulation S-X and any other applicable regulations and professional standards. The Committee shall discuss any potential independence issues with the Board and recommend any action that the Committee deems appropriate.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.6&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall review and evaluate the qualifications, independence and performance of the Independent Auditor and its lead engagement partner. Without limiting the foregoing, the Committee shall:

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.review and discuss with Management and separately with the Independent Auditor the results of the Corporation's annual Independent Auditor assessment process; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.at least annually, obtain and review a report from the Independent Auditor describing the firm's internal quality control processes 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 (5) years with respect to independent audits carried out by the Independent Auditor, and any steps taken to address such issues.

The Committee shall discuss any material issues identified with the Board and recommend any action that the Committee deems appropriate.

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.8&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall 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.&nbsp;&nbsp;&nbsp;&nbsp;Financial Reporting**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.9&nbsp;&nbsp;&nbsp;&nbsp;In consultation with Management, the Independent Auditor and the Internal Auditor, the Committee shall 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 shall receive and review:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.reports regarding: (i) critical accounting estimates, policies and practices; (ii) goodwill impairment testing; (iii) derivatives and hedges; (iv) any reserves, accruals, provisions and estimates that may have a material effect on the Corporation's financial statements; (v) any *pro forma*, adjusted or restated financial information, forecasts, or projections; and (vii) the effect of regulatory and accounting initiatives, as well as off-balance sheet arrangements, on the Corporation's financial statements;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.analyses by Management and the Independent Auditor regarding significant financial reporting issues and judgments 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 auditing and accounting principles and presentations, including significant changes in the selection or application of auditing and accounting principles; and (iii) major issues regarding the adequacy of the Corporation's internal controls over financial reporting and disclosure controls and procedures and any specific audit steps adopted in light of material weaknesses or significant deficiencies in such controls; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.other material written communication between Management and the Independent Auditor.

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.the Corporation's annual audited consolidated and non-consolidated financial statements and unaudited condensed consolidated interim financial statements and the Independent Auditor's related attestation reports, as well as any related MD&As;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Management's report and the Independent Auditor's audit report on internal controls over financial reporting;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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;

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&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.&nbsp;&nbsp;&nbsp;&nbsp;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 condensed consolidated interim 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 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;e.&nbsp;&nbsp;&nbsp;&nbsp;the report to shareholders contained in the Corporation's annual report; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;f.&nbsp;&nbsp;&nbsp;&nbsp;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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.11&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall, 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 releases or other news releases.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.12&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall 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 and disclosure controls and procedures, MD&As, earnings releases, and reports 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 reports on Form 40-F. The Committee shall approve the external release of the Corporation's unaudited condensed consolidated interim financial statements and related interim MD&As and earnings releases on behalf of the Board.

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.any future oriented financial information, financial outlooks, and earnings or dividend guidance to be provided by the Corporation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.the Annual Information Form and Management Information Circular to be filed by the Corporation;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.any prospectus or other offering documents and documents related thereto for the issuance of securities by the Corporation; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.other disclosure documents to be released publicly by the Corporation containing or derived from financial information.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.14&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall review, 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 alleged fraud involving Management or other employees.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.15&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall use reasonable efforts to satisfy itself as to the appropriateness of the Corporation's material financing, capital and tax structures.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.16&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall review, 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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.17&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall 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 laws.

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

**C.&nbsp;&nbsp;&nbsp;&nbsp;Internal Audit**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.19&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall be responsible for the appointment and 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.

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

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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.22&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall 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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.23&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall periodically discuss with the Internal Auditor the internal audit function's responsibility, budget, staffing and compensation.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.24&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall satisfy itself as to the performance of the internal audit function and the integrity and qualifications of its staff.

**D.&nbsp;&nbsp;&nbsp;&nbsp;Risk Management and Other**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.25&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall be responsible for the oversight of the ERM Program and shall report any actions or findings of the ERM Program to the Board.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.26&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall review and discuss with Management, the Internal Auditor and others as it deems appropriate Management's report regarding identifying, assessing, managing and mitigating significant risks and related matters identified pursuant to the ERM Program.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.27&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall satisfy itself as to the appropriateness of the Corporation's internal controls and processes associated with the release of any sustainability disclosures.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.28&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall review and discuss with Management and others as it deems appropriate the quarterly report prepared by Management regarding significant litigation and other material legal matters that could have a significant impact on the Corporation or its financial statements.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.29&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall be responsible for the oversight of the Corporation's insurance programs, any renewals or replacements thereof, including in respect of directors' and officers' insurance and indemnification of Directors.

**E.&nbsp;&nbsp;&nbsp;&nbsp;Policies and Mandate**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.30&nbsp;&nbsp;&nbsp;&nbsp;The Committee is responsible for the oversight of the following policies:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;a.Policy on Reporting Allegations of Suspected Improper Conduct and Wrongdoing (Speak Up Policy), 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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;b.Derivative Instruments and Hedging Policy;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;c.Pre-Approval Policy for Independent Auditor Services;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;d.Guidelines for Hiring Employees or Former Employees of the Independent Auditor;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;e.Policy on the Role of the Internal Audit Function;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;f.Disclosure Policy; and

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;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.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;5.31&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall periodically review this Mandate and the policies in Section 5.30 and recommend any necessary amendments to the Governance and Sustainability Committee for consideration and recommendation to the Board for approval, as deemed appropriate.

**6.0&nbsp;&nbsp;&nbsp;&nbsp;REPORTING**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;6.1&nbsp;&nbsp;&nbsp;&nbsp;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.

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**7.0&nbsp;&nbsp;&nbsp;&nbsp;REMUNERATION OF MEMBERS**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;7.1&nbsp;&nbsp;&nbsp;&nbsp;Members and the Chair shall receive such remuneration for their service on the Committee as the Board may determine from time to time, having considered the recommendation of the Governance and Sustainability Committee.

**8.0&nbsp;&nbsp;&nbsp;&nbsp;GENERAL**

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;8.1&nbsp;&nbsp;&nbsp;&nbsp;This Mandate shall be posted on the Corporation's corporate website at www.fortisinc.com.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;8.2&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall annually review its own effectiveness and performance.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;8.3&nbsp;&nbsp;&nbsp;&nbsp;The Committee shall perform any other activities consistent with this Mandate, the Corporation's by-laws and applicable laws, that the Board or Committee determines are necessary or appropriate.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;8.4&nbsp;&nbsp;&nbsp;&nbsp;The Committee may, in its discretion and in circumstances that it considers appropriate, obtain advice and assistance from outside legal, accounting and other advisors and approve the engagement by the Committee or any Member of outside advisors or persons having special expertise, all at the expense of the Corporation. The Corporation shall provide appropriate compensation, as determined by the Committee, for 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 and responsibilities.

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;8.5&nbsp;&nbsp;&nbsp;&nbsp;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 reporting, internal controls over financial reporting and disclosure controls and processes 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 members of the Committee or the Board under applicable laws.

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**EXHIBIT D:**

**MATERIAL CONTRACTS**

The following are the material contracts of Fortis filed on SEDAR and EDGAR during 2022 or which were entered into prior to 2022 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 Fourth Amended and Restated Credit Facility dated May 4, 2022, with The Bank of Nova Scotia as underwriter, sole lead arranger, book runner, sustainability structuring agent 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. The Fourth 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 Fourth 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.

**Amended and Restated Shareholders' Agreement**

On January 28, 2021, ITC Investment Holdings, ITC Holdings, FortisUS and Eiffel Investment, an affiliate of GIC, entered into an Amended and Restated Shareholders' Agreement, amending the shareholders' agreement among the parties originally entered into on October 14, 2016. The Amended and Restated Shareholders' Agreement governs the rights of the parties in their respective capacities as direct or indirect shareholders of ITC Holdings.

Under the terms of the Amended and Restated Shareholders' Agreement, Eiffel Investment has certain minority approval rights relating to ITC Investment Holdings and ITC Holdings which depend on: (x) whether Eiffel Investment is a holder of Class A common stock or Class B non-voting common stock at the relevant time and (y) the satisfaction by Eiffel Investment of certain ownership thresholds with respect to ITC Investment Holdings. The minority approval rights available to Eiffel Investment contingent on its ITC Investment Holdings share class and percentage ownership include rights 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 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 Amended and Restated 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 U.S. 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 currently 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.

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| **40** | **December 31, 2022** |

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## Exhibit 99.2

?xml version="1.0" ? fts-20221231_d2

Exhibit 99.2

<u>Consolidated Financial Statements</u>

FORTIS INC.

Audited Consolidated Financial Statements

As at and for the years ended December 31, 2022 and 2021

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| **1** | FORTIS INC. | DECEMBER 31, 2022 |

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<u>Consolidated Financial Statements</u>

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Table of Contents** | **Table of Contents** |  |  |  |  |
| Management's Report on Internal Control over Financial Reporting | Management's Report on Internal Control over Financial Reporting | **2** | NOTE 9 | Other Assets | **24** |
| Report of Independent Registered Public Accounting Firm | Report of Independent Registered Public Accounting Firm |  | NOTE 10 | Property, Plant and Equipment | **24** |
| &nbsp;&nbsp;&nbsp;("PCAOB ID No. 01208") - Opinion on the Financial Statements | &nbsp;&nbsp;&nbsp;("PCAOB ID No. 01208") - Opinion on the Financial Statements | **3** | NOTE 11 | Intangible Assets | **25** |
| Report of Independent Registered Public Accounting Firm - Opinion on | Report of Independent Registered Public Accounting Firm - Opinion on |  | NOTE 12 | Goodwill | **26** |
| &nbsp;&nbsp;&nbsp;Internal Control over Financial Reporting | &nbsp;&nbsp;&nbsp;Internal Control over Financial Reporting | **5** | NOTE 13 | Accounts Payable and Other Current Liabilities | **26** |
| Consolidated Balance Sheets | Consolidated Balance Sheets | **6** | NOTE 14 | Long-Term Debt | **27** |
| Consolidated Statements of Earnings | Consolidated Statements of Earnings | **7** | NOTE 15 | Leases | **30** |
| Consolidated Statements of Comprehensive Income | Consolidated Statements of Comprehensive Income | **7** | NOTE 16 | Other Liabilities | **31** |
| Consolidated Statements of Cash Flows | Consolidated Statements of Cash Flows | **8** | NOTE 17 | Earnings Per Common Share | **32** |
| Consolidated Statements of Changes in Equity | Consolidated Statements of Changes in Equity | **9** | NOTE 18 | Preference Shares | **32** |
| **Notes to Consolidated Financial Statements** | **Notes to Consolidated Financial Statements** | **Notes to Consolidated Financial Statements** | NOTE 19 | Accumulated Other Comprehensive Income | **33** |
| NOTE 1 | Description of Business | **10** | NOTE 20 | Stock-Based Compensation Plans | **33** |
| NOTE 2 | Regulation | **11** | NOTE 21 | Other Income, Net | **35** |
| NOTE 3 | Summary of Significant Accounting Policies | **13** | NOTE 22 | Income Taxes | **36** |
| NOTE 4 | Segmented Information | **19** | NOTE 23 | Employee Future Benefits | **37** |
| NOTE 5 | Revenue | **21** | NOTE 24 | Supplementary Cash Flow Information | **41** |
| NOTE 6 | Accounts Receivable and Other Current Assets | **22** | NOTE 25 | Fair Value of Financial Instruments and Risk Management | **41** |
| NOTE 7 | Inventories | **22** | NOTE 26 | Commitments and Contingencies | **45** |
| NOTE 8 | Regulatory Assets and Liabilities | **22** |  |  |  |

---

**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, 2022, 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, 2022, the Corporation's ICFR was effective.

The Corporation's ICFR as of December 31, 2022 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, 2022. Deloitte LLP issued an unqualified opinion for both audits.

February 9, 2023

---

| | |
|:---|:---|
| /s/ David G. Hutchens | /s/ Jocelyn H. Perry |
| **David G. Hutchens** | **Jocelyn H. Perry** |
| President and Chief Executive Officer, Fortis Inc. | Executive Vice President, Chief Financial Officer, Fortis Inc. |
| St. John's, Canada | |

---

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| | | |
|:---|:---|:---|
| **2** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

**Consolidated Financial Statements**

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, 2022 and 2021, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2022, 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, 2022, 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 9, 2023, expressed an unqualified opinion on the Corporation's internal control over financial reporting.

**Basis for Opinion**

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

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

**Critical Audit Matters**

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

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

*Critical Audit Matter Description*

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

Management's assessment primarily 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 terminal 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 terminal growth rate and discount rate used by management to estimate the fair value of more recently acquired reporting units included the following:

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

&nbsp;&nbsp;&nbsp;&nbsp;• Evaluating management's ability to accurately forecast the terminal growth rate by:

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

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

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

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

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

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| | | |
|:---|:---|:---|
| **3** | FORTIS INC. | DECEMBER 31, 2022 |

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------

**Consolidated Financial Statements**

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

*Critical Audit Matter Description*

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

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

*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:

&nbsp;&nbsp;&nbsp;&nbsp;• 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.

&nbsp;&nbsp;&nbsp;&nbsp;• 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.

&nbsp;&nbsp;&nbsp;&nbsp;• 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.

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

/s/ Deloitte LLP

Chartered Professional Accountants

St. John's, Canada

February 9, 2023

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

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| | | |
|:---|:---|:---|
| **4** | FORTIS INC. | DECEMBER 31, 2022 |

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------

**Consolidated Financial Statements**

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, 2022, 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, 2022, based on criteria established in *Internal Control - Integrated Framework* (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2022, of the Corporation and our report dated February 9, 2023, 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 9, 2023

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| | | |
|:---|:---|:---|
| **5** | FORTIS INC. | DECEMBER 31, 2022 |

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------

<u>Consolidated Financial Statements</u>

---

| | | |
|:---|:---|:---|
| **CONSOLIDATED BALANCE SHEETS** | **CONSOLIDATED BALANCE SHEETS** | **CONSOLIDATED BALANCE SHEETS** |
| **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** |
| *As at December 31 (in millions of Canadian dollars)* | **2022** | 2021 |
| **ASSETS** |  |  |
| **Current assets** |  |  |
| Cash and cash equivalents | $**209** | $131 |
| Accounts receivable and other current assets (Note 6) | **2339** | 1511 |
| Prepaid expenses | **146** | 116 |
| Inventories (Note 7) | **661** | 478 |
| Regulatory assets (Note 8) | **914** | 492 |
| **Total current assets** | **4269** | 2728 |
| Other assets (Note 9) | **1213** | 955 |
| Regulatory assets (Note 8) | **3095** | 3097 |
| Property, plant and equipment, net (Note 10) | **41663** | 37816 |
| Intangible assets, net (Note 11) | **1548** | 1343 |
| Goodwill (Note 12) | **12464** | 11720 |
| **Total assets** | $**64252** | $57659 |
| **LIABILITIES AND EQUITY** |  |  |
| **Current liabilities** |  |  |
| Short-term borrowings (Note 14) | $**253** | $247 |
| Accounts payable and other current liabilities (Note 13) | **3288** | 2570 |
| Regulatory liabilities (Note 8) | **595** | 357 |
| Current installments of long-term debt (Note 14) | **2481** | 1628 |
| **Total current liabilities** | **6617** | 4802 |
| Regulatory liabilities (Note 8) | **3320** | 2865 |
| Deferred income taxes (Note 22) | **4060** | 3627 |
| Long-term debt (Note 14) | **25931** | 23707 |
| Finance leases (Note 15) | **336** | 333 |
| Other liabilities (Note 16) | **1146** | 1409 |
| **Total liabilities** | **41410** | 36743 |
| Commitments and contingencies (Note 26) |  |  |
| **Equity** |  |  |
| Common shares <sup>(1)</sup>  | **14656** | 14237 |
| Preference shares (Note 18) | **1623** | 1623 |
| Additional paid-in capital | **10** | 10 |
| Accumulated other comprehensive income (loss) (Note 19) | **1008** | (40) |
| Retained earnings | **3733** | 3458 |
| Shareholders' equity | **21030** | 19288 |
| Non-controlling interests | **1812** | 1628 |
| **Total equity** | **22842** | 20916 |
| **Total liabilities and equity** | $**64252** | $57659 |

---

---

| | | |
|:---|:---|:---|
| <sup>(1)</sup> No par value. Unlimited authorized shares. 482.2 million and 474.8 million issued and outstanding as at December 31, 2022 and 2021, respectively | **Approved on Behalf of the Board** | **Approved on Behalf of the Board** |
|  | /s/ Jo Mark Zurel | /s/ Maura J. Clark |
|  | /s/ Jo Mark Zurel | /s/ Maura J. Clark |
|  | **Jo Mark Zurel,** | **Maura J. Clark,** |
|  | **Jo Mark Zurel,** | **Maura J. Clark,** |
| See accompanying Notes to Consolidated Financial Statements | **Director** | **Director** |

---

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| | | |
|:---|:---|:---|
| **6** | FORTIS INC. | DECEMBER 31, 2022 |

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<u>Consolidated Financial Statements</u>

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| | | |
|:---|:---|:---|
| **CONSOLIDATED STATEMENTS OF EARNINGS** | **CONSOLIDATED STATEMENTS OF EARNINGS** | **CONSOLIDATED STATEMENTS OF EARNINGS** |
| **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** |
| *For the years ended December 31 (in millions of Canadian dollars, except per share amounts)* | **2022** | 2021 |
| **Revenue (Note 5)** | $**11043** | $9448 |
| **Expenses** |  |  |
| Energy supply costs | **3952** | 2951 |
| Operating expenses | **2683** | 2523 |
| Depreciation and amortization | **1668** | 1505 |
| **Total expenses** | **8303** | 6979 |
| **Operating income** | **2740** | 2469 |
| Other income, net (Note 21) | **165** | 173 |
| Finance charges | **1102** | 1003 |
| **Earnings before income tax expense** | **1803** | 1639 |
| Income tax expense (Note 22) | **289** | 234 |
| **Net earnings** | $**1514** | $1405 |
| **Net earnings attributable to:** |  |  |
| Non-controlling interests | $**120** | $111 |
| Preference equity shareholders | **64** | 63 |
| Common equity shareholders | **1330** | 1231 |
|  | $**1514** | $1405 |
| **Earnings per common share (Note 17)** |  |  |
| Basic | $**2.78** | $2.61 |
| Diluted | $**2.78** | $2.61 |
| See accompanying Notes to Consolidated Financial Statements | See accompanying Notes to Consolidated Financial Statements | See accompanying Notes to Consolidated Financial Statements |

---

---

| | | |
|:---|:---|:---|
| **CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME** | **CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME** | **CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME** |
| *For the years ended December 31 (in millions of Canadian dollars)* | **2022** | 2021 |
| **Net earnings** | $**1514** | $1405 |
| **Other comprehensive income (loss)** |  |  |
| Unrealized foreign currency translation gains (losses), net of hedging activities and income tax recovery (expense) of $15 million and $(2) million, respectively  | **1100** | (93) |
| Other, net of income tax expense of $21 million and $3 million, respectively | **73** | 8 |
|  | **1173** | (85) |
| **Comprehensive income** | $**2687** | $1320 |
| **Comprehensive income attributable to:** |  |  |
| Non-controlling interests | $**245** | $100 |
| Preference equity shareholders | **64** | 63 |
| Common equity shareholders | **2378** | 1157 |
|  | $**2687** | $1320 |
| See accompanying Notes to Consolidated Financial Statements |  |  |

---

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| | | |
|:---|:---|:---|
| **7** | FORTIS INC. | DECEMBER 31, 2022 |

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<u>Consolidated Financial Statements</u>

---

| | | |
|:---|:---|:---|
| **CONSOLIDATED STATEMENTS OF CASH FLOWS** | **CONSOLIDATED STATEMENTS OF CASH FLOWS** | **CONSOLIDATED STATEMENTS OF CASH FLOWS** |
| **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** |
| *For the year ended December 31 (in millions of Canadian dollars)* | **2022** | 2021 |
| **Operating activities** |  |  |
| Net earnings | $**1514** | $1405 |
| Adjustments to reconcile net earnings to net cash provided by operating activities: |  |  |
| &nbsp;&nbsp;&nbsp;Depreciation - property, plant and equipment | **1460** | 1313 |
| &nbsp;&nbsp;&nbsp;Amortization - intangible assets | **145** | 136 |
| &nbsp;&nbsp;&nbsp;Amortization - other | **63** | 56 |
| &nbsp;&nbsp;&nbsp;Deferred income tax expense (Note 22) | **182** | 147 |
| &nbsp;&nbsp;&nbsp;Equity component, allowance for funds used during construction (Note 21) | **(78)** | (77) |
| &nbsp;&nbsp;&nbsp;Other | **105** | 75 |
| Change in long-term regulatory assets and liabilities | **162** | (4) |
| Change in working capital (Note 24) | **(479)** | (144) |
| **Cash from operating activities** | **3074** | 2907 |
| **Investing activities** |  |  |
| Additions to property, plant and equipment | **(3587)** | (3189) |
| Additions to intangible assets | **(278)** | (197) |
| Contributions in aid of construction | **111** | 93 |
| Contributions to equity-accounted investees | **(100)** |  |
| Other | **(205)** | (195) |
| **Cash used in investing activities** | **(4059)** | (3488) |
| **Financing activities** |  |  |
| Proceeds from long-term debt, net of issuance costs (Note 14) | **3067** | 1324 |
| Repayments of long-term debt and finance leases | **(1526)** | (634) |
| Borrowings under committed credit facilities | **6651** | 5082 |
| Repayments under committed credit facilities | **(6381)** | (4749) |
| Net change in short-term borrowings | **(21)** | 115 |
| Issue of common shares, net of costs, and dividends reinvested | **53** | 60 |
| Dividends |  |  |
| &nbsp;&nbsp;&nbsp;Common shares, net of dividends reinvested | **(673)** | (608) |
| &nbsp;&nbsp;&nbsp;Preference shares | **(64)** | (63) |
| &nbsp;&nbsp;&nbsp;Subsidiary dividends paid to non-controlling interests | **(66)** | (58) |
| Other | **(5)** | (18) |
| **Cash from financing activities** | **1035** | 451 |
| Effect of exchange rate changes on cash and cash equivalents | **28** | 12 |
| **Change in cash and cash equivalents** | **78** | (118) |
| Cash and cash equivalents, beginning of year | **131** | 249 |
| **Cash and cash equivalents, end of year** | $**209** | $131 |
| Supplementary Cash Flow Information (Note 24) | Supplementary Cash Flow Information (Note 24) | Supplementary Cash Flow Information (Note 24) |
| See accompanying Notes to Consolidated Financial Statements | See accompanying Notes to Consolidated Financial Statements | See accompanying Notes to Consolidated Financial Statements |

---

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| | | |
|:---|:---|:---|
| **8** | FORTIS INC. | DECEMBER 31, 2022 |

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<u>Consolidated Financial Statements</u>

---

| | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| **CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY** | **CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY** | **CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY** | **CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY** | **CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY** | **CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY** | **CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY** | **CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY** | **CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY** |
| **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** | **FORTIS INC.** |
| *For the years ended December 31<br>(in millions of Canadian dollars, except share numbers)* | **Common Shares**<br>*(# millions)* | **Common<br>Shares** | **Preference Shares**<br>(Note 18) | **Additional Paid-In<br>Capital** | **Accumulated Other Comprehensive Income (Loss)**<br>(Note 19) | **Retained<br>Earnings** | **Non-Controlling<br>Interests** | **Total<br>Equity** |
| **As at December 31, 2021** | **474.8** | $**14237** | $**1623** | $**10** | $**(40)** | $**3458** | $**1628** | $**20916** |
| Net earnings | **—** | **—** | **—** | **—** | **—** | **1394** | **120** | **1514** |
| Other comprehensive income | **—** | **—** | **—** | **—** | **1048** | **—** | **125** | **1173** |
| Common shares issued | **7.4** | **419** | **—** | **(2)** | **—** | **—** | **—** | **417** |
| Subsidiary dividends paid to non-controlling interests | **—** | **—** | **—** | **—** | **—** | **—** | **(66)** | **(66)** |
| Dividends declared on common shares ($2.20 per share) | **—** | **—** | **—** | **—** | **—** | **(1055)** | **—** | **(1055)** |
| Dividends on preference shares | **—** | **—** | **—** | **—** | **—** | **(64)** | **—** | **(64)** |
| Other | **—** | **—** | **—** | **2** | **—** | **—** | **5** | **7** |
| **As at December 31, 2022** | **482.2** | $**14656** | $**1623** | $**10** | $**1008** | $**3733** | $**1812** | $**22842** |
| **As at December 31, 2020** | 466.8 | $13819 | $1623 | $11 | $34 | $3210 | $1587 | $20284 |
| Net earnings |  |  |  |  |  | 1294 | 111 | 1405 |
| Other comprehensive loss |  |  |  |  | (74) |  | (11) | (85) |
| Common shares issued | 8.0 | 418 |  | (2) |  |  |  | 416 |
| Subsidiary dividends paid to non-controlling interests |  |  |  |  |  |  | (58) | (58) |
| Dividends declared on common shares ($2.08 per share) |  |  |  |  |  | (983) |  | (983) |
| Dividends on preference shares |  |  |  |  |  | (63) |  | (63) |
| Other |  |  |  | 1 |  |  | (1) |  |
| **As at December 31, 2021** | 474.8 | $14237 | $1623 | $10 | $(40) | $3458 | $1628 | $20916 |
| See accompanying Notes to Consolidated Financial Statements | See accompanying Notes to Consolidated Financial Statements | See accompanying Notes to Consolidated Financial Statements | See accompanying Notes to Consolidated Financial Statements | See accompanying Notes to Consolidated Financial Statements |  |  |  |  |

---

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| | | |
|:---|:---|:---|
| **9** | FORTIS INC. | DECEMBER 31, 2022 |

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Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

1. DESCRIPTION OF BUSINESS

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

**Regulated Utilities** 

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

ITC owns and operates high-voltage transmission lines in Michigan's lower peninsula and portions of Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma. ITC also has electric transmission system assets under construction in Wisconsin.

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

UNS Energy's largest operating subsidiary, TEP, and UNS Electric are vertically integrated regulated electric utilities. They generate, transmit and distribute electricity to retail customers in southeastern Arizona, including the greater Tucson metropolitan area in Pima County and parts of Cochise County, as well as in Santa Cruz and Mohave counties. TEP also sells wholesale electricity to other entities in the western United States. Together they own generating capacity of 3,328 megawatts ("MW"), including 68 MW of solar capacity and 250 MW of wind 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 primarily includes Central Hudson Gas & Electric Corporation. Central Hudson is a regulated electric and gas transmission and distribution utility that serves portions of New York State's Mid-Hudson River Valley and owns gas-fired and hydroelectric generating capacity totalling 65 MW.

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

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

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

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

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 90 MW. FortisOntario consists of three regulated electric utilities that provide service to customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario with a generating capacity of 5 MW. Wataynikaneyap Partnership is a partnership between 24 First Nations communities, Fortis and Algonquin Power & Utilities Corp. with a mandate to connect remote First Nations communities to the electricity grid in Ontario through the development of new transmission lines.

Caribbean Utilities is an integrated regulated electric utility and the sole electricity provider on Grand Cayman with a diesel-powered generating capacity of 166 MW. FortisTCI consists of two integrated regulated electric utilities that provide electricity to certain Turks and Caicos Islands and has a generating capacity of 86 MW, including 84 MW of diesel-powered generating capacity and 2 MW of solar capacity. Belize Electricity is an integrated electric utility and the principal distributor of electricity in Belize.

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|:---|:---|:---|
| **10** | FORTIS INC. | DECEMBER 31, 2022 |

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Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***1. DESCRIPTION OF BUSINESS (cont'd)***

**Non-Regulated** 

*Energy Infrastructure:* Long-term contracted generation assets in Belize and the Aitken Creek natural gas storage facility ("Aitken Creek") in British Columbia. Generation assets in Belize consist of three hydroelectric generating facilities with a combined generating capacity of 51 MW, held through the Corporation's indirectly wholly owned subsidiary Fortis Belize Limited (formerly known as Belize Electric Company Limited). 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.

*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 and non-regulated holding company expenses.

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 deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). PBR mechanisms generally apply a formula that incorporates inflation and assumed productivity improvements for a set term.

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

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

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|:---|:---|:---|
| **11** | FORTIS INC. | DECEMBER 31, 2022 |

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Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***2. REGULATION (cont'd)***

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| **Nature of Regulation** | **Nature of Regulation** | **Nature of Regulation** | **Nature of Regulation** | **Nature of Regulation** | **Nature of Regulation** |
| | | **Allowed**<br>**Common**<br>**Equity**<br>*(%)* | **Allowed ROE** <sup>(1)</sup><br>*(%)* | **Allowed ROE** <sup>(1)</sup><br>*(%)* | |
| **Regulated Utility** | **Regulatory Authority** | **Allowed**<br>**Common**<br>**Equity**<br>*(%)* | **2022** | 2021 | **Significant Features** |
| ITC <sup>(2)</sup> | Federal Energy Regulatory Commission ("FERC") | 60.0 | &nbsp;&nbsp;&nbsp;&nbsp;**10.77** | 10.77 | Cost-based formula rates, with annual true-up mechanism <sup>(3)</sup><br>Incentive adders |
|  | Federal Energy Regulatory Commission ("FERC") |  |  |  | Cost-based formula rates, with annual true-up mechanism <sup>(3)</sup><br>Incentive adders |
| TEP | Arizona Corporation Commission ("ACC") <sup>(4)</sup> | 53.0 | &nbsp;&nbsp;&nbsp;&nbsp;**9.15** | 9.15 | COS regulation<br>Historical test year |
|  | FERC | <sup>(5)</sup> | **9.79** | 9.79 | Formula transmission rates |
| UNS Electric | ACC | 52.8 | **9.50** | 9.50 |  |
| UNS Gas | ACC | 50.8 | &nbsp;&nbsp;&nbsp;&nbsp;**9.75** | 9.75 |  |
| Central Hudson <sup>(6)</sup> | New York State Public Service Commission ("PSC")  | 49.0 | &nbsp;&nbsp;&nbsp;&nbsp;**9.00** | 9.00 | COS regulation<br>Future test year |
|  | New York State Public Service Commission ("PSC")  |  |  |  | COS regulation<br>Future test year |
| FortisBC Energy <sup>(7)</sup> | British Columbia Utilities Commission ("BCUC") | 38.5 | &nbsp;&nbsp;&nbsp;&nbsp;**8.75** | 8.75 | COS regulation with formula components and incentives <sup>(8)</sup> |
|  | British Columbia Utilities Commission ("BCUC") |  |  |  | COS regulation with formula components and incentives <sup>(8)</sup> |
| FortisBC Electric <sup>(7)</sup> | BCUC | 40.0 | &nbsp;&nbsp;&nbsp;&nbsp;**9.15** | 9.15 | Future test year |
| FortisAlberta | Alberta Utilities Commission ("AUC") | 37.0 | &nbsp;&nbsp;&nbsp;&nbsp;**8.50**  | 8.50 | PBR <sup>(9)</sup> |
| Newfoundland Power | Newfoundland and Labrador Board of Commissioners of Public Utilities | 45.0 | &nbsp;&nbsp;&nbsp;&nbsp;**8.50** | 8.50 | COS regulation<br>Future test year |
| Newfoundland Power | Newfoundland and Labrador Board of Commissioners of Public Utilities |  |  |  | COS regulation<br>Future test year |
| Maritime Electric | Island Regulatory and Appeals Commission | 40.0 | &nbsp;&nbsp;&nbsp;&nbsp;**9.35** | 9.35 | COS regulation<br>Future test year |
| Maritime Electric | Island Regulatory and Appeals Commission |  |  |  | COS regulation<br>Future test year |
| FortisOntario <sup>(10)</sup> | Ontario Energy Board | 40.0 | &nbsp;&nbsp;&nbsp;&nbsp;**8.52-9.30** | 8.52-9.30 | COS regulation with incentive mechanisms |
| Caribbean Utilities <sup>(11)</sup> | Utility Regulation and Competition Office | N/A | &nbsp;&nbsp;&nbsp;&nbsp;**6.25-8.25** | 6.00-8.00 | COS regulation<br>Rate-cap adjustment mechanism<br>based on published consumer price indices |
| FortisTCI <sup>(12)</sup> | Government of the Turks and Caicos Islands | N/A | &nbsp;&nbsp;&nbsp;&nbsp;**15.00-17.50**  | 15.00-17.50  | COS regulation<br>Historical test year |

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<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*ROA for Caribbean Utilities and FortisTCI*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Includes the allowed common equity and base ROE plus incentive adders for ITCTransmission, METC, and ITC Midwest. See "Significant Regulatory Developments" below*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Annual true-up collected or refunded in rates within a two-year period*

<sup>(4)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Approved ROE of 9.15% with a 0.20% return on the fair value increment. A general rate application requesting new rates effective September 1, 2023 is ongoing. See "Significant Regulatory Developments" below*

<sup>(5)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*The allowed common equity component for FERC transmission rates is formulaic, and is updated annually based on TEP's actual equity ratio*

<sup>(6)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Effective July 1, 2021 Central Hudson's approved common equity component of capital structure was 50%, declining by 1% annually to 48% in the third rate year*

<sup>(7)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*A generic cost of capital ("GCOC") proceeding is ongoing. See "Significant Developments" below*

<sup>(8)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Formula and incentives have been set through 2024*

<sup>(9)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*FortisAlberta is subject to PBR including mechanisms for flow-through costs and capital expenditures not otherwise recovered through customer rates. FortisAlberta's current PBR term expired as of December 31, 2022. See "Significant Regulatory Developments" below*

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

<sup>(11)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;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*

<sup>(12)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Operates under 50-year licences from the Government of the Turks and Caicos Islands, which expire in 2036 and 2037*

**Significant Regulatory Developments**

**ITC**

*ITC Midwest Capital Structure Complaint:* In May 2022, the Iowa Coalition for Affordable Transmission ("ICAT") filed a complaint with FERC under Section 206 of the Federal Power Act requesting that ITC Midwest's common equity component of capital structure be reduced from 60% to 53%. ICAT alleged that ITC Midwest does not meet FERC's three-part test for authorizing the use of the utility's actual capital structure for rate-making purposes. In November 2022, FERC issued an order denying the complaint, and in December 2022, ICAT filed a request for rehearing with FERC. As at December 31, 2022, ITC Midwest has not recorded a regulatory liability related to the complaint.

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|:---|:---|:---|
| **12** | FORTIS INC. | DECEMBER 31, 2022 |

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Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***2. REGULATION (cont'd)***

*MISO Base ROE:* In August 2022, the U.S. Court of Appeals for the District of Columbia Circuit issued a decision vacating certain FERC orders that had established the methodology for setting the base ROE for transmission owners operating in the Midcontinent Independent System Operator, Inc. ("MISO") region, including ITC. This matter dates back to complaints filed at FERC in 2013 and 2015 challenging the MISO base ROE then in effect. The court has remanded the matter to FERC for further process, the timing and outcome of which is unknown.

*Transmission Incentives:* In 2021, FERC issued a supplemental notice of proposed rulemaking ("NOPR") on transmission incentives modifying the proposal in the initial NOPR released by FERC in 2020. The supplemental NOPR proposes to eliminate the 50-basis point regional transmission organization ("RTO") ROE incentive adder for RTO members that have been members for longer than three years. The timing and outcome of this proceeding is unknown.

**UNS Energy**

*TEP General Rate Application:* In June 2022, TEP filed a general rate application with the ACC requesting new rates effective September 1, 2023 using a December 31, 2021 test year. The application reflects a US$136 million net increase in non-fuel and fuel-related revenue, as well as proposals to eliminate certain adjustor mechanisms, and modify an existing adjustor to provide more timely recovery of clean energy investments. The timing and outcome of this proceeding is unknown.

**Central Hudson**

*Customer Information System ("CIS") Implementation:* In December 2022, the PSC released a report into the deployment by Central Hudson of its new CIS. The PSC also issued an Order to Commence Proceeding and Show Cause, which directed Central Hudson to explain why the PSC should not pursue civil or administrative penalties or initiate a proceeding to review the prudence of the CIS implementation costs. Central Hudson was also required to submit a plan to eliminate bi-monthly bill estimates and to evaluate the customer impacts of such a change. Central Hudson's response was filed in January 2023. The timing and outcome of this proceeding is unknown.

**FortisBC Energy and FortisBC Electric**

*GCOC Proceeding:* In 2021, the BCUC initiated a proceeding including a review of the common equity component of capital structure and the allowed ROE. FortisBC filed a final argument with the BCUC in December 2022 and the proceeding remains ongoing, with a decision expected in the second quarter of 2023.

**FortisAlberta**

*2023/2024 GCOC Proceeding:* In January 2022, the AUC initiated proceedings to establish the cost of capital parameters for Alberta regulated utilities for 2023 and to consider a formula-based approach to setting the allowed ROE for 2024 and beyond. In March 2022, the AUC issued a decision extending the existing allowed ROE of 8.5% using a 37% equity component of capital structure through 2023. The GCOC proceeding for 2024 and beyond remains ongoing, and a decision is expected in the third quarter of 2023.

*2023 COS Application:* In July 2022, the AUC issued a decision largely accepting the forecast requested in FortisAlberta's COS application. The associated compliance filing, including the updated 2023 revenue requirement, was approved by the AUC in December 2022.

*Third PBR Term*: In July 2021, the AUC issued a decision confirming that Alberta distribution utilities will be subject to a third PBR term commencing in 2024 with going-in rates based on the 2023 COS rebasing. The AUC also initiated a new proceeding to consider the design of the third PBR term. FortisAlberta is participating in this proceeding and a decision from the AUC is expected in 2023.

*Rural Electrification Association ("REA") Cost Recovery*: In 2021, the AUC determined that costs attributable to REAs, approximating $10 million annually, can no longer be recovered from FortisAlberta's rate payers, effective January 1, 2023. FortisAlberta filed an appeal with the Alberta Court of Appeal, asserting that the AUC erred in preventing the company from recovering these costs from its own rate payers to the extent that such costs cannot be recovered directly from REAs. The appeal was heard in December 2022, and a decision from the Court is expected in first quarter of 2023.

**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 ("U.S. GAAP") for rate-regulated entities, and are in Canadian dollars unless otherwise indicated.

These consolidated financial statements include the accounts of the Corporation and its subsidiaries. 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 U.S. GAAP for rate-regulated entities.

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|:---|:---|:---|
| **13** | FORTIS INC. | DECEMBER 31, 2022 |

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Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)***

**Cash and Cash Equivalents**

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

**Allowance for Credit Losses**

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

**Inventories** 

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

**Regulatory Assets and Liabilities**

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

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

**Investments**

Investments 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 removal costs not identified as a legal obligation. The provision is recognized as a long-term regulatory liability (Note 8) against which actual removal costs are netted when incurred.

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

Through methodologies established by their respective regulators, the Corporation's regulated utilities capitalize: (i) overhead costs that are not directly attributable to specific PPE but relate to the overall capital expenditure plan; and (ii) an allowance for funds used during construction ("AFUDC"). The debt component of AFUDC for 2022 totalled $45 million (2021 - $39 million) and is reported as a reduction of finance charges and the equity component is reported as other income (Note 21). Both components are recorded to earnings through depreciation expense over the estimated service lives of the applicable PPE.

Excluding UNS Energy and Central Hudson, PPE includes inventory held for the development, construction and betterment of other assets. As required by its regulators, 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 and ranged from 0.5% to 39.8% for 2022 (2021 - 0.9% to 39.8%). The weighted average composite rate of depreciation, before reduction for amortization of contributions in aid of construction, was 2.7% for 2022 (2021 – 2.6%).

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|:---|:---|:---|
| **14** | FORTIS INC. | DECEMBER 31, 2022 |

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Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)***

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

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| | | | | |
|:---|:---|:---|:---|:---|
| | **2022** | **2022** | 2021 | 2021 |
| *(years)* | **Service Life**<br>**Ranges** | **Weighted<br>Average<br>Remaining<br>Service Life** | Service Life<br>Ranges | Weighted<br>Average<br>Remaining<br>Service Life |
| Distribution |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Electric | **5-80** | **31** | 5-80 | 32 |
| &nbsp;&nbsp;&nbsp;Gas | **18-95** | **39** | 18-95 | 38 |
| Transmission |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Electric | **20-90** | **41** | 20-90 | 42 |
| &nbsp;&nbsp;&nbsp;Gas | **10-85** | **35** | 10-85 | 35 |
| Generation | **5-95** | **22** | 5-95 | 23 |
| Other | **3-80** | **11** | 3-70 | 13 |

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**Intangible Assets**

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

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

Intangible assets with finite lives are amortized using the straight-line method based on the estimated service lives of the assets. Amortization rates for regulated intangible assets are approved by the respective regulators and ranged from 1.0% to 33.0% for 2022 (2021 – 1.0% to 33.0%).

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

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| | | | | |
|:---|:---|:---|:---|:---|
| | **2022** | **2022** | 2021 | 2021 |
| *(years)* | **Service Life<br>Ranges** | **Weighted<br>Average<br>Remaining<br>Service Life** | Service Life<br>Ranges | Weighted<br>Average<br>Remaining<br>Service Life |
| Computer software | **3-15** | **5** | 3-15 | 4 |
| Land, transmission and water rights | **34-90** | **54** | 34-90 | 55 |
| Other | **10-100** | **11** | 10-100 | 11 |

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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 total undiscounted cash flows expected to be generated by the asset may be below carrying value. 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.

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

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

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|:---|:---|:---|
| **15** | FORTIS INC. | DECEMBER 31, 2022 |

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Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)***

**Deferred Financing Costs**

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

**Employee Future Benefits**

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

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

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

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

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

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

**Leases**

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

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

**Revenue Recognition**

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

FortisAlberta is a distribution company and is required by its regulator to arrange and pay for transmission services with the Alberta Electric System Operator. 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 probable.

Revenue excludes sales and municipal taxes collected from customers.

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|:---|:---|:---|
| **16** | FORTIS INC. | DECEMBER 31, 2022 |

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Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)***

**Revenue Recognition (cont'd)**

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

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

**Stock-Based Compensation**

Effective January 1, 2022, stock options have been excluded from the Corporation's long-term incentive mix. Compensation expense related to stock options granted in 2021 or prior were measured at the grant date using the Black-Scholes fair value option-pricing model with each grant amortized to compensation expense evenly over the four-year vesting period, with the offsetting entry to additional paid-in capital. Fortis satisfies stock option exercises by issuing common shares from treasury. Upon exercise, proceeds are credited to capital stock at the option prices and the fair value of the options, as previously recognized, is reclassified from additional paid-in capital to capital stock.

Fortis recognizes liabilities associated with its directors' Deferred Share Unit ("DSU"), Performance Share Unit ("PSU") and Restricted Share Unit ("RSU") Plans. DSUs and PSUs, represent cash-settled awards whereas RSU's represent cash or share-settled awards, depending on settlement elections and the share ownership requirements of the executive. The fair value of these liabilities is based on the five-day volume weighted average price ("VWAP") of the Corporation's common shares at the end of each reporting period. The VWAP as at December 31, 2022 was $54.65 (2021 - $61.08). 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 U.S. 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, 2022 was US$1.00=CA$1.36 (2021 – US$1.00=CA$1.26).

Revenue and expenses of the Corporation's foreign operations are translated at the average exchange rate for the reporting period, which was US$1.00=CA$1.30 for 2022 (2021 - US$1.00=CA$1.25).

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 U.S. dollar cash inflows and forecast future cash settlements of DSU, PSU and RSU obligations; (ii) UNS Energy, to meet forecast load and reserve requirements; and (iii) Aitken Creek, to manage commodity price risk, capture natural gas price spreads, and manage the financial risk of physical transactions. These derivatives are measured at fair value with changes thereto recognized in earnings.

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

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

*Derivatives Designated as Hedges*

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

The Corporation's earnings from, and net investments in, foreign subsidiaries and certain equity-accounted investments are exposed to fluctuations in the U.S. dollar-to-Canadian dollar exchange rate. The Corporation has hedged a portion of this exposure through U.S. 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.

---

| | | |
|:---|:---|:---|
| **17** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)***

**Derivatives and Hedging (cont'd)**

*Presentation of Derivatives*

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

**Income Taxes**

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

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

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

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

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 $5.3 billion as at December 31, 2022 (2021 - $4.1 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, rights-of-way and agreements are reasonably expected to effectively exist and operate in perpetuity due to their nature. Consequently, where the final date and cost of remediation and/or removal of the noted assets cannot be reasonably determined, AROs have not been recognized.

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

**Contingencies**

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

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

---

| | | |
|:---|:---|:---|
| **18** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (cont'd)***

**Use of Accounting Estimates**

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

**Future Accounting Pronouncements**

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

4. SEGMENTED INFORMATION

**General**

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

**Related-Party and Inter-Company Transactions**

Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions in 2022 or 2021.

The lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy of $37 million in 2022 (2021 - $38 million) are inter-company transactions between non-regulated and regulated entities, which were not eliminated on consolidation.

As at December 31, 2022, accounts receivable included $7 million due from Belize Electricity (2021 - $22 million).

Fortis periodically provides short-term financing to subsidiaries to support capital expenditures and seasonal working capital requirements, the impacts of which are eliminated on consolidation. As at December 31, 2022, there were no inter-segment loans outstanding (2021 - $126 million). Interest charged on inter-segment loans was not material in 2022 and 2021.

---

| | | |
|:---|:---|:---|
| **19** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***4. SEGMENTED INFORMATION (cont'd)***

---

| | | | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| | **Regulated** | **Regulated** | **Regulated** | **Regulated** | **Regulated** | **Regulated** | **Regulated** | **Regulated** | **Non-Regulated** | **Non-Regulated** | | |
| | | | | | | | | | **Energy** | | **Inter-** | |
| | | UNS | Central | FortisBC | Fortis | FortisBC | Other | **Sub-** | **Infra-** | **Corporate** | **segment** | |
| *($ millions)* | ITC | Energy | Hudson | Energy | Alberta | Electric | Electric | **total** | **structure** | **and Other** | **eliminations** | **Total** |
| **Year ended December 31, 2022** |  |  |  |  |  |  |  |  |  |  |  |  |
| Revenue | 1906 | 2758 | 1325 | 2084 | 680 | 487 | 1652 | **10892** | **151** | **—** | **—** | **11043** |
| Energy supply costs |  | 1213 | 525 | 1055 |  | 141 | 1013 | **3947** | **5** | **—** | **—** | **3952** |
| Operating expenses | 481 | 691 | 571 | 364 | 166 | 133 | 217 | **2623** | **40** | **20** | **—** | **2683** |
| Depreciation and amortization | 385 | 365 | 104 | 298 | 243 | 67 | 187 | **1649** | **17** | **2** | **—** | **1668** |
| Operating income | 1040 | 489 | 125 | 367 | 271 | 146 | 235 | **2673** | **89** | **(22)** | **—** | **2740** |
| Other income, net | 48 | 22 | 59 | 22 | 5 | 6 | 14 | **176** | **1** | **(12)** | **—** | **165** |
| Finance charges | 349 | 127 | 53 | 146 | 110 | 76 | 75 | **936** | **—** | **166** | **—** | **1102** |
| Income tax expense | 184 | 56 | 28 | 39 | 15 | 12 | 22 | **356** | **18** | **(85)** | **—** | **289** |
| Net earnings | 555 | 328 | 103 | 204 | 151 | 64 | 152 | **1557** | **72** | **(115)** | **—** | **1514** |
| Non-controlling interests | 101 |  |  | 1 |  |  | 18 | **120** | **—** | **—** | **—** | **120** |
| Preference share dividends |  |  |  |  |  |  |  | **—** | **—** | **64** | **—** | **64** |
| Net earnings attributable to common equity shareholders | 454 | 328 | 103 | 203 | 151 | 64 | 134 | **1437** | **72** | **(179)** | **—** | **1330** |
| Additions to property, plant and equipment and intangible assets | 1212 | 709 | 293 | 589 | 510 | 130 | 393 | **3836** | **29** | **—** | **—** | **3865** |
| **As at December 31, 2022** |  |  |  |  |  |  |  |  |  |  |  |  |
| Goodwill | 8318 | 1873 | 612 | 913 | 228 | 235 | 258 | **12437** | **27** | **—** | **—** | **12464** |
| Total assets | 23478 | 12678 | 5131 | 8875 | 5547 | 2596 | 4916 | **63221** | **884** | **159** | **(12)** | **64252** |
| Year ended December 31, 2021 |  |  |  |  |  |  |  |  |  |  |  |  |
| Revenue | 1691 | 2334 | 1000 | 1715 | 644 | 468 | 1498 | 9350 | 98 |  |  | 9448 |
| Energy supply costs |  | 919 | 285 | 713 |  | 136 | 895 | 2948 | 3 |  |  | 2951 |
| Operating expenses | 466 | 648 | 498 | 355 | 157 | 128 | 201 | 2453 | 33 | 37 |  | 2523 |
| Depreciation and amortization | 291 | 345 | 91 | 281 | 231 | 65 | 181 | 1485 | 17 | 3 |  | 1505 |
| Operating income | 934 | 422 | 126 | 366 | 256 | 139 | 221 | 2464 | 45 | (40) |  | 2469 |
| Other income, net | 42 | 41 | 34 | 12 | 2 | 5 | 5 | 141 | 1 | 31 |  | 173 |
| Finance charges | 300 | 120 | 46 | 144 | 106 | 73 | 71 | 860 |  | 143 |  | 1003 |
| Income tax expense | 156 | 51 | 21 | 48 | 11 | 12 | 21 | 320 | 8 | (94) |  | 234 |
| Net earnings | 520 | 292 | 93 | 186 | 141 | 59 | 134 | 1425 | 38 | (58) |  | 1405 |
| Non-controlling interests | 94 |  |  | 1 |  |  | 16 | 111 |  |  |  | 111 |
| Preference share dividends |  |  |  |  |  |  |  |  |  | 63 |  | 63 |
| Net earnings attributable to common equity shareholders | 426 | 292 | 93 | 185 | 141 | 59 | 118 | 1314 | 38 | (121) |  | 1231 |
| Additions to property, plant and equipment and intangible assets | 1046 | 710 | 291 | 475 | 389 | 134 | 321 | 3366 | 20 |  |  | 3386 |
| As at December 31, 2021 |  |  |  |  |  |  |  |  |  |  |  |  |
| Goodwill | 7755 | 1746 | 570 | 913 | 228 | 235 | 246 | 11693 | 27 |  |  | 11720 |
| Total assets | 21020 | 11126 | 4356 | 8135 | 5201 | 2540 | 4357 | 56735 | 777 | 295 | (148) | 57659 |

---

---

| | | |
|:---|:---|:---|
| **20** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**5. REVENUE** 

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| **Electric and gas revenue** |  |  |
| United States |  |  |
| &nbsp;&nbsp;&nbsp;ITC | **1911** | 1694 |
| &nbsp;&nbsp;&nbsp;UNS Energy | **2498** | 2071 |
| &nbsp;&nbsp;&nbsp;Central Hudson | **1307** | 962 |
| Canada |  |  |
| &nbsp;&nbsp;&nbsp;FortisBC Energy | **2080** | 1645 |
| &nbsp;&nbsp;&nbsp;FortisAlberta | **655** | 622 |
| &nbsp;&nbsp;&nbsp;FortisBC Electric | **429** | 404 |
| &nbsp;&nbsp;&nbsp;Newfoundland Power | **722** | 701 |
| &nbsp;&nbsp;&nbsp;Maritime Electric | **234** | 223 |
| &nbsp;&nbsp;&nbsp;FortisOntario | **220** | 211 |
| Caribbean |  |  |
| &nbsp;&nbsp;&nbsp;Caribbean Utilities | **349** | 248 |
| &nbsp;&nbsp;&nbsp;FortisTCI | **98** | 89 |
| **Total electric and gas revenue** | **10503** | 8870 |
| Other services revenue <sup>(1)</sup> | **409** | 382 |
| **Revenue from contracts with customers** | **10912** | 9252 |
| Alternative revenue | **(28)** | (18) |
| Other revenue | **159** | 214 |
| **Total revenue** | **11043** | 9448 |

---

<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Includes $266 million and $260 million from regulated operations for 2022 and 2021, respectively*

***Revenue from Contracts with Customers***

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

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

***Alternative Revenue***

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

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

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

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

***Other Revenue***

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

---

| | | |
|:---|:---|:---|
| **21** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**6. ACCOUNTS RECEIVABLE AND OTHER CURRENT ASSETS** 

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Trade accounts receivable | **930** | 621 |
| Unbilled accounts receivable | **887** | 701 |
| Allowance for credit losses | **(58)** | (53) |
|  | **1759** | 1269 |
| Other <sup>(1)</sup> | **580** | 242 |
|  | **2339** | 1511 |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Consists mainly of customer billings for non-core services, gas mitigation costs and collateral deposits for gas purchases, and the fair value of derivative instruments (Note 25)*

**Allowance for Credit Losses**

The allowance for credit losses changed as follows.

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Balance, beginning of year | **(53)** | (64) |
| Credit loss expensed | **(27)** | (7) |
| Credit loss deferral | **(6)** |  |
| Write-offs, net of recoveries | **30** | 18 |
| Foreign exchange | **(2)** |  |
| Balance, end of year | **(58)** | (53) |

---

See Note 25 for disclosure on the Corporation's credit risk.

**7. INVENTORIES** 

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Materials and supplies | **394** | 318 |
| Gas and fuel in storage | **235** | 131 |
| Coal inventory | **32** | 29 |
|  | **661** | 478 |

---

**8. REGULATORY ASSETS AND LIABILITIES** 

---

| | | |
|:---|:---|:---|
| *($ millions*) | **2022** | 2021 |
| **Regulatory assets** |  |  |
| Deferred income taxes (Note 3) | **1874** | 1806 |
| Rate stabilization and related accounts <sup>(1)</sup> | **557** | 339 |
| Deferred energy management costs <sup>(2)</sup> | **445** | 384 |
| Employee future benefits (Notes 3 and 23) | **207** | 388 |
| Deferred lease costs <sup>(3)</sup> | **132** | 127 |
| Manufactured gas plant site remediation deferral (Note 16) | **97** | 96 |
| Deferred restoration costs <sup>(4)</sup> | **91** | 17 |
| Derivatives (Notes 3 and 25) | **84** | 20 |
| Generation early retirement costs <sup>(5)</sup> | **78** | 48 |
| Other regulatory assets <sup>(6)</sup> | **444** | 364 |
| **Total regulatory assets** | **4009** | 3589 |
| **Less: Current portion** | **(914)** | (492) |
| **Long-term regulatory assets** | **3095** | 3097 |

---

---

| | | |
|:---|:---|:---|
| **22** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***8. REGULATORY ASSETS AND LIABILITIES (cont'd)***

---

| | | |
|:---|:---|:---|
| ($ millions) | **2022** | 2021 |
| **Regulatory liabilities** |  |  |
| Deferred income taxes (Note 3) | **1364** | 1289 |
| Future cost of removal (Note 3) | **1306** | 1217 |
| Employee future benefits (Notes 3 and 23) | **306** | 196 |
| Rate stabilization and related accounts <sup>(1)</sup> | **297** | 116 |
| Derivatives (Notes 3 and 25) | **224** | 52 |
| Renewable energy surcharge <sup>(7)</sup> | **126** | 107 |
| Energy efficiency liability <sup>(8)</sup> | **89** | 83 |
| Other regulatory liabilities <sup>(6)</sup> | **203** | 162 |
| **Total regulatory liabilities** | **3915** | 3222 |
| **Less: Current portion** | **(595)** | (357) |
| **Long-term regulatory liabilities** | **3320** | 2865 |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Rate Stabilization and Related Accounts:* Rate stabilization accounts mitigate the earnings volatility otherwise caused by variability in the cost of fuel, purchased power and natural gas above or below a forecast or predetermined level, and by weather-driven volume variability. At certain utilities, revenue decoupling mechanisms minimize the earnings impact of reduced energy consumption as energy efficiency programs are implemented. Resultant deferrals are recovered from, or refunded to, customers in future rates as approved by the respective regulators.

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

<sup>(2)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;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 one to 10 years.

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

<sup>(4)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Deferred Restoration Costs:* Incremental costs incurred at Central Hudson and Maritime Electric associated with restoration activities due to significant weather events. Incremental costs incurred in excess of that collected in customer rates at Central Hudson are recovered through rate stabilization accounts. The form and recovery period for Maritime Electric will be determined by the regulator.

<sup>(5)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Generation Early Retirement Costs:* Includes costs at TEP associated with the retirement of the Navajo Generating Station ("Navajo") and Sundt Generating Facility Units 1 and 2 in 2019 and the San Juan Generating Station ("San Juan") in 2022, as approved for recovery by its regulator.

<sup>(6)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Other Regulatory Assets and Liabilities:* Comprised of regulatory assets and liabilities individually less than $40 million.

<sup>(7)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Renewable Energy Surcharge:* Under the ACC's Renewable Energy Standard ("RES"), UNS Energy is required to increase its use of renewable energy each year until it represents at least 15% of its total annual retail energy requirements by 2025. The cost of carrying out the plan is recovered from retail customers through a RES surcharge. Any RES surcharge collections above or below the costs incurred to implement the plans are deferred as a regulatory liability or asset.

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

<sup>(8)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;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.

Regulatory assets not earning a return: (i) totalled $1,980 million and $1,727 million as at December 31, 2022 and 2021, respectively; (ii) are primarily related to deferred income taxes and employee future benefits; and (iii) generally do not represent a past cash outlay as they are offset by related liabilities that, likewise, do not incur a carrying cost for rate-making purposes. Recovery periods vary or are yet to be determined by the respective regulators.

---

| | | |
|:---|:---|:---|
| **23** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**9. OTHER ASSETS** 

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Employee future benefits (Note 23) | **274** | 259 |
| Equity investments <sup>(1)</sup> | **201** | 92 |
| Supplemental Executive Retirement Plan ("SERP") | **155** | 165 |
| RECs (Note 8) | **142** | 112 |
| Derivatives | **118** | 40 |
| Other investments | **115** | 86 |
| Operating leases (Note 15) | **43** | 40 |
| Deferred compensation plan | **40** | 42 |
| Other | **125** | 119 |
|  | **1213** | 955 |

---

<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Includes investments in Belize Electricity and Wataynikaneyap Partnership*

ITC, UNS Energy and Central Hudson provide additional post-employment benefits through SERPs and deferred compensation plans for directors and officers. The assets held to support these plans are reported separately from the related liabilities (Note 16). Most plan assets are held in trust and funded mainly through life insurance policies and mutual funds. Assets in mutual and money market funds are recorded at fair value on a recurring basis (Note 25).

**10. PROPERTY, PLANT AND EQUIPMENT** 

---

| | | | |
|:---|:---|:---|:---|
| *($ millions)* | **Cost** | **Accumulated Depreciation** | **Net Book Value** |
| **2022** |  |  |  |
| Distribution |  |  |  |
| &nbsp;&nbsp;&nbsp;Electric | **13650** | **(3715)** | **9935** |
| &nbsp;&nbsp;&nbsp;Gas | **6396** | **(1626)** | **4770** |
| Transmission |  |  |  |
| &nbsp;&nbsp;&nbsp;Electric | **19056** | **(4074)** | **14982** |
| &nbsp;&nbsp;&nbsp;Gas | **2600** | **(800)** | **1800** |
| Generation | **7173** | **(2679)** | **4494** |
| Other | **4803** | **(1610)** | **3193** |
| Assets under construction | **2094** | **—** | **2094** |
| Land | **395** | **—** | **395** |
|  | **56167** | **(14504)** | **41663** |

---

---

| | | | |
|:---|:---|:---|:---|
| 2021 |  |  |  |
| Distribution |  |  |  |
| &nbsp;&nbsp;&nbsp;Electric | 12321 | (3359) | 8962 |
| &nbsp;&nbsp;&nbsp;Gas | 5838 | (1504) | 4334 |
| Transmission |  |  |  |
| &nbsp;&nbsp;&nbsp;Electric | 17104 | (3610) | 13494 |
| &nbsp;&nbsp;&nbsp;Gas | 2453 | (756) | 1697 |
| Generation | 7014 | (2691) | 4323 |
| Other | 4362 | (1454) | 2908 |
| Assets under construction | 1759 |  | 1759 |
| Land | 339 |  | 339 |
|  | 51190 | (13374) | 37816 |

---

---

| | | |
|:---|:---|:---|
| **24** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***10. PROPERTY, PLANT AND EQUIPMENT (cont'd)***

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 assets associated with natural gas storage at Aitken Creek.

As at December 31, 2022, assets under construction largely reflect ongoing transmission projects at ITC and UNS Energy.

The cost of PPE under finance lease as at December 31, 2022 was $323 million (2021 - $323 million) and related accumulated depreciation was $117 million (2021 - $113 million) (Note 15).

**Jointly Owned Facilities**

UNS Energy and ITC hold undivided interests in jointly owned generating facilities and transmission systems, are entitled to their pro rata share of the PPE, and are proportionately liable for the associated operating costs and liabilities. As at December 31, 2022, interests in jointly owned facilities consisted of the following.

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Ownership** | | **Accumulated** | **Net Book** |
| *($ millions, except as indicated)* | *(%)* | **Cost** | **Depreciation** | **Value** |
| Transmission Facilities | Various | **1333** | **(428)** | **905** |
| Springerville Common Facilities | 86.0 | **544** | **(294)** | **250** |
| Springerville Coal Handling Facilities | 83.0 | **281** | **(133)** | **148** |
| Four Corners Units 4 and 5 ("Four Corners") | 7.0 | **264** | **(119)** | **145** |
| Gila River Common Facilities | 50.0 | **118** | **(43)** | **75** |
| Luna Energy Facility ("Luna") | 33.3 | **77** | **—** | **77** |
|  |  | **2617** | **(1017)** | **1600** |

---

**11. INTANGIBLE ASSETS** 

---

| | | | |
|:---|:---|:---|:---|
| | | **Accumulated** | **Net Book** |
| *($ millions*) | **Cost** | **Amortization** | **Value** |
| **2022** |  |  |  |
| Computer software | **985** | **(497)** | **488** |
| Land, transmission and water rights | **1064** | **(171)** | **893** |
| Other | **135** | **(78)** | **57** |
| Assets under construction | **110** | **—** | **110** |
|  | **2294** | **(746)** | **1548** |

---

---

| | | | |
|:---|:---|:---|:---|
| 2021 |  |  |  |
| Computer software | 952 | (518) | 434 |
| Land, transmission and water rights | 941 | (154) | 787 |
| Other | 113 | (69) | 44 |
| Assets under construction | 78 |  | 78 |
|  | 2084 | (741) | 1343 |

---

Included in the cost of land, transmission and water rights as at December 31, 2022 was $117 million (2021 - $137 million) not subject to amortization. Amortization expense was $145 million for 2022 (2021 - $136 million). Amortization is estimated to average approximately $90 million for each of the next five years.

---

| | | |
|:---|:---|:---|
| **25** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**12. GOODWILL** 

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Balance, beginning of year | **11720** | 11792 |
| Foreign currency translation impacts <sup>(1)</sup> | **744** | (72) |
| Balance, end of year | **12464** | 11720 |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*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 U.S. dollar*

No goodwill impairment was recognized by the Corporation in 2022 or 2021.

**13. ACCOUNTS PAYABLE AND OTHER CURRENT LIABILITIES** 

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Trade accounts payable | **886** | 774 |
| Gas and fuel cost payable | **512** | 269 |
| Customer and other deposits | **401** | 288 |
| Accrued taxes other than income taxes | **282** | 238 |
| Dividends payable | **278** | 259 |
| Employee compensation and benefits payable | **270** | 283 |
| Interest payable | **254** | 218 |
| Derivatives (Note 25) | **127** | 43 |
| Income taxes payable | **88** | 31 |
| Employee future benefits (Note 23) | **28** | 26 |
| Manufactured gas plant site remediation (Note 16) | **17** | 13 |
| Other | **145** | 128 |
|  | **3288** | 2570 |

---

---

| | | |
|:---|:---|:---|
| **26** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**14. LONG-TERM DEBT** 

---

| | | | |
|:---|:---|:---|:---|
| *($ millions*) | Maturity Date | **2022** | 2021 |
| ***ITC*** |  |  |  |
| Secured U.S. First Mortgage Bonds - |  |  |  |
| 4.22% weighted average fixed rate (2021 - 4.31%) | 2024-2055 | **3344** | 2736 |
| Secured U.S. Senior Notes - |  |  |  |
| 3.83% weighted average fixed rate (2021 - 3.90%) | 2040-2055 | **1186** | 1011 |
| Unsecured U.S. Senior Notes - |  |  |  |
| 3.98% weighted average fixed rate (2021 - 3.61%) | 2023-2043 | **4541** | 4108 |
| Unsecured U.S. Shareholder Note - |  |  |  |
| 6.00% fixed rate (2021 - 6.00%) | 2028 | **270** | 252 |
| ***UNS Energy*** |  |  |  |
| Unsecured U.S. Tax-Exempt Bond - 4.00% weighted |  |  |  |
| average fixed rate (2021 - 4.34%) | 2029 | **123** | 359 |
| Unsecured U.S. Fixed Rate Notes - |  |  |  |
| 3.58% weighted average fixed rate (2021 - 3.62%) | 2023-2052 | **3450** | 2780 |
| ***Central Hudson*** |  |  |  |
| Unsecured U.S. Promissory Notes - 4.14% weighted |  |  |  |
| average fixed and variable rate (2021 - 3.83%) | 2024-2060 | **1526** | 1177 |
| ***FortisBC Energy*** |  |  |  |
| Unsecured Debentures - |  |  |  |
| 4.61% weighted average fixed rate (2021 - 4.61%) | 2026-2052 | **3295** | 3145 |
| ***FortisAlberta*** |  |  |  |
| Unsecured Debentures - |  |  |  |
| 4.49% weighted average fixed rate (2021 - 4.49%) | 2024-2052 | **2485** | 2360 |
| ***FortisBC Electric*** |  |  |  |
| Secured Debentures - |  |  |  |
| 8.80% fixed rate (2021 - 8.80%) | 2023 | **25** | 25 |
| Unsecured Debentures - |  |  |  |
| 4.70% weighted average fixed rate (2021 - 4.77%) | 2035-2052 | **860** | 760 |
| ***Other Electric*** |  |  |  |
| Secured First Mortgage Sinking Fund Bonds - |  |  |  |
| 5.26% weighted average fixed rate (2021 - 5.61%) | 2026-2060 | **666** | 627 |
| Secured First Mortgage Bonds - |  |  |  |
| 5.31% weighted average fixed rate (2021 - 5.31%) | 2025-2061 | **260** | 260 |
| Unsecured Senior Notes - |  |  |  |
| 4.45% weighted average fixed rate (2021 - 4.45%) | 2041-2048 | **152** | 152 |
| Unsecured U.S. Senior Loan Notes and Bonds - |  |  |  |
| 4.71% weighted average fixed and variable rate (2021 - 4.36%) | 2023-2052 | **745** | 609 |
| ***Corporate and Other*** |  |  |  |
| Unsecured U.S. Senior Notes and Promissory Notes - |  |  |  |
| 3.82% weighted average fixed rate (2021 - 3.82%) | 2023-2044 | **2691** | 2509 |
| Unsecured Debentures - |  |  |  |
| 6.51% fixed rate (2021 - 6.51%) | 2039 | **200** | 200 |
| Unsecured Senior Notes - |  |  |  |
| 3.31% weighted average fixed rate (2021 - 2.52%) | 2028-2029 | **1000** | 1000 |
| Long-term classification of credit facility borrowings | Long-term classification of credit facility borrowings | **1657** | 1305 |
| Fair value adjustment - ITC acquisition |  | **102** | 107 |
| Total long-term debt (Note 25) |  | **28578** | 25482 |
| Less: Deferred financing costs and debt discounts |  | **(166)** | (147) |
| Less: Current installments of long-term debt |  | **(2481)** | (1628) |
|  |  | **25931** | 23707 |

---

---

| | | |
|:---|:---|:---|
| **27** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***14. LONG-TERM DEBT (cont'd)***

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

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

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

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| **Long-Term Debt Issuances in 2022** | **Month Issued** | **Interest**<br>**Rate**<br>*(%)* | | **Maturity** | **Amount**<br>*($ millions)* | **Amount**<br>*($ millions)* | **Use of Proceeds** |
| ***ITC*** | | | | | | | |
| &nbsp;&nbsp;&nbsp;Secured first mortgage bonds | January | 2.93 |  | 2052 | **US** | **150** | <sup>(1) (2) (3) (4)</sup> |
| &nbsp;&nbsp;&nbsp;Secured senior notes | May | 3.05 |  | 2052 | **US** | **75** | <sup>(1) (3) (4)</sup> |
| &nbsp;&nbsp;&nbsp;Unsecured senior notes | September | 4.95 | <sup>(5)</sup> | 2027 | **US** | **600** | <sup>(1) (4) (6)</sup> |
| &nbsp;&nbsp;&nbsp;Secured first mortgage bonds | October | 3.87 |  | 2027 | **US** | **75** | <sup>(2)</sup> |
| &nbsp;&nbsp;&nbsp;Secured first mortgage bonds | October | 4.53 |  | 2052 | **US** | **75** | <sup>(2)</sup> |
| ***UNS Energy*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Unsecured senior notes | February | 3.25 |  | 2032 | **US** | **325** | <sup>(4) (6)</sup> |
| ***Central Hudson*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Unsecured senior notes | January | 2.37 |  | 2027 | **US** | **50** | <sup>(4) (6)</sup> |
| &nbsp;&nbsp;&nbsp;Unsecured senior notes | January | 2.59 |  | 2029 | **US** | **60** | <sup>(4) (6)</sup> |
| &nbsp;&nbsp;&nbsp;Unsecured senior notes | September | 5.07 |  | 2032 | **US** | **100** | <sup>(1) (4)</sup> |
| &nbsp;&nbsp;&nbsp;Unsecured senior notes | September | 5.42 |  | 2052 | **US** | **10** | <sup>(1) (4)</sup> |
| ***FortisBC Energy*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Unsecured debentures | November | 4.67 |  | 2052 | **150** | **150** | <sup>(2)</sup> |
| ***FortisAlberta*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Senior unsecured debentures | May | 4.62 |  | 2052 | **125** | **125** | <sup>(1)</sup> |
| ***FortisBC Electric*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Unsecured debentures | March | 4.16 |  | 2052 | **100** | **100** | <sup>(1)</sup> |
| ***Newfoundland Power*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;First mortgage sinking fund bonds | April | 4.20 |  | 2052 | **75** | **75** | <sup>(1) (4) (6)</sup> |
| ***Caribbean Utilities*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Unsecured senior notes | November | 5.88 |  | 2052 | **US** | **80** | <sup>(1) (3)</sup> |
| ***Fortis*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Unsecured senior notes | May | 4.43 | <sup>(7)</sup> | 2029 | **500** | **500** | <sup>(4) (8)</sup> |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Repay short-term and/or credit facility borrowings*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Fund or refinance, in part or in full, a portfolio of new and/or existing eligible green projects*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Fund capital expenditures*

<sup>(4)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*General corporate purposes*

<sup>(5)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;ITC entered into interest rate swaps which reduced the effective interest rate to 3.54%. See Note 25 to the 2022 Annual Financial Statements*

<sup>(6)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Repay maturing long-term debt*

<sup>(7)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*The Corporation entered into cross-currency interest rate swaps to effectively convert the debt into US$391 million with an interest rate of 4.34% (Note 25)*

<sup>(8)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Fund the June 2022 redemption of the Corporation's $500 million, 2.85% senior unsecured notes due December 2023*

**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.

---

| | |
|:---|:---|
| *($ millions)* | **Total** |
| 2023 | 2481 |
| 2024 | 1434 |
| 2025 | 518 |
| 2026 | 2434 |
| 2027 | 1977 |
| Thereafter | 19734 |
|  | 28578 |

---

---

| | | |
|:---|:---|:---|
| **28** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***14. LONG-TERM DEBT (cont'd)***

In November 2022, Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts, or debt securities in an aggregate principal amount of up to $2.0 billion. As at December 31, 2022, $2.0 billion remained available under the short-form base shelf prospectus.

**Credit Facilities**

---

| | | | | |
|:---|:---|:---|:---|:---|
| *($ millions)* | Regulated<br>Utilities | Corporate<br>and Other | **2022** | 2021 |
| Total credit facilities | 3795 | 2055 | **5850** | 4846 |
| Credit facilities utilized: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Short-term borrowings <sup>(1)</sup> | (253) |  | **(253)** | (247) |
| &nbsp;&nbsp;&nbsp;Long-term debt (including current portion) <sup>(2)</sup> | (922) | (735) | **(1657)** | (1305) |
| Letters of credit outstanding | (76) | (52) | **(128)** | (115) |
| **Credit facilities unutilized** | 2544 | 1268 | **3812** | 3179 |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*The weighted average interest rate was approximately 4.9% (2021 - 0.6%).*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*The weighted average interest rate was approximately 5.1% (2021 - 0.9%). The current portion was $1,376 million (2021 - $888 million).* 

Credit facilities are syndicated primarily with large banks in Canada and the U.S., with no one bank holding more than approximately 20% of the Corporation's total revolving credit facilities. Approximately $5.6 billion of the total credit facilities are committed facilities with maturities ranging from 2023 through 2027.

In 2022, Central Hudson increased its available credit facilities from US$230 million to US$320 million.

In May 2022, the Corporation amended its unsecured $1.3 billion revolving term committed credit facility agreement to extend the maturity to July 2027, and to establish a sustainability-linked loan structure based on the Corporation's achievement of targets for diversity on the Board of Directors and Scope 1 greenhouse gas emissions for 2022 through 2025. Maximum potential annual margin pricing adjustments are +/- 5 basis points and +/- 1 basis point for drawn and undrawn funds, respectively.

Also in May 2022, the Corporation entered into an unsecured US$500 million non-revolving term credit facility. The facility has an initial one-year term and is repayable at any time without penalty.

Consolidated credit facilities of approximately $5.9 billion as at December 31, 2022 are itemized below.

---

| | | |
|:---|:---|:---|
| *($ millions)* | **Amount** | **Maturity** |
| **Unsecured committed revolving credit facilities** |  |  |
| Regulated utilities |  |  |
| &nbsp;&nbsp;&nbsp;ITC <sup>(1)</sup> | **900** | 2024 |
| &nbsp;&nbsp;&nbsp;UNS Energy | **375** | 2026 |
| &nbsp;&nbsp;&nbsp;Central Hudson | **250** | 2025 |
| &nbsp;&nbsp;&nbsp;FortisBC Energy | **700** | 2027 |
| &nbsp;&nbsp;&nbsp;FortisAlberta | **250** | 2027 |
| &nbsp;&nbsp;&nbsp;FortisBC Electric | **150** | 2027 |
| &nbsp;&nbsp;&nbsp;Other Electric | **255** | <sup>(2)</sup> |
| &nbsp;&nbsp;&nbsp;Other Electric | **83** | 2025 |
| Corporate and Other | **1350** | <sup>(3)</sup> |
| **Other facilities** |  |  |
| Regulated utilities |  |  |
| &nbsp;&nbsp;&nbsp;Central Hudson - uncommitted credit facility | **70** | n/a |
| &nbsp;&nbsp;&nbsp;FortisBC Energy - uncommitted credit facility | **55** | 2024 |
| &nbsp;&nbsp;&nbsp;FortisBC Electric - unsecured demand overdraft facility | **10** | n/a |
| &nbsp;&nbsp;&nbsp;Other Electric - unsecured demand facilities | **20** | n/a |
| &nbsp;&nbsp;&nbsp;Other Electric - unsecured demand facility and emergency standby loan | **60** | 2023 |
| Corporate and Other |  |  |
| &nbsp;&nbsp;&nbsp;Unsecured non-revolving facility | **500** | 2023 |
| &nbsp;&nbsp;&nbsp;Unsecured non-revolving facility | **27** | n/a |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*ITC also has a US$400 million commercial paper program, under which US$134 million was outstanding as at December 31, 2022 (2021 - US$155 million), as reported in short-term borrowings.*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*$65 million in 2025, $90 million in 2025 and $100 million in 2027*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*$50 million in 2024 and $1.3 billion in 2027*

---

| | | |
|:---|:---|:---|
| **29** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**15. LEASES**

The Corporation and its subsidiaries lease office facilities, utility equipment, land, and communication tower space with remaining terms of up to 25 years, with optional renewal terms. Certain lease agreements include rental payments adjusted periodically for inflation or require the payment of real estate taxes, insurance, maintenance, or other operating expenses associated with the leased premises.

The Corporation's subsidiaries also have finance leases related to generating facilities with remaining terms of up to 33 years.

Leases were presented on the consolidated balance sheets as follows.

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| **Operating leases** |  |  |
| Other assets | **43** | 40 |
| Accounts payable and other current liabilities | **(9)** | (8) |
| Other liabilities | **(34)** | (32) |
| **Finance leases** <sup>(1)</sup> |  |  |
| Regulatory assets | **132** | 127 |
| PPE, net | **206** | 210 |
| Accounts payable and other current liabilities | **(2)** | (4) |
| Finance leases | **(336)** | (333) |

---

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

The components of lease expense were as follows*.*

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Operating lease cost | **9** | 8 |
| Finance lease cost: |  |  |
| &nbsp;&nbsp;&nbsp;Amortization | **1** | 2 |
| &nbsp;&nbsp;&nbsp;Interest | **33** | 32 |
| Variable lease cost | **21** | 19 |
| **Total lease cost** | **64** | 61 |

---

As at December 31, 2022, the present value of minimum lease payments was as follows.

---

| | | | |
|:---|:---|:---|:---|
| *($ millions)* | Operating<br>Leases | Finance<br>Leases | **Total** |
| 2023 | 10 | 35 | **45** |
| 2024 | 9 | 35 | **44** |
| 2025 | 6 | 35 | **41** |
| 2026 | 5 | 35 | **40** |
| 2027 | 3 | 36 | **39** |
| Thereafter | 19 | 1001 | **1020** |
|  | 52 | 1177 | **1229** |
| Less: Imputed interest | (9) | (839) | **(848)** |
| Total lease obligations | 43 | 338 | **381** |
| Less: Current installments | (9) | (2) | **(11)** |
|  | 34 | 336 | **370** |

---

---

| | | |
|:---|:---|:---|
| **30** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***15. LEASES (cont'd)***

---

| | | |
|:---|:---|:---|
| Supplemental lease information follows. |  |  |
| *($ millions, except as indicated)* | **2022** | 2021 |
| **Weighted average remaining lease term** *(years)*  |  |  |
| Operating leases | **9** | 10 |
| Finance leases | **33** | 34 |
| **Weighted average discount rate** *(%)*  |  |  |
| Operating leases | **4.1** | 3.8 |
| Finance leases | **5.0** | 5.1 |
| **Cash payments related to lease liabilities** |  |  |
| Operating cash flows used for operating leases | **(8)** | (8) |
| Financing cash flows used for finance leases | **(1)** | (2) |

---

**16. OTHER LIABILITIES**

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Employee future benefits (Note 23) | **423** | 740 |
| AROs (Note 3) | **174** | 184 |
| Customer and other deposits | **107** | 99 |
| Manufactured gas plant site remediation <sup>(1)</sup> | **95** | 83 |
| Stock-based compensation plans (Note 20) | **79** | 96 |
| Derivatives (Note 25) | **72** | 7 |
| Deferred compensation plan (Note 9) | **48** | 50 |
| Mine reclamation obligations <sup>(2)</sup> | **39** | 44 |
| Operating leases (Note 15) | **34** | 32 |
| Retail energy contract <sup>(3)</sup> | **33** | 40 |
| Other | **42** | 34 |
|  | **1146** | 1409 |

---

<sup>(1)</sup> <sup>&nbsp;&nbsp;&nbsp;&nbsp;</sup>Environmental regulations require Central Hudson to investigate sites at which it or its predecessors once owned and/or operated manufactured gas plants and, if necessary, remediate those sites. Costs are accrued based on the amounts that can be reasonably estimated. As at December 31, 2022, an obligation of $100 million was recognized, including a current portion of $5 million recognized in accounts payable and other current liabilities (Note 13). Central Hudson has notified its insurers that it intends to seek reimbursement where insurance coverage exists. Differences between actual costs and the associated rate allowances are deferred as a regulatory asset for future recovery (Note 8).

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>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 $54 million. The present value of the estimated future liability is shown in the table above.

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>In 2020, FortisAlberta entered into an eight-year agreement with an existing retail energy provider to continue to act as its default retailer to eligible customers under the regulated retail option. As part of this agreement FortisAlberta received an upfront payment which is being amortized to revenue over the life of the agreement.

---

| | | |
|:---|:---|:---|
| **31** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**17. EARNINGS PER COMMON SHARE** 

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

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| | **2022** | **2022** | **2022** | 2021 | 2021 | 2021 |
| | **Net Earnings** | **Weighted** | | Net Earnings | Weighted | |
| | **to Common** | **Average** | | to Common | Average | |
| | **Shareholders** | **Shares** | **EPS** | Shareholders | Shares | EPS |
|  | *($ millions)* | *(# millions)* | *($)* | *($ millions)* | *(# millions)* | *($)* |
| **Basic EPS** | **1330** | **478.6** | **2.78** | 1231 | 470.9 | 2.61 |
| Potential dilutive effect of stock options | **—** | **0.4** | **—** |  | 0.5 |  |
| **Diluted EPS** | **1330** | **479.0** | **2.78** | 1231 | 471.4 | 2.61 |

---

**18. PREFERENCE SHARES** 

**Authorized**

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

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Issued and Outstanding** | **2022** | **2022** | 2021 | 2021 |
| **First Preference Shares** | **Number** |  | Number |  |
| **First Preference Shares** | **of Shares** | **Amount** | of Shares | Amount |
| **First Preference Shares** | *(thousands)* | *($ millions)* | *(thousands)* | *($ millions)* |
| Series F | **5000** | **122** | 5000 | 122 |
| Series G | **9200** | **225** | 9200 | 225 |
| Series H | **7665** | **188** | 7665 | 188 |
| Series I | **2335** | **57** | 2335 | 57 |
| Series J | **8000** | **196** | 8000 | 196 |
| Series K | **10000** | **244** | 10000 | 244 |
| Series M | **24000** | **591** | 24000 | 591 |
|  | **66200** | **1623** | 66200 | 1623 |

---

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Characteristics of the first preference shares are as follows.** | **Characteristics of the first preference shares are as follows.** | | **Reset** | | | **Right to** |
| | **Initial** | **Annual** | **Dividend** | **Redemption** | **Redemption** | **Convert on** |
| | **Yield** | **Dividend** | **Yield** | **and/or Conversion** | **Value** | **a One-For-** |
| **First Preference Shares** <sup>(1) (2)</sup> | *(%)* | *($)* | *(%)* | **Option Date** | *($)* | **One Basis** |
| Perpetual fixed rate |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Series F | 4.90 | 1.2250 |  | Currently Redeemable | 25.00 |  |
| &nbsp;&nbsp;&nbsp;Series J | 4.75 | 1.1875 |  | Currently Redeemable | 25.00 |  |
| Fixed rate reset <sup>(3) (4)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Series G | 5.25 | 1.0983 | 2.13 | September 1, 2023 | 25.00 |  |
| &nbsp;&nbsp;&nbsp;Series H | 4.25 | 0.4588 | 1.45 | June 1, 2025 | 25.00 | Series I |
| &nbsp;&nbsp;&nbsp;Series K | 4.00 | 0.9823 | 2.05 | March 1, 2024 | 25.00 | Series L |
| &nbsp;&nbsp;&nbsp;Series M | 4.10 | 0.9783 | 2.48 | December 1, 2024 | 25.00 | Series N |
| Floating rate reset <sup>(4) (5)</sup> |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;Series I | 2.10 |  | 1.45 | June 1, 2025 | 25.00 | Series H |
| &nbsp;&nbsp;&nbsp;Series L |  |  |  |  |  | Series K |
| &nbsp;&nbsp;&nbsp;Series N |  |  |  |  |  | Series M |

---

<sup>(1</sup><sup>)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*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.* 

<sup>(2)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;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.*

<sup>(3)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;On the redemption and/or conversion option date, and on each five-year anniversary thereafter, the reset annual dividend per share will be determined by multiplying $25.00 per share by the annual fixed dividend rate, which is the sum of the five-year Government of Canada Bond Yield on the applicable reset date, plus the applicable reset dividend yield.*

<sup>(4)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;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.* 

<sup>(5)</sup> &nbsp;&nbsp;&nbsp;&nbsp;*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.*

---

| | | |
|:---|:---|:---|
| **32** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**18. PREFERENCE SHARES *(cont'd)***

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.

**19. ACCUMULATED OTHER COMPREHENSIVE INCOME** 

---

| | | | |
|:---|:---|:---|:---|
| *($ millions)* | **Opening Balance** | **Net Change** | **Ending Balance** |
| **2022** |  |  |  |
| **Unrealized foreign currency translation gains (losses)** |  |  |  |
| Net investments in foreign operations | **273** | **1222** | **1495** |
| Hedges of net investments in foreign operations | **(276)** | **(254)** | **(530)** |
| Income tax (expense) recovery | **(8)** | **15** | **7** |
|  | **(11)** | **983** | **972** |
| **Other** |  |  |  |
| Interest rate hedges (Note 25) | **(5)** | **54** | **49** |
| Unrealized employee future benefits (losses) gains (Note 23) | **(36)** | **30** | **(6)** |
| Income tax recovery (expense) | **12** | **(19)** | **(7)** |
|  | **(29)** | **65** | **36** |
| **Accumulated other comprehensive income** | **(40)** | **1048** | **1008** |
| 2021 |  |  |  |
| **Unrealized foreign currency translation gains (losses)** |  |  |  |
| Net investments in foreign operations | 377 | (104) | 273 |
| Hedges of net investments in foreign operations | (299) | 23 | (276) |
| Income tax expense | (6) | (2) | (8) |
|  | 72 | (83) | (11) |
| **Other** |  |  |  |
| Interest rate hedges (Note 25) | (4) | (1) | (5) |
| Unrealized employee future benefits (losses) gains (Note 23) | (49) | 13 | (36) |
| Income tax recovery (expense) | 15 | (3) | 12 |
|  | (38) | 9 | (29) |
| **Accumulated other comprehensive income** | 34 | (74) | (40) |

---

20. STOCK-BASED COMPENSATION PLANS

**Stock Options**

Effective 2022, the Corporation no longer grants stock options. Existing options to purchase common shares of the Corporation are exercisable for a period of 10 years from the grant date, expire no later than three years after the death or retirement of the optionee, and vest evenly over a four-year period on each anniversary of the grant date.

As at December 31, 2022, the Corporation had 2.3 million (2021 - 2.9 million) stock options outstanding with a weighted average exercise price of $47.72 (2021 - $47.20). The options vested as of December 31, 2022, were 1.5 million (2021 – 1.4 million) with a weighted average exercise price of $44.86 (2021 - $42.76).

In 2022, 1 million stock options were exercised (2021 - 1 million) for cash proceeds of $26 million (2021 - $32 million) and an intrinsic value realized by employees of $9 million (2021 - $11 million).

---

| | | |
|:---|:---|:---|
| **33** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***20. STOCK-BASED COMPENSATION PLANS (cont'd)***

**DSU Plan**

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

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

The following table summarizes information related to DSUs.

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Number of units** *(thousands)* | | |
| Beginning of year | **183** | 147 |
| Granted | **33** | 30 |
| Notional dividends reinvested | **8** | 6 |
| End of year | **224** | 183 |

---

The accrued liability has been recognized at the respective December 31<sup>st</sup> VWAP (Note 3) and included in other liabilities (Note 16). The accrued liability, compensation expense and cash payout were not material for 2022 or 2021.

**PSU Plans**

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

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

The payout percentage is based on the Corporation's performance over the three-year vesting period, mainly determined by: (i) the Corporation's total shareholder return as compared to a predefined peer group of companies; and (ii) the Corporation's cumulative EPS, or for subsidiaries the Company's cumulative net income, as compared to the target established at the time of the grant. Beginning with the 2022 PSU grant, the Corporation's Scope 1 carbon reduction performance as compared to the target established at the time of the grant has been included in the payout percentage.

The following table summarizes information related to PSUs.

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Number of units** *(thousands)* |  |  |
| Beginning of year | **1898** | 1976 |
| Granted | **580** | 587 |
| Notional dividends reinvested | **58** | 60 |
| Paid out | **(712)** | (697) |
| Cancelled/forfeited | **(34)** | (28) |
| End of year | **1790** | 1898 |
| **Additional information** *($ millions)* |  |  |
| Compensation expense recognized | **25** | 74 |
| Compensation expense unrecognized <sup>(1)</sup> | **24** | 33 |
| Cash payout | **66** | 50 |
| Accrued liability as at December 31 <sup>(2)</sup> | **90** | 132 |
| Aggregate intrinsic value as at December 31 <sup>(3)</sup> | **114** | 165 |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Relates to unvested PSUs and is expected to be recognized over a weighted average period of two years*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Recognized at the respective December 31*<sup>st</sup> *VWAP and included in accounts payable and other current liabilities and in other liabilities (Notes 13 and 16)*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Relates to outstanding PSUs and reflects a weighted average contractual life of one year*

---

| | | |
|:---|:---|:---|
| **34** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***20. STOCK-BASED COMPENSATION PLANS (cont'd)***

**RSU Plans**

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

Each RSU vests over a three-year period or immediately upon retirement eligibility of the holder, has an underlying value equivalent to that of one common share of the Corporation, is entitled to commensurate notional common share dividends, and is settled in cash or, beginning with the 2020 grant, common shares of the Corporation. Effective January 1, 2020, new RSU issuances may be settled in cash, common shares, or an equal proportion of cash and common shares depending on an executives' settlement election and whether their share ownership requirements have been met.

The following table summarizes information related to RSUs.

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Number of units** *(thousands)* |  |  |
| Beginning of year | **1060** | 1048 |
| Granted | **331** | 378 |
| Notional dividends reinvested | **29** | 32 |
| Paid out | **(410)** | (371) |
| Cancelled/forfeited | **(33)** | (27) |
| End of year | **977** | 1060 |
| **Additional information** *($ millions)* |  |  |
| Compensation expense recognized | **16** | 26 |
| Compensation expense unrecognized <sup>(1)</sup> | **16** | 17 |
| Cash payout | **25** | 21 |
| Accrued liability as at December 31 <sup>(2)</sup> | **40** | 46 |
| Aggregate intrinsic value as at December 31 <sup>(3)</sup> | **56** | 63 |

---

<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Relates to unvested RSUs and is expected to be recognized over a weighted average period of two years*

<sup>(2)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Recognized at the respective December 31*<sup>st</sup> *VWAP and included in accounts payable and other current liabilities and in long-term other liabilities (Notes 13 and 16)*

<sup>(3)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Relates to outstanding RSUs and reflects a weighted average contractual life of one year* 

**21. OTHER INCOME, NET**

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Non-service component of net periodic benefit cost | **92** | 45 |
| Equity component of AFUDC | **78** | 77 |
| Interest income | **11** | 5 |
| (Loss) gain on derivatives, net | **(17)** | 30 |
| (Loss) gain on retirement investments, net | **(18)** | 4 |
| Other | **19** | 12 |
|  | **165** | 173 |

---

---

| | | |
|:---|:---|:---|
| **35** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**22. INCOME TAXES** 

**Deferred Income Tax Assets and Liabilities**

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

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| **Gross deferred income tax assets** |  |  |
| Regulatory liabilities | **674** | 560 |
| Tax loss and credit carryforwards | **658** | 556 |
| Employee future benefits | **161** | 169 |
| Other | **160** | 91 |
|  | **1653** | 1376 |
| Valuation allowance | **(32)** | (23) |
| **Net deferred income tax asset** | **1621** | 1353 |
| **Gross deferred income tax liabilities** |  |  |
| PPE | **(5146)** | (4571) |
| Regulatory assets | **(388)** | (283) |
| Intangible assets | **(147)** | (126) |
|  | **(5681)** | (4980) |
| **Net deferred income tax liability** | **(4060)** | (3627) |

---

**Income Tax Expense**

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| **Canadian** |  |  |
| Earnings before income tax expense | **447** | 427 |
| Current income tax | **93** | 84 |
| Deferred income tax | **(41)** | (35) |
| Total Canadian | **52** | 49 |
| **Foreign** |  |  |
| Earnings before income tax expense | **1356** | 1212 |
| Current income tax | **14** | 3 |
| Deferred income tax | **223** | 182 |
| Total Foreign | **237** | 185 |
| **Income tax expense** | **289** | 234 |

---

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.

---

| | | |
|:---|:---|:---|
| **36** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***22. INCOME TAXES (cont'd)***

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

---

| | | |
|:---|:---|:---|
| *($ millions, except as indicated)* | **2022** | 2021 |
| Earnings before income tax expense | **1803** | 1639 |
| Combined Canadian federal and provincial statutory income tax rate *(%)* | **30.0** | 30.0 |
| Expected federal and provincial taxes at statutory rate | **541** | 492 |
| Decrease resulting from: |  |  |
| &nbsp;&nbsp;&nbsp;Foreign and other statutory rate differentials | **(162)** | (155) |
| &nbsp;&nbsp;&nbsp;AFUDC | **(18)** | (16) |
| &nbsp;&nbsp;&nbsp;Effects of rate-regulated accounting: |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Difference between depreciation claimed for income tax and accounting purposes | **(74)** | (74) |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Items capitalized for accounting purposes but expensed for income tax purposes | **(7)** | (8) |
| &nbsp;&nbsp;&nbsp;Other | **9** | (5) |
| **Income tax expense** | **289** | 234 |
| **Effective tax rate** *(%)* | **16.0** | 14.3 |

---

---

| | | |
|:---|:---|:---|
| Income Tax Carryforwards |  |  |
| *($ millions)* | Expiring Year | **2022** |
| **Canadian** |  |  |
| Non-capital loss | 2028-2042 | **393** |
| **Foreign** |  |  |
| Federal and state net operating loss<sup>(1)</sup> | 2023-2042 | **3093** |
| Other tax credits | 2023-2042 | **131** |
|  |  | **3224** |
| **Total income tax carryforwards recognized** |  | **3617** |

---

<sup>(1)</sup> *Indefinite carryforward for Federal net operating losses, and for states that have adopted the Federal provisions, effective for tax years beginning after December 31, 2017*

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, British Columbia and Alberta). The Corporation's 2018 to 2022 taxation years are still open for audit in Canadian jurisdictions, and its 2018 to 2022 taxation years are still open for audit in United States jurisdictions.

**23. EMPLOYEE FUTURE BENEFITS**

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

For the Corporation's Canadian and Caribbean subsidiaries, actuarial valuations to determine funding contributions for pension plans are required at least every three years. The most recent valuations were as of December 31, 2019 for FortisBC Electric plans (non-unionized employees), Newfoundland Power, FortisAlberta and FortisOntario; December 31, 2020 for the Corporation; December 31, 2021 for FortisBC Energy and the remaining FortisBC Electric plans and December 31, 2022 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.

---

| | | |
|:---|:---|:---|
| **37** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***23. EMPLOYEE FUTURE BENEFITS (cont'd)***

---

| | | | |
|:---|:---|:---|:---|
| **Allocation of Plan Assets** | **2022 Target Allocation** | | |
| *(weighted average %)* | **2022 Target Allocation** | **2022** | 2021 |
| Equities | **47** | **48** | 48 |
| Fixed income | **46** | **43** | 45 |
| Real estate | **6** | **8** | 6 |
| Cash and other | **1** | **1** | 1 |
|  | **100** | **100** | 100 |

---

**Fair Value of Plan Assets**

---

| | | | | |
|:---|:---|:---|:---|:---|
| *($ millions)* | **Level 1** <sup>(1)</sup> | **Level 2** <sup>(1)</sup> | **Level 3** <sup>(1)</sup> | **Total** |
| **2022** |  |  |  |  |
| Equities | **666** | **1005** | **—** | **1671** |
| Fixed income | **199** | **1289** | **—** | **1488** |
| Real estate | **—** | **—** | **264** | **264** |
| Private equities | **—** | **—** | **18** | **18** |
| Cash and other | **5** | **22** | **—** | **27** |
|  | **870** | **2316** | **282** | **3468** |
| 2021 |  |  |  |  |
| Equities | 749 | 1271 |  | 2020 |
| Fixed income | 219 | 1642 |  | 1861 |
| Real estate |  |  | 235 | 235 |
| Private equities |  |  | 21 | 21 |
| Cash and other | 10 | 15 |  | 25 |
|  | 978 | 2928 | 256 | 4162 |

---

<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;See Note 25 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.

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| Balance, beginning of year | **256** | 224 |
| Return on plan assets | **28** | 32 |
| Foreign currency translation | **3** |  |
| Purchases, sales and settlements | **(5)** |  |
| Balance, end of year | **282** | 256 |

---

---

| | | |
|:---|:---|:---|
| **38** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***23. EMPLOYEE FUTURE BENEFITS (cont'd)***

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Funded Status** | **Defined Benefit<br>Pension Plans** | **Defined Benefit<br>Pension Plans** | **OPEB Plans** | **OPEB Plans** |
| *($ millions)* | **2022** | 2021 | **2022** | 2021 |
| **Change in benefit obligation** <sup>(1)</sup> |  |  |  |  |
| Balance, beginning of year | **3922** | 3995 | **747** | 789 |
| Service costs | **106** | 109 | **35** | 35 |
| Employee contributions | **18** | 18 | **3** | 2 |
| Interest costs | **114** | 98 | **21** | 19 |
| Benefits paid | **(195)** | (170) | **(29)** | (25) |
| Actuarial gains | **(1026)** | (111) | **(225)** | (70) |
| Past service costs (credits)/plan amendments | **—** | (2) | **1** |  |
| Foreign currency translation | **124** | (15) | **29** | (3) |
| Balance, end of year <sup>(2)</sup> | **3063** | 3922 | **582** | 747 |
| **Change in value of plan assets** |  |  |  |  |
| Balance, beginning of year | **3722** | 3528 | **440** | 391 |
| Actual return on plan assets | **(651)** | 291 | **(77)** | 48 |
| Benefits paid | **(187)** | (158) | **(24)** | (21) |
| Employee contributions | **18** | 18 | **3** | 2 |
| Employer contributions | **54** | 55 | **19** | 22 |
| Foreign currency translation | **123** | (12) | **28** | (2) |
| Balance, end of year | **3079** | 3722 | **389** | 440 |
| **Funded status** | **16** | (200) | **(193)** | (307) |
| **Balance sheet presentation** |  |  |  |  |
| Other assets (Note 9) | **188** | 204 | **86** | 55 |
| Other current liabilities (Note 13) | **(15)** | (13) | **(13)** | (13) |
| Other liabilities (Note 16) | **(157)** | (391) | **(266)** | (349) |
|  | **16** | (200) | **(193)** | (307) |

---

<sup>(1)</sup> *Amounts reflect projected benefit obligation for defined benefit pension plans and accumulated benefit obligation for OPEB plans.*

<sup>(2)</sup> *The accumulated benefit obligation, which excludes assumptions about future salary levels, for defined benefit pension plans was $2,818 million as at December 31, 2022 (2021 - $3,586 million).*

For those defined benefit pension plans for which the projected benefit obligation exceeded the fair value of plan assets as at December 31, 2022, the obligation was $978 million compared to plan assets of $790 million (2021 - $2,188 million and $1,799 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, 2022, the obligation was $833 million compared to plan assets of $790 million (2021 - $1,243 million and $1,063 million, respectively).

For those OPEB plans for which the accumulated benefit obligation exceeded the fair value of plan assets as at December 31, 2022, the obligation was $310 million compared to plan assets of $31 million (2021 - $398 million and $36 million, respectively).

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Net Benefit Cost** <sup>(1)</sup> | **Defined Benefit<br>Pension Plans** | **Defined Benefit<br>Pension Plans** | **OPEB Plans** | **OPEB Plans** |
| *($ millions)* | **2022** | 2021 | **2022** | 2021 |
| Service costs | **106** | 109 | **35** | 35 |
| Interest costs | **114** | 98 | **21** | 19 |
| Expected return on plan assets | **(194)** | (177) | **(23)** | (19) |
| Amortization of actuarial losses (gains) | **4** | 36 | **(10)** | (2) |
| Amortization of past service credits/plan amendments | **(1)** | (1) | **(1)** | (1) |
| Regulatory adjustments | **(10)** | (1) | **4** | 3 |
|  | **19** | 64 | **26** | 35 |

---

<sup>(1)</sup> &nbsp;&nbsp;&nbsp;&nbsp;*The non-service benefit cost components of net periodic benefit cost are included in other income, net in the consolidated statements of earnings.*

---

| | | |
|:---|:---|:---|
| **39** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***23. EMPLOYEE FUTURE BENEFITS (cont'd)***

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>Pension Plans** | **Defined Benefit<br>Pension Plans** | **OPEB Plans** | **OPEB Plans** |
| *($ millions)* | **2022** | 2021 | **2022** | 2021 |
| Unamortized net actuarial losses (gains) | **9** | 33 | **(11)** | (5) |
| Unamortized past service costs | **1** | 1 | **7** | 7 |
| Income tax (recovery) expense | **(2)** | (8) | **1** |  |
| **Accumulated other comprehensive income** | **8** | 26 | **(3)** | 2 |
| Net actuarial losses (gains) | **103** | 260 | **(195)** | (81) |
| Past service credits | **(4)** | (5) | **(4)** | (6) |
| Other regulatory deferrals | **(6)** | 10 | **7** | 14 |
|  | **93** | 265 | **(192)** | (73) |
| Regulatory assets (Note 8) | **207** | 376 | **—** | 12 |
| Regulatory liabilities (Note 8) | **(114)** | (111) | **(192)** | (85) |
| **Net regulatory assets (liabilities)** | **93** | 265 | **(192)** | (73) |

---

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

---

| | | | | |
|:---|:---|:---|:---|:---|
| | **Defined Benefit<br>Pension Plans** | **Defined Benefit<br>Pension Plans** | **OPEB Plans** | **OPEB Plans** |
| *($ millions)* | **2022** | 2021 | **2022** | 2021 |
| Current year net actuarial gains | **(23)** | (10) | **(6)** | (4) |
| Amortization of actuarial losses | **1** | 1 | **—** |  |
| Foreign currency translation | **(2)** |  | **—** |  |
| Income tax expense | **6** | 2 | **1** | 1 |
| **Total recognized in comprehensive income** | **(18)** | (7) | **(5)** | (3) |
| Current year net actuarial gains | **(155)** | (220) | **(118)** | (95) |
| Past service cost/plan amendments | **—** |  | **1** |  |
| Amortization of actuarial (losses) gains | **(6)** | (35) | **10** | 2 |
| Amortization of past service credits | **1** | 2 | **1** | 2 |
| Foreign currency translation | **4** | (2) | **(6)** |  |
| Regulatory adjustments | **(16)** | (3) | **(7)** | (4) |
| **Total recognized in regulatory liabilities** | **(172)** | (258) | **(119)** | (95) |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Significant Assumptions** | **Defined Benefit<br>Pension Plans** | **Defined Benefit<br>Pension Plans** | **OPEB Plans** | **OPEB Plans** |
| *(weighted average %)* | **2022** | 2021 | **2022** | 2021 |
| Discount rate during the year <sup>(1)</sup> | **2.97** | 2.60 | **2.97** | 2.60 |
| Discount rate as at December 31 | **5.27** | 3.00 | **5.36** | 2.97 |
| Expected long-term rate of return on plan assets <sup>(2)</sup> | **5.87** | 5.40 | **5.00** | 4.88 |
| Rate of compensation increase | **3.33** | 3.30 | **—** |  |
| Health care cost trend increase as at December 31 <sup>(3)</sup> | **—** |  | **4.48** | 4.49 |

---

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

<sup>(2)</sup> *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.*

<sup>(3)</sup> *The projected 2023 weighted average health care cost trend rate is 6.17% and is assumed to decrease over the next 12 years to the weighted average ultimate health care cost trend rate of 4.48% in 2034 and thereafter.*

---

| | | |
|:---|:---|:---|
| **40** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***23. EMPLOYEE FUTURE BENEFITS (cont'd)***

---

| | | |
|:---|:---|:---|
| **Expected Benefit Payments** | **Defined Benefit** | **OPEB** |
| *($ millions)* | **Pension Payments** | **Payments** |
| 2023 | $177 | $30 |
| 2024 | 183 | 32 |
| 2025 | 190 | 33 |
| 2026 | 197 | 35 |
| 2027 | 203 | 35 |
| 2028-2032 | 1094 | 191 |

---

During 2023, the Corporation expects to contribute $35 million for defined benefit pension plans and $20 million for OPEB plans.

In 2022, the Corporation expensed $47 million (2021 - $44 million) related to defined contribution pension plans.

**24. SUPPLEMENTARY CASH FLOW INFORMATION** 

---

| | | |
|:---|:---|:---|
| *($ millions)* | **2022** | 2021 |
| **Cash paid (received) for** |  |  |
| Interest | **1057** | 986 |
| Income taxes | **79** | (13) |
| **Change in working capital** |  |  |
| Accounts receivable and other current assets | **(479)** | (88) |
| Prepaid expenses | **(22)** | (15) |
| Inventories | **(153)** | (56) |
| Regulatory assets - current portion | **(307)** | (99) |
| Accounts payable and other current liabilities | **449** | 164 |
| Regulatory liabilities - current portion | **33** | (50) |
|  | **(479)** | (144) |
| **Non-cash investing and financing activities** |  |  |
| Accrued capital expenditures | **411** | 432 |
| Common share dividends reinvested | **364** | 356 |
| Contributions in aid of construction | **13** | 13 |

---

**25. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT** 

**Derivatives**

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

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

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

*Energy Contracts Subject to Regulatory Deferral*

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

---

| | | |
|:---|:---|:---|
| **41** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***25. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)***

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

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

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, 2022, unrealized losses of $84 million (2021 - $20 million) were recognized as regulatory assets and unrealized gains of $224 million (2021 - $52 million) were recognized as regulatory liabilities.

*Energy Contracts Not Subject to Regulatory Deferral* 

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

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

Unrealized gains or losses associated with changes in the fair value of these energy contracts are recognized in revenue. In 2022, unrealized gains of $34 million (2021 - $21 million) were recognized in revenue.

*Total Return Swaps* 

The Corporation holds total return swaps to manage the cash flow risk associated with forecast future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $114 million and terms of one to three years expiring at varying dates through January 2025. Fair value is measured using an income valuation approach based on forward pricing curves. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. In 2022, unrealized losses of $22 million (2021 - unrealized gains of $17 million) were recognized in other income, net.

*Foreign Exchange Contracts* 

The Corporation holds U.S. dollar-denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The contracts expire at varying dates through May 2024 and have a combined notional amount of $352 million. Fair value was measured using independent third-party information. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. In 2022, unrealized losses of $9 million (2021 - $11 million) were recognized in other income, net.

*Interest Rate Swaps*

ITC entered into forward-starting interest rate swaps to manage the interest rate risk associated with planned borrowings. The swaps, which had a combined notional value of US$450 million, were terminated in September 2022 with the issuance of US$600 million senior notes and realized gains of $52 million (US$39 million) were recognized in other comprehensive income, which will be reclassified to earnings as a component of interest expense over five years.

*Cross-Currency Interest Rate Swaps*

In May 2022, the Corporation entered into cross-currency interest rate swaps with a 7-year term to effectively convert its $500 million, 4.43% unsecured senior notes to US$391 million, 4.34% debt (Note 14). The Corporation designated this notional U.S. debt as an effective hedge of its foreign net investments and unrealized gains and losses associated with exchange rate fluctuations on the notional U.S. debt are recognized in other comprehensive income, consistent with the translation adjustment related to the net investments. Other changes in the fair value of the swaps are also recognized in other comprehensive income but are excluded from the assessment of hedge effectiveness. Fair value is measured using a discounted cash flow method based on secured overnight financing rates. In 2022, unrealized losses of $17 million were recorded in other comprehensive income.

*Other Investments*

UNS Energy holds investments in money market accounts, and ITC and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees, which include mutual funds and money market accounts. These investments are recorded at fair value based on quoted market prices in active markets. Gains and losses are recognized in other income, net. In 2022, unrealized losses of $11 million (2021 - unrealized gains of $5 million) were recognized in other income, net.

---

| | | |
|:---|:---|:---|
| **42** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***25. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)***

**Recurring Fair Value Measures**

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

---

| | | | | |
|:---|:---|:---|:---|:---|
| *($ millions)* | **Level 1** <sup>(1)</sup> | **Level 2** <sup>(1)</sup> | **Level 3** <sup>(1)</sup> | **Total** |
| **As at December 31, 2022** |  |  |  |  |
| **Assets** |  |  |  |  |
| Energy contracts subject to regulatory deferral <sup>(2) (3)</sup> | **—** | **304** | **—** | **304** |
| Energy contracts not subject to regulatory deferral <sup>(2)</sup> | **—** | **49** | **—** | **49** |
| Other investments <sup>(4)</sup> | **150** | **—** | **—** | **150** |
|  | **150** | **353** | **—** | **503** |
| **Liabilities** |  |  |  |  |
| Energy contracts subject to regulatory deferral <sup>(3) (5)</sup> | **—** | **(164)** | **—** | **(164)** |
| Energy contracts not subject to regulatory deferral <sup>(5)</sup> | **—** | **(8)** | **—** | **(8)** |
| Foreign exchange contracts, total return and cross-currency interest rate swaps <sup>(5)</sup> | **—** | **(26)** | **—** | **(26)** |
|  | **—** | **(198)** | **—** | **(198)** |

---

---

| | | | |
|:---|:---|:---|:---|
| As at December 31, 2021 |  |  |  |
| **Assets** |  |  |  |
| Energy contracts subject to regulatory deferral <sup>(2) (3)</sup> |  | 78 | 78 |
| Energy contracts not subject to regulatory deferral <sup>(2)</sup> |  | 16 | 16 |
| Foreign exchange contracts, total return and interest rate swaps <sup>(2)</sup> | 23 | 2 | 25 |
| Other investments <sup>(4)</sup> | 137 |  | 137 |
|  | 160 | 96 | 256 |
| **Liabilities** |  |  |  |
| Energy contracts subject to regulatory deferral <sup>(3) (5)</sup> |  | (46) | (46) |
| Energy contracts not subject to regulatory deferral <sup>(5)</sup> |  | (3) | (3) |
|  |  | (49) | (49) |

---

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

<sup>(2)</sup> *Included in accounts receivable and other current assets or other assets*

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

<sup>(4)</sup> *Included in cash and cash equivalents and other assets*

<sup>(5)</sup> *Included in accounts payable and other current liabilities or other liabilities*

**Energy Contracts**

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

---

| | | | | |
|:---|:---|:---|:---|:---|
| *($ millions)* | **Gross Amount<br>Recognized In<br>Balance Sheet** | **Counterparty<br>Netting of<br>Energy Contracts** | **Cash Collateral<br>Received/Posted** | **Net Amount** |
| **As at December 31, 2022** |  |  |  |  |
| Derivative assets | **353** | **54** | **63** | **236** |
| Derivative liabilities | **(172)** | **(54)** | **—** | **(118)** |

---

---

| | | | | |
|:---|:---|:---|:---|:---|
| As at December 31, 2021 |  |  |  |  |
| Derivative assets | 94 | 25 | 7 | 62 |
| Derivative liabilities | (49) | (25) |  | (24) |

---

---

| | | |
|:---|:---|:---|
| **43** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***25. FAIR VALUE OF FINANCIAL INSTRUMENTS AND RISK MANAGEMENT (cont'd)***

**Volume of Derivative Activity** 

As at December 31, 2022, 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.

---

| | | |
|:---|:---|:---|
| | **2022** | 2021 |
| **Energy contracts subject to regulatory deferral** <sup>(1)</sup> |  |  |
| Electricity swap contracts *(GWh)* | **586** | 509 |
| Electricity power purchase contracts *(GWh)* | **224** | 731 |
| Gas swap contracts *(PJ)* | **185** | 151 |
| Gas supply contract premiums *(PJ)* | **148** | 144 |
| **Energy contracts not subject to regulatory deferral** <sup>(1)</sup> |  |  |
| Wholesale trading contracts *(GWh)* | **1886** | 1886 |
| Gas swap contracts *(PJ)* | **34** | 29 |

---

<sup>(1)</sup> *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 MISO by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors.

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

Central Hudson has seen an increase in accounts receivable due to the suspension of collection efforts in response to the COVID-19 pandemic, as well as higher commodity prices. Central Hudson continues to proactively contact customers regarding past-due balances to advise them of financial assistance available through federal and state programs, and collection efforts are expected to expand in 2023. Under its regulatory framework, Central Hudson can defer uncollectible write-offs that exceed 10 basis points above the amounts collected in customer rates for future recovery.

UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and the Corporation may be exposed to credit risk in the event of non-performance by counterparties to derivatives. Credit risk is managed by net settling payments, when possible, and dealing only with counterparties that have investment-grade credit ratings. At UNS Energy, Central Hudson and FortisBC Energy, 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 $178 million as at December 31, 2022 (2021 - $59 million).

**Hedge of Foreign Net Investments**

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

As at December 31, 2022, US$2.9 billion (2021 - US$2.2 billion) of corporately issued U.S. dollar-denominated long-term debt has been designated as an effective hedge of net investments, leaving approximately US$10.6 billion (2021 - US$10.8 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, 2022, the carrying value of long-term debt, including current portion, was $28.6 billion (2021 - $25.5 billion) compared to an estimated fair value of $25.8 billion (2021 - $28.8 billion).

---

| | | |
|:---|:---|:---|
| **44** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

**26. COMMITMENTS AND CONTINGENCIES** 

As at December 31, 2022, unconditional minimum purchase obligations were as follows.

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| *($ millions)* | **Total** | Year 1 | Year 2 | Year 3 | Year 4 | Year 5 | Thereafter |
| Gas and fuel purchase obligations <sup>(1)</sup> | **5720** | 1024 | 516 | 461 | 374 | 328 | 3017 |
| Waneta Expansion capacity agreement <sup>(2)</sup> | **2472** | 54 | 55 | 56 | 58 | 59 | 2190 |
| Renewable PPAs <sup>(3)</sup> | **1926** | 131 | 131 | 131 | 131 | 130 | 1272 |
| Power purchase obligations <sup>(4)</sup> | **1691** | 334 | 253 | 191 | 192 | 113 | 608 |
| ITC easement agreement <sup>(5)</sup> | **380** | 14 | 14 | 14 | 14 | 14 | 310 |
| Debt collection agreement <sup>(6)</sup> | **106** | 3 | 3 | 3 | 3 | 3 | 91 |
| Renewable energy credit purchase agreements <sup>(7)</sup> | **77** | 18 | 14 | 7 | 7 | 6 | 25 |
| Other <sup>(8)</sup> | **132** | 21 | 9 | 20 | 3 | 3 | 76 |
|  | **12504** | **1599** | **995** | **883** | **782** | **656** | **7589** |

---

<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;FortisBC Energy ($4,804 million):* includes contracts of $2,720 million for the purchase of renewable natural gas expiring in 2044 and contracts of $2,084 million for the purchase of gas, renewable gas, gas transportation and storage services, expiring in 2062. FortisBC Energy's gas purchase obligations are based on gas commodity indices that vary with market prices and the obligations are based on index prices as at December 31, 2022. The renewable gas supply obligations disclosed reflect the contracted price per GJ between the Corporation and the suppliers.

*UNS Energy ($801 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, the purchase of transmission services for purchased power, as well as natural gas commodity agreements based on projected market prices as of December 31, 2022. Amounts paid for coal depend on actual quantities purchased and delivered. Certain contracts have price adjustment clauses that will affect future costs. These contracts have various expiry dates through 2040.

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*FortisBC Electric* is a party to an agreement to purchase capacity from the Waneta Expansion hydroelectric generating facility for forty-years, beginning April 2015.

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*TEP and UNS Electric* are party to renewable PPAs, with expiry dates from 2027 through 2051, that require TEP and UNS Electric to purchase 100% of the output of certain renewable energy generating facilities and RECs associated with the output delivered once commercial operation is achieved. Amounts are the estimated future payments.

<sup>(4)</sup> &nbsp;&nbsp;&nbsp;&nbsp;*Maritime Electric ($746 million):* includes an energy purchase agreement and transmission capacity contract for 30 MW of capacity to PEI with New Brunswick Power, expiring December 2026 and November 2032, respectively. The agreements entitle Maritime Electric to approximately 4.55% of the output of New Brunswick Power's Point Lepreau nuclear generating station and require Maritime Electric to pay its share of the station's capital operating costs for the life of the unit.

*FortisOntario ($489 million):* an agreement with Hydro-Québec for the supply of up to 145 MW of capacity and a minimum of 537 GWh of associated energy annually through December 2030.

*FortisBC Electric ($258 million):* includes 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.

*UNS Energy ($153 million):* an agreement with Salt River Project Agricultural Improvement and Power District to purchase up to 300 MW of capacity, power and ancillary services through 2023. TEP will pay monthly capacity charges and variable power charges.

<sup>(5)&nbsp;&nbsp;&nbsp;&nbsp;</sup>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 licenses associated with the land over which its transmission lines cross. The agreement expires in December 2050, subject to 10 potential 50-year renewals thereafter unless METC gives notice of non-renewal at least one year in advance.

<sup>(6)</sup> &nbsp;&nbsp;&nbsp;&nbsp;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, are collected in customer rates.

<sup>(7)&nbsp;&nbsp;&nbsp;&nbsp;</sup>UNS Energy and Central Hudson are party to REC 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.

<sup>(8)&nbsp;&nbsp;&nbsp;&nbsp;</sup>Includes AROs and joint-use asset and shared service agreements.

---

| | | |
|:---|:---|:---|
| **45** | FORTIS INC. | DECEMBER 31, 2022 |

---

------

Notes to Consolidated Financial Statements

For the years ended December 31, 2022 and 2021

***26. COMMITMENTS AND CONTINGENCIES (cont'd)***

**Other Commitments**

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

UNS Energy has joint generation performance guarantees with participants at Four Corners and Luna, with agreements expiring in 2041 and 2046 respectively, and at San Juan and Navajo through decommissioning. The participants have guaranteed that in the event of payment default, each non-defaulting participant will bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. In the case of San Juan and Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of $339 million for Four Corners. As at December 31, 2022, there was no obligation under these guarantees.

Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York State. Central Hudson's maximum commitment is $74 million, for which it has issued a parental guarantee. As at December 31, 2022, there was no obligation under this guarantee.

As at December 31, 2022, FortisBC Holdings Inc. ("FHI") had $142 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 2016, the Federal Court dismissed the Band's application for judicial review of the ministerial consent. In 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.

---

| | | |
|:---|:---|:---|
| **46** | FORTIS INC. | DECEMBER 31, 2022 |

---

## Exhibit 99.3

**Exhibit 99.3**

<u>Management Discussion and Analysis</u>

---

| | | | |
|:---|:---|:---|:---|
| Contents | Contents | Contents | Contents |
| About Fortis | **1** | &nbsp;&nbsp;&nbsp;&nbsp;Cash Flow Requirements | **17** |
| Performance at a Glance | **3** | &nbsp;&nbsp;&nbsp;&nbsp;Cash Flow Summary | **18** |
| The Industry | **6** | &nbsp;&nbsp;&nbsp;&nbsp;Contractual Obligations | **20** |
| Focus on Sustainability | **7** | &nbsp;&nbsp;&nbsp;&nbsp;Capital Structure and Credit Ratings | **21** |
| Operating Results | **9** | &nbsp;&nbsp;&nbsp;&nbsp;Capital Plan | **21** |
| Business Unit Performance | **10** | Business Risks | **25** |
| &nbsp;&nbsp;&nbsp;&nbsp;ITC | **10** | Accounting Matters | **32** |
| &nbsp;&nbsp;&nbsp;&nbsp;UNS Energy | **11** | Financial Instruments | **35** |
| &nbsp;&nbsp;&nbsp;&nbsp;Central Hudson | **11** | &nbsp;&nbsp;&nbsp;&nbsp;Long-Term Debt and Other | **35** |
| &nbsp;&nbsp;&nbsp;&nbsp;FortisBC Energy | **12** | &nbsp;&nbsp;&nbsp;&nbsp;Derivatives | **35** |
| &nbsp;&nbsp;&nbsp;&nbsp;FortisAlberta | **12** | Selected Annual Financial Information | **37** |
| &nbsp;&nbsp;&nbsp;&nbsp;FortisBC Electric | **13** | Fourth Quarter Results | **38** |
| &nbsp;&nbsp;&nbsp;&nbsp;Other Electric | **13** | Summary of Quarterly Results | **39** |
| &nbsp;&nbsp;&nbsp;&nbsp;Energy Infrastructure | **13** | Related-Party and Inter-Company Transactions | **40** |
| &nbsp;&nbsp;&nbsp;&nbsp;Corporate and Other | **14** | Management's Evaluation of Controls and Procedures | **41** |
| Non-U.S. GAAP Financial Measures | **14** | Outlook | **41** |
| Regulatory Highlights | **15** | Forward-Looking Information | **42** |
| Financial Position | **16** | Glossary | **43** |
| Liquidity and Capital Resources | **17** | Annual Consolidated Financial Statements | **F-1** |

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**Dated February 9, 2023** 

This MD&A has been prepared in accordance with National Instrument 51-102 - *Continuous Disclosure Obligations*. It should be read in conjunction with the 2022 Annual Financial Statements and is subject to the cautionary statement and disclaimer provided under "Forward-Looking Information" on page 42. 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 U.S. GAAP (except for indicated Non-U.S. GAAP Financial Measures) and, unless otherwise specified, is presented in Canadian dollars based, as applicable, on the following U.S. dollar-to-Canadian dollar exchange rates: (i) average of 1.30 and 1.25 for the years ended December 31, 2022 and 2021, respectively; (ii) 1.36 and 1.26 as at December 31, 2022 and 2021, respectively; (iii) average of 1.36 and 1.26 for the quarters ended December 31, 2022 and 2021, respectively; and (iv) 1.30 for all forecast periods. Certain terms used in this MD&A are defined in the "Glossary" on page 43.

**ABOUT FORTIS**

Fortis (TSX/NYSE: FTS) is a well-diversified leader in the North American regulated electric and gas utility industry, with revenue of $11 billion in 2022 and total assets of $64 billion as at December 31, 2022.

Regulated utilities account for 99% of the Corporation's assets with the remainder primarily attributable to non-regulated energy infrastructure. The Corporation's 9,200 employees serve 3.4 million utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries. As at December 31, 2022, 67% of the Corporation's assets were located outside Canada and 59% of 2022 revenue was derived from foreign operations.

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| **1** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

**TOTAL ASSETS AT DECEMBER 31, 2022**

![chart-221e4a7a8a8d4b48bbe.jpg](chart-221e4a7a8a8d4b48bbe.jpg)![chart-caca8d038eaa4b8c962.jpg](chart-caca8d038eaa4b8c962.jpg)

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. Earnings, 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, and assets under construction in Wisconsin); UNS Energy (integrated electric and natural gas distribution - Arizona); Central Hudson (electric transmission and distribution, and natural gas distribution - New York State); 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 consists of Fortis Belize (three hydroelectric generation facilities - Belize) and Aitken Creek (natural gas storage facility - British Columbia).

Fortis has a unique operating model with a small corporate 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 board of directors, with most having a majority of independent board 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.

Fortis strives to provide safe, reliable and cost-effective energy service to customers while focusing on sustainability policies and practices. The Corporation has established delivering a cleaner energy future as its core purpose. In addition, management is focused on delivering long-term profitable growth for shareholders through the execution of its Capital Plan and the pursuit of investment opportunities within and proximate to its service territories.

Additional information about the Corporation's business and reporting units is provided in Note 1 in the 2022 Annual Financial Statements.

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| **2** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

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| | | | |
|:---|:---|:---|:---|
| **PERFORMANCE AT A GLANCE** | | | |
| **Key Financial Metrics** | | | |
| *($ millions, except as indicated)* | **2022** | 2021 | Variance |
| Common Equity Earnings |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Actual | **1330** | 1231 | 99 |
| &nbsp;&nbsp;&nbsp;&nbsp;Adjusted <sup>(1)</sup> | **1329** | 1219 | 110 |
| Basic EPS *($)* |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Actual | **2.78** | 2.61 | 0.17 |
| &nbsp;&nbsp;&nbsp;&nbsp;Adjusted <sup>(1)</sup> | **2.78** | 2.59 | 0.19 |
| Dividends |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Paid per common share *($)* | **2.17** | 2.05 | 0.12 |
| &nbsp;&nbsp;&nbsp;&nbsp;Actual Payout Ratio *(%)* | **78.1** | 78.5 | (0.4) |
| &nbsp;&nbsp;&nbsp;&nbsp;Adjusted Payout Ratio *(%)* <sup>(1)</sup> | **78.1** | 79.2 | (1.1) |
| Weighted average number of common shares outstanding *(# millions)* | **478.6** | 470.9 | 7.7 |
| Operating Cash Flow | **3074** | 2907 | 167 |
| Capital Expenditures <sup>(1)</sup> | **4034** | 3564 | 470 |

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<sup>(1)</sup> *See "Non-U.S. GAAP Financial Measures" on page 14*

**Earnings and EPS**

The Corporation reported Common Equity Earnings of $1.3 billion in 2022, or $2.78 per common share, compared to $1.2 billion, or $2.61 per common share in 2021. Our businesses performed well in 2022, delivering approximately 7% annual EPS growth. The increase was primarily driven by Rate Base growth across our utilities. The increase in earnings was also due to: (i) higher retail and wholesale electricity sales, as well as transmission revenue in Arizona; (ii) higher margins on gas sold and the mark-to-market accounting of natural gas derivatives at Aitken Creek; and (iii) the impact of new customer rates at Central Hudson. The translation of U.S. dollar-denominated subsidiary earnings at the higher U.S.-to-Canadian dollar foreign exchange rate and lower stock based compensation costs also contributed to results, with these impacts exceeding the related losses on derivatives associated with hedging activities.

Growth in earnings was tempered by certain discrete items at ITC including: (i) costs associated with the suspension of the Lake Erie Connector project; (ii) the revaluation of deferred income tax assets due to a reduction in the corporate income tax rate in the state of Iowa; and (iii) a favourable adjustment recognized in 2021 related to interest rate swaps. Losses on investments that support retirement benefits at UNS Energy and ITC, higher operating costs at Central Hudson related to the implementation of a new CIS, and higher corporate costs also tempered results.

In addition to the above-noted items impacting earnings, the change in EPS reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

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| **3** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

Year over year, Adjusted Common Equity Earnings and Adjusted Basic EPS increased by $110 million and $0.19, respectively. Refer to "Non-U.S. GAAP Financial Measures" on page 14 for a reconciliation of these measures. The changes in Adjusted Basic EPS are illustrated in the chart below.

![chart-a273b7b07c2a4378a4b.jpg](chart-a273b7b07c2a4378a4b.jpg)

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Reflects Rate Base growth and lower non-recoverable stock-based compensation costs, partially offset by a favourable adjustment related to interest rate swaps in 2021, losses on investments that support retirement benefits and higher holding company finance costs*

<sup>(2)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Includes FortisBC Energy, FortisAlberta and FortisBC Electric. Primarily reflects Rate Base growth, partially offset by an increase in operating expenses and a higher effective income tax rate at FortisAlberta*

<sup>(3)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Includes UNS Energy and Central Hudson. Reflects higher earnings at UNS Energy, due to higher retail and wholesale electricity sales, as well as transmission revenue, partially offset by higher costs associated with Rate Base growth not yet reflected in customer rates, higher operating expenses, and losses on certain investments that support retirement benefits. Also reflects higher earnings at Central Hudson, driven by new customer rates due to the conclusion of the general rate application in 2021, and the impact of unfavourable regulatory deferrals recorded in 2021, partially offset by higher operating expenses associated with the implementation of a new CIS and non-recoverable finance costs*

<sup>(4)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Includes higher margins on gas sold at Aitken Creek, reflecting market conditions, and higher hydroelectric production in Belize associated with rainfall levels*

<sup>(5)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Primarily reflects Rate Base growth and higher electricity sales*

<sup>(6)</sup> &nbsp;&nbsp;&nbsp;&nbsp;*Average foreign exchange rate of 1.30 in 2022 compared to 1.25 in 2021*

<sup>(7)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Primarily reflects market conditions, including losses on total return swaps and foreign exchange contracts and higher finance costs, as well as lower income tax recovery*

<sup>(8)</sup> &nbsp;&nbsp;&nbsp;&nbsp;*Weighted average shares of 478.6 million in 2022 compared to 470.9 million in 2021*

**Dividends**

Fortis paid a dividend of $0.565 per common share in the fourth quarter of 2022, up 5.6% from $0.535 paid in each of the previous four quarters. This marked the Corporation's 49<sup>th</sup> consecutive year of dividend increases. The Actual Payout Ratio was 78% in 2022 and an average of 68% over the five-year period of 2018 through 2022.

Fortis is targeting annual dividend growth of approximately 4-6% through 2027. See "Outlook" on page 41.

![chart-dc2933c27eee4709be3.jpg](chart-dc2933c27eee4709be3.jpg)

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| **4** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

Growth in dividends and changes in the market price of the Corporation's common shares have yielded the following TSR.

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| | | | | |
|:---|:---|:---|:---|:---|
| **TSR** <sup>(1)</sup> *(%)* | **1-Year** | **5-Year** | **10-Year** | **20-Year** |
| Fortis | **(7.9)** | **7.2** | **8.7** | **11.3** |

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<sup>(1)</sup> *Annualized TSR per Bloomberg, as at December 31, 2022*

**Operating Cash Flow**

The $167 million increase in Operating Cash Flow was due to: (i) higher cash earnings, reflecting Rate Base growth and higher retail and long-term wholesale electricity sales, as well as transmission revenue, in Arizona; (ii) collateral deposits received at UNS Energy related to derivative energy contracts; (iii) proceeds received at ITC upon the settlement of interest rate swaps; and (iv) the higher U.S.-to-Canadian dollar exchange rate. The timing of flow-through of costs in customer rates also favourably impacted Operating Cash Flow. The increase was partially offset by higher gas inventory levels in British Columbia, as well as storm restoration costs incurred in 2022, to be recovered in future customer rates, and higher accounts receivable at Central Hudson.

**Capital Expenditures**

Capital Expenditures were $4.0 billion, consistent with the 2022 Capital Plan and $0.5 billion higher than 2021. The increase over 2021 was primarily due to continued investment in various smaller transmission and distribution projects at the Corporation's regulated utilities, as well as the impact of the higher average foreign exchange rate.

The Corporation's 2023-2027 Capital Plan of $22.3 billion is the largest in the Corporation's history and is $2.3 billion higher than the previous five-year plan. The increase is driven by organic growth, largely reflecting regional transmission projects associated with the MISO LRTP at ITC, additional cleaner energy investments in Arizona to support TEP's planned exit from coal by 2032, and enhancements to distribution infrastructure reliability and capacity, as well as investments to support customer growth, across the Corporation's regulated utilities. Approximately $500 million of the increase is driven by a higher assumed U.S.-to-Canadian dollar exchange rate over the five-year period. See "Capital Plan" on page 21 for further information.

Funding of the Capital Plan is expected to be primarily through Operating Cash Flow, debt issued at the regulated utilities and common equity from the Corporation's DRIP.

The five-year Capital Plan is expected to increase midyear Rate Base from $34.1 billion in 2022 to $46.1 billion by 2027, representing a five-year CAGR of 6.2%.

Capital Expenditures and Capital Plan reflect Non-U.S. GAAP financial measures. Refer to "Non-U.S. GAAP Financial Measures" on page 14 and "Capital Plan" on page 21.

![chart-e36901b96cb44041a03.jpg](chart-e36901b96cb44041a03.jpg)

Beyond the five-year Capital Plan, additional opportunities to expand and extend growth include: further expansion of the electric transmission grid in the U.S. to facilitate the interconnection of cleaner energy, including infrastructure investments associated with the IRA and the MISO LRTP; climate adaptation and grid resiliency investments; renewable gas solutions and LNG infrastructure in British Columbia; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.

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| **5** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

**THE INDUSTRY**

The North American energy industry's transformation is accelerating rapidly, driven by the impacts of climate change, as well as the need for a cleaner energy future and innovation. There is a growing need for the development of cleaner energy sources and the deployment of energy conservation measures to preserve the planet for future generations. The goal of carbon emissions reduction, and associated advancements in technology, have attracted interest from investors and customers. Electric transmission is seen as a critical enabler of large-scale renewable generation. Natural gas also continues to be an important part of the energy mix, as supplemental generation to the intermittent nature of renewables, and as a cost-effective heating source. Longer term, advancements in the use of hydrogen and RNG will further contribute to carbon reduction. Each of these factors, as well as the increasing affordability of cleaner energy, is driving significant investment opportunity in the utility sector.

Energy policies at the federal, state, and provincial levels reflect the rising focus on climate change, with clean energy and carbon reduction goals and initiatives at the forefront. In the U.S., the IRA has been passed into law and includes, among other items, incentives and clean energy tax credits encouraging investments in clean energy, energy storage, electric vehicles and manufacturing, all to support a targeted 40% reduction in carbon emissions by 2030. With states and provinces also setting ambitious carbon reduction targets, the regulatory and compliance environment continues to evolve and become increasingly complex. These changes are creating opportunities to expand investment in new, renewable generation sources, as well as transmission infrastructure to connect renewable energy sources to the grid. In addition to growth of renewable generation, investment opportunities in energy storage technology are also being created. The electrification of the transportation sector is gaining momentum and represents a significant opportunity to reduce carbon emissions while increasing the output and efficiency of the grid. The Corporation's utilities are well positioned and actively involved in pursuing these opportunities which will drive significant investment.

New technology is stimulating change across all of the Corporation's service territories. Energy delivery systems are becoming more intelligent, with upgraded advanced meters, additional grid automation, high-speed private communications networks, and more capable operational technology, providing utilities with detailed usage data and predictive maintenance information to improve cost efficiency and safety. Energy management capabilities are expanding through emerging storage and demand response systems, and customers have options to manage energy usage and access to more affordable distributed generation. Grid resilience is growing in importance with the increasing frequency and intensity of weather events such as hurricanes, wildfires, floods and storms. With electricity expected to represent a larger portion of society's energy mix, investments in grid hardening and resiliency are necessary to improve the grid's ability to withstand and recover from these climate events.

Fortis' culture of innovation underlies a continuous drive to find a better way to safely, reliably and affordably deliver the energy and services that customers need, and the choice and control they increasingly seek. Fortis is a partner in the Energy Impact Partners utility coalition, which is a strategic private equity fund that invests in emerging technologies, products, services and business models that are transforming the industry. The Corporation is also involved in the Low Carbon Resources Initiative, a collaboration between EPRI and GTI Energy, along with major North American utilities, to develop and demonstrate the low- and zero-carbon energy technologies needed to enable pathways to economy-wide decarbonization. In 2022, Fortis also joined EPRI's Climate READi, an initiative involving major North American utilities, regulators, policy makers, and other stakeholders focused on developing an industry-wide best practice framework for managing physical climate risk.

Meaningful customer engagement is important for utilities as customer expectations change. Customers want to make informed energy choices and become active participants in the delivery of their energy services. They also expect personalized service, customized self-service offerings and more real-time, digital communication. Fortis' utilities are enhancing customer information systems and digital technologies to improve customer service.

On the security front, with the advent of new and increasing cyber threats to our information and operational technology systems, increased focus and investment on protection and response to these cyber events is an ongoing priority. Upgrades to the physical security environment is also required to keep pace with evolving challenges. All these technological advancements and challenges offer strategic investment opportunities for improving and expanding customer service and enhancing security.

The Corporation's culture and decentralized structure support the efforts required to meet changing customer expectations. Each of our utilities work constructively with regulators and all stakeholders on policy, energy and service solutions, and are an integral partner in all the communities they serve. Fortis is committed to be an industry leader in the clean energy transition.

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| **6** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

**FOCUS ON SUSTAINABILITY**

Fortis is dedicated to operating in an environmentally and socially responsible manner in the interests of all of its stakeholders. Fortis believes that focusing on the responsible and sustainable management of its businesses is good for employees, customers, communities and the planet, but also, importantly, shareholders. Oversight and accountability for sustainability are established at the most senior levels of the Corporation and its operating subsidiaries. At Fortis, the Board has overall responsibility for sustainability. However, primary oversight of the issues, policies and practices pertaining to sustainability has been delegated to the governance and sustainability committee of the Board, reflecting sustainability's important role in the Corporation's strategy and management of risk.

Key aspects of Fortis' sustainability program and practices are outlined below.

**Climate Change and Environmental Matters**

Fortis is primarily an energy delivery company with 93% of its assets related to transmission and distribution. The focus for Fortis is the delivery of cleaner energy to its customers and this limits the impact of the Corporation's utilities on the environment when compared to more generation-intensive businesses. Fortis has a relatively small amount of fossil-fuel generation in its portfolio and has a plan to transition to more renewable sources of energy for its customers.

The Corporation's direct GHG emissions come primarily from its generation assets, which largely consist of fossil fuel-based generation at TEP, representing 4% of the Corporation's total assets. Fortis continues to build on its low emissions profile, and in May 2022, set a 2050 net-zero direct GHG emissions target. This goal is in addition to the Corporation's interim targets to reduce GHG emissions 50% by 2030 and 75% by 2035 from a 2019 base year. Fortis expects to achieve both interim targets without the use of carbon offsets, primarily through delivering on TEP's plan to reduce carbon emissions, as well as clean energy initiatives across the Corporation's other utilities.

Consistent with our interim targets and pathway to net-zero, in June 2022, TEP retired 170-MW of coal-fired generation through the planned closure of San Juan. Fortis has made significant progress on its emissions reduction targets. Through 2022, the Corporation's Scope 1 emissions were 28% lower compared to 2019 levels, equivalent to taking approximately 760,000 vehicles off the road in one year.

Beyond 2035, most of the Corporation's Scope 1 emissions are expected to relate to natural gas generation at TEP. To reach net-zero by 2050, TEP will focus on developing and adopting new technologies, improving the efficiency of natural gas units, utilizing lower-carbon fuels and preparing its generating units for future hydrogen injection. Reliability and affordability will remain key priorities as Fortis works to meet its emissions reduction targets.

The Corporation made progress on its commitment as a TCFD supporter in March 2022, with the release of its first TCFD and Climate Assessment Report, which included an analysis of four climate-related scenarios and associated risks and opportunities. This report provides information on Fortis' strategy and actions to address climate change, physical and transition risks, and business opportunities including investments in resilient and adaptable infrastructure. In July 2022, Fortis released its 2022 Sustainability Report, highlighting progress on a number of sustainability priorities, including adding more renewable energy, reducing GHG emissions and improving diversity. The report also provided enhanced information on the Corporation's sustainability strategy, significantly expanded the scope of key performance indicators, and was fully aligned with applicable Sustainability Accounting Standards Board standards.

In 2022, over $600 million in Capital Expenditures were focused on the delivery of cleaner energy to customers. In the development of the Corporation's five-year Capital Plan, each of the utilities considered the investment required to deliver cleaner energy to customers, strengthen infrastructure, and improve network resiliency to deal with the expected impacts of climate change on utility infrastructure. Fortis' 2023-2027 Capital Plan includes cleaner energy investments of $5.9 billion, with investments focused on connecting renewables to the grid, renewable and storage investments, and cleaner fuel solutions. Additional information can be found in the "Capital Plan" section on page 21. In support of the capital program, during 2022, Fortis amended its unsecured $1.3 billion revolving term committed credit facility agreement to include the establishment of a sustainability-linked loan structure based on the Corporation's achievement of targets related to diversity on the Board and reduction of Scope 1 GHG emissions for 2022 through 2025.

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, seek feasible, cost-effective opportunities to decrease GHG emissions and increase renewable energy sources. 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.

**Safety and Reliability**

Fortis is an industry leader in safety and reliability, with the Corporation consistently performing above industry averages. Fortis leverages its unique operating model and utility experience to deliver safe and reliable service to its customers and the communities it serves. Senior operational executives from all Fortis utilities meet regularly to share best practices and identify opportunities for collaboration on a range of operational areas including health and safety.

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| **7** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

All contractors are required to share our commitment to conduct work in a safe manner. Contractors must demonstrate a strong safety program with a high level of training centered around risk management. Historical safety performance is a consideration when selecting successful contractors.

**Engaging with Stakeholders and Communities**

Fortis' utilities work closely with their customers and communities to drive enhancements and improve the overall customer service experience. Customer satisfaction targets are established and customer service surveys are completed regularly focusing on customer satisfaction, reliability and accuracy of billing and metering, contact center services and reliability of energy supply.

Customer affordability is a key priority for Fortis. Historically, Fortis utilities have managed annual increases in controllable operating costs per customer to below inflation. In addition, our utilities work to ensure customers are aware of bill payment options, external government payment assistance programs, as well as home energy efficiency programs and rebates.

Fortis and its utilities work with a number of Indigenous groups, with the goal of developing long-term partnerships and creating economic opportunities. The Wataynikaneyap Power Transmission project is an 1,800 kilometer transmission line that will connect 17 First Nations communities to the Ontario power grid for the first time. These communities currently have inefficient and unreliable access to electricity based on diesel generation, compromising their economic and social well-being and limiting their opportunities for growth. The project is majority-owned by 24 First Nations, while Fortis has a 39% ownership interest and acts as project manager. Additional information can be found in the "Capital Plan" section on page 21.

Fortis and its utilities consistently look for opportunities for growth, innovation and energy efficiency in the communities they serve. Regular community engagement includes donations to local charities, partnerships with educational institutions, and participation on local boards, which enables Fortis and its utilities to serve as meaningful contributors to their local communities. In 2022, the Fortis group of companies contributed $9.7 million to the communities they serve.

**Cybersecurity**

Fortis' CRMP aims to continually improve information sharing and the culture of security. Fortis has an enterprise-wide CRMP that allows for the identification, measurement, monitoring and management of cybersecurity risks. Further, the Corporation and each of the utilities continually consider investments required in security, in both the corporate and grid environments, during the development of the five-year Capital Plan. Physical and cyber security leaders share best practices in areas such as threat monitoring, protecting customer information and risk management. The group also conducts training exercises to test systems and identify opportunities to improve. Oversight of cybersecurity is the responsibility of Fortis' Vice President, Chief Information Officer as well as the respective boards and executive committees at Fortis and at each utility. The Fortis group of companies have not had any reportable cybersecurity breaches since we began reporting this performance indicator in 2018.

**Human Capital Management**

Fortis values its 9,200 employees and recognizes that success is dependent on a strong workforce which is safe, supported and empowered. Fortis and its utilities have compensation and benefit programs designed to attract and retain talent. Fortis believes that the foundation for a healthy work environment starts with leadership from the most senior levels of the organization and must be driven by clearly articulated values that are understood and practiced at all levels of the organization.

Fortis has a longstanding corporate-wide talent management strategy that enhances our ability to identify, mentor and develop current executives and employees for more senior positions. The Corporation seeks to continually enhance its talent management strategy. In 2022, it completed the inaugural year of a new leadership training program for high-potential employees across the organization that provides substantive training, mentoring opportunities and exposure to management. This approach supports talent development and ensures there is a pipeline of qualified talent, preparing the Corporation and its utilities for an orderly succession of critical roles.

Our utilities strive to maintain good employee and labour relations and regular communications and collaboration between union and management leaders. Approximately 50% of the employees across our group of companies are represented by a labour union.

Governance & Executive Compensation

The Fortis Code of Conduct is guided by the Corporation's purpose and values and sets out standards for the ethical conduct of its directors, officers, employees, consultants, contractors and representatives. The core principles of the Code of Conduct apply across the organization, with each operating subsidiary adopting its own substantially similar Code. Fortis and its utilities hold regular Code of Conduct employee training and all Fortis employees and Board members annually certify compliance.

The Code of Conduct is supported by other policies that outline the actions and behaviours 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.

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| **8** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

Fortis and each of its operating subsidiaries have a Speak Up Policy to support and facilitate the anonymous reporting of conduct that may breach the Code of Conduct or other workplace policies.

Achieving Fortis' sustainability objectives is a focus for the Board and forms a component of executive compensation. Sustainability-related performance measures including ESG leadership, carbon reduction, safety and reliability, and diversity, equity and inclusion are embedded in the Corporation's executive compensation program.

**Diversity, Equity and Inclusion**

The Corporation's Board and Executive Diversity Policy describes the principles and objectives for diversity among the Board and executive leadership, including a commitment to maintain a Board where at least 40% of independent directors are women. As of December 31, 2022, 54% of Board members were women, 42% of Fortis' executives were women and 73% of Fortis utilities had either a female president or female board chair. The Corporation also committed to have at least two Board members who identify as a visible minority or Indigenous person by 2023, and achieved this objective as of December 31, 2022.

Advancing diversity, equity and inclusion is a priority at Fortis. The Corporation adopted an Inclusion and Diversity Commitment that applies to all employees of Fortis and its operating subsidiaries. The commitment is supported by a framework built upon three pillars - talent, culture and community. A Diversity, Equity and Inclusion Advisory Council with diverse, senior level representation from across the Fortis organization guides the inclusion and diversity strategy and its implementation.

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| | | | | |
|:---|:---|:---|:---|:---|
| **OPERATING RESULTS** | | | | |
|  |  |  | Variance | Variance |
| *($ millions)* | **2022** | 2021 | FX | Other |
| Revenue | **11043** | 9448 | 206 | 1389 |
| Energy supply costs | **3952** | 2951 | 55 | 946 |
| Operating expenses | **2683** | 2523 | 61 | 99 |
| Depreciation and amortization | **1668** | 1505 | 30 | 133 |
| Other income, net | **165** | 173 | 4 | (12) |
| Finance charges | **1102** | 1003 | 22 | 77 |
| Income tax expense | **289** | 234 | 7 | 48 |
| Net earnings | **1514** | 1405 | 35 | 74 |
| Net earnings attributable to: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-controlling interests | **120** | 111 | 4 | 5 |
| &nbsp;&nbsp;&nbsp;&nbsp;Preference equity shareholders | **64** | 63 |  | 1 |
| &nbsp;&nbsp;&nbsp;&nbsp;Common equity shareholders | **1330** | 1231 | 31 | 68 |
| Net Earnings | **1514** | 1405 | 35 | 74 |

---

**Revenue**

The increase in revenue, net of foreign exchange, was due primarily to: (i) higher flow-through costs in customer rates, driven by higher commodity prices; (ii) Rate Base growth; and (iii) higher retail and wholesale electricity sales, as well as transmission revenue, at UNS Energy, partially offset by the normal operation of regulatory deferrals at FortisBC Energy.

**Energy Supply Costs**

The increase in energy supply costs, net of foreign exchange, was due primarily to higher commodity costs reflecting increases in pricing and volumes.

**Operating Expenses**

The increase in operating expenses, net of foreign exchange, was due primarily to general inflationary and employee-related cost increases, as well as the implementation of a new CIS at Central Hudson, partially offset by lower stock-based compensation costs.

**Depreciation and Amortization**

The increase in depreciation and amortization, net of foreign exchange, was due to continued investment in energy infrastructure at the Corporation's regulated utilities, as well as new depreciation rates, recoverable in customer rates, at ITC effective January 1, 2022.

**Other Income, Net**

The decrease in other income, net of foreign exchange, was due primarily to losses on total return swaps and foreign exchange contracts in the Corporate and Other segment, as well as losses on investments that support retirement benefits at UNS Energy and ITC. The decrease was largely offset by an increase in the non-service component of benefit costs.

---

| | | |
|:---|:---|:---|
| **9** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

**Finance Charges**

The increase in finance charges, net of foreign exchange, was due to higher debt levels to support the Corporation's Capital Plan, as well as higher interest rates impacting variable-rate debt and new debt issuances.

**Income Tax Expense**

The increase in income tax expense, net of foreign exchange, was driven by: (i) higher earnings before taxes; (ii) the revaluation of deferred income tax assets resulting from a reduction in the corporate income tax rate in the state of Iowa; and (iii) a lower income tax recovery in the Corporate & Other segment, including a lower benefit associated with filing a consolidated U.S. tax return and the timing of true-ups to the income tax provision to reflect tax filings.

**Net Earnings**

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

---

| | | | | |
|:---|:---|:---|:---|:---|
| **BUSINESS UNIT PERFORMANCE** | | | | |
| **Common Equity Earnings** |  |  | Variance | Variance |
| *($ millions)* | **2022** | 2021 | FX <sup>(1)</sup> | Other |
| **Regulated Utilities** |  |  |  |  |
| ITC | **454** | 426 | 16 | 12 |
| UNS Energy | **328** | 292 | 12 | 24 |
| Central Hudson | **103** | 93 | 3 | 7 |
| FortisBC Energy | **203** | 185 |  | 18 |
| FortisAlberta | **151** | 141 |  | 10 |
| FortisBC Electric | **64** | 59 |  | 5 |
| Other Electric <sup>(2)</sup> | **134** | 118 | 2 | 14 |
|  | **1437** | 1314 | 33 | 90 |
| **Non-Regulated** |  |  |  |  |
| Energy Infrastructure <sup>(3)</sup> | **72** | 38 |  | 34 |
| Corporate and Other <sup>(4)</sup> | **(179)** | (121) | (2) | (56) |
| **Common Equity Earnings** | **1330** | 1231 | 31 | 68 |

---

<sup>(1)</sup> *The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI and Fortis Belize is the U.S. dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the U.S. dollar at BZ$2.00=US$1.00. The Corporate and Other segment includes certain transactions denominated in U.S. dollars*

<sup>(2)</sup> *Consists of the utility operations in eastern Canada and the Caribbean: Newfoundland Power; Maritime Electric; FortisOntario; Wataynikaneyap Partnership; Caribbean Utilities; FortisTCI; and Belize Electricity*

<sup>(3)</sup> *Primarily consists of long-term contracted generation assets in Belize and Aitken Creek in British Columbia*

<sup>(4)</sup> *Includes Fortis net corporate expenses and non-regulated holding company expenses* 

---

| | | | | |
|:---|:---|:---|:---|:---|
| **ITC** |  |  | Variance | Variance |
| *($ millions)* | **2022** | 2021 | FX | Other |
| Revenue <sup>(1)</sup> | **1906** | 1691 | 63 | 152 |
| Earnings <sup>(1)</sup> | **454** | 426 | 16 | 12 |

---

<sup>(1)</sup> *Revenue represents 100% of ITC. Earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflect consolidated purchase price accounting adjustments.* 

**Revenue**

The increase in revenue, net of foreign exchange, was due primarily to higher recoverable depreciation expense, reflecting revised depreciation rates effective January 1, 2022, and Rate Base growth.

**Earnings**

The increase in earnings, net of foreign exchange, reflected Rate Base growth and lower non-recoverable stock-based compensation costs. Growth in earnings was tempered by certain discrete items including: (i) costs associated with the suspension of the Lake Erie Connector project; (ii) the revaluation of deferred income tax assets resulting from a reduction in the corporate income tax rate in the state of Iowa; and (iii) a favourable adjustment recognized in 2021 related to interest rate swaps. Losses on certain investments that support retirement benefits and higher holding company finance costs also unfavourably impacted results.

---

| | | |
|:---|:---|:---|
| **10** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

In July 2022, ITC suspended development activities and commercial negotiations relating to the $1.7 billion Lake Erie Connector project. ITC determined that there was no viable path to conclude certain key commercial negotiations and other requirements within the required timelines, in part due to macroeconomic conditions, including rising inflation, interest rates, and fluctuations in the U.S.-to-Canadian dollar foreign exchange rate. This project was never included in the Corporation's five-year Capital Plan.

---

| | | | | |
|:---|:---|:---|:---|:---|
| **UNS Energy** |  |  | Variance | Variance |
| *($ millions, except as indicated)* | **2022** | 2021 | FX | Other |
| Retail electricity sales *(GWh)* | **10658** | 10559 |  | 99 |
| Wholesale electricity sales *(GWh)* <sup>(1)</sup> | **5401** | 6283 |  | (882) |
| Gas sales *(PJ)* | **16** | 16 |  |  |
| Revenue | **2758** | 2334 | 93 | 331 |
| Earnings | **328** | 292 | 12 | 24 |

---

<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Primarily short-term wholesale sales*

**Sales**

The increase in retail electricity sales was due primarily to favourable weather as compared to 2021 and customer growth.

The decrease in wholesale electricity sales was driven by lower short-term wholesale electricity sales, partially offset by higher long-term wholesale electricity sales. Revenue from short-term wholesale electricity sales is primarily credited to customers through regulatory deferral mechanisms and, therefore, does not materially impact earnings.

Gas sales were consistent with 2021.

**Revenue**

The increase in revenue, net of foreign exchange, was due primarily to: (i) the recovery of higher fuel and non-fuel costs through the normal operation of regulatory mechanisms; (ii) higher revenue from short-term wholesale electricity sales due to favourable pricing; (iii) higher long-term wholesale electricity sales; (iv) higher retail electricity sales, discussed above; and (v) higher transmission revenue. The increase was partially offset by lower short-term wholesale electricity sales.

**Earnings**

The increase in earnings, net of foreign exchange, was due primarily to higher retail electricity sales, long-term wholesale electricity sales, and transmission revenue. The increase in earnings was partially offset by higher costs associated with Rate Base growth not yet reflected in customer rates, higher operating expenses, and losses on certain investments that support retirement benefits.

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Central Hudson** |  |  | Variance | Variance |
| *($ millions, except as indicated)* | **2022** | 2021 | FX | Other |
| Electricity sales *(GWh)* | **5002** | 5000 |  | 2 |
| Gas sales *(PJ)* | **25** | 23 |  | 2 |
| Revenue  | **1325** | 1000 | 36 | 289 |
| Earnings  | **103** | 93 | 3 | 7 |

---

**Sales**

Electricity sales were consistent with 2021.

The increase in gas sales was due to higher average consumption by residential, commercial and industrial customers due to colder temperatures.

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

**Revenue**

The increase in revenue, net of foreign exchange, was due primarily to: (i) the flow through of higher energy supply costs driven by commodity prices; and (ii) an increase in gas and electricity delivery rates effective July 1, 2021 and July 1, 2022, reflecting a return on increased Rate Base assets and the recovery of higher operating and finance expenses, associated with the conclusion of Central Hudson's general rate application in 2021.

---

| | | |
|:---|:---|:---|
| **11** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

**Earnings**

The increase in earnings, net of foreign exchange, was due to new customer rates discussed above, and the impact of unfavourable regulatory deferrals recorded in 2021 associated with reliability performance targets. The increase was partially offset by higher operating expenses associated with the implementation of a new CIS, and higher non-recoverable finance costs.

---

| | | | |
|:---|:---|:---|:---|
| **FortisBC Energy** | | | |
| *($ millions, except as indicated)* | **2022** | 2021 | Variance |
| Gas sales *(PJ)* | **231** | 228 | 3 |
| Revenue | **2084** | 1715 | 369 |
| Earnings | **203** | 185 | 18 |

---

**Sales**

The increase in gas sales was due primarily to higher average consumption by residential and commercial customers due to colder temperatures, partially offset by lower average consumption by transportation customers.

**Revenue**

The increase in revenue was due primarily to a higher cost of natural gas recovered from customers and Rate Base growth, partially offset by the normal operation of regulatory deferrals.

**Earnings**

The increase in earnings 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 delivery. Due to regulatory deferral mechanisms, changes in consumption levels and commodity costs do not materially impact earnings.

---

| | | | |
|:---|:---|:---|:---|
| **FortisAlberta** | | | |
| *($ millions, except as indicated)* | **2022** | 2021 | Variance |
| Electricity deliveries *(GWh)* | **16923** | 16643 | 280 |
| Revenue | **680** | 644 | 36 |
| Earnings  | **151** | 141 | 10 |

---

**Deliveries**

The increase in electricity deliveries was due to higher load from industrial customers, higher average consumption by commercial customers, and customer additions. The increase was partially offset by lower average consumption by residential customers due to milder weather in 2022 as compared to 2021.

As approximately 85% 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. Significant variations in weather conditions, however, can impact revenue and earnings.

**Revenue**

The increase in revenue was due to Rate Base growth.

**Earnings**

The increase in earnings was due to Rate Base growth, partially offset by higher operating expenses and a higher effective income tax rate.

---

| | | |
|:---|:---|:---|
| **12** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

---

| | | | |
|:---|:---|:---|:---|
| **FortisBC Electric** | | | |
| *($ millions, except as indicated)* | **2022** | 2021 | Variance |
| Electricity sales *(GWh)* | **3542** | 3460 | 82 |
| Revenue  | **487** | 468 | 19 |
| Earnings  | **64** | 59 | 5 |

---

**Sales**

The increase in electricity sales was due primarily to higher average consumption by industrial customers.

**Revenue**

The increase in revenue was due to higher electricity sales, Rate Base growth, and higher surplus power sales, partially offset by the normal operation of regulatory deferrals.

**Earnings**

The increase in earnings was due primarily to Rate Base growth.

Due to regulatory deferral mechanisms, changes in consumption levels do not materially impact earnings.

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Other Electric** |  |  | Variance | Variance |
| *($ millions, except as indicated)* | **2022** | 2021 | FX | Other |
| Electricity sales *(GWh)* | **9470** | 9266 |  | 204 |
| Revenue | **1652** | 1498 | 14 | 140 |
| Earnings  | **134** | 118 | 2 | 14 |

---

**Sales**

The increase in electricity sales was due to higher average consumption by residential and commercial customers in Eastern Canada, as well as higher sales in the Caribbean, due to increased tourism-related activities.

**Revenue**

The increase in revenue, net of foreign exchange, was due to the flow through of higher energy supply costs, higher electricity sales and Rate Base growth, as well as the normal operation of regulatory mechanisms at Newfoundland Power.

**Earnings**

The increase in earnings, net of foreign exchange, was due primarily to Rate Base growth and higher electricity sales.

---

| | | | |
|:---|:---|:---|:---|
| **Energy Infrastructure** | | | |
| *($ millions, except as indicated)* | **2022** | 2021 | Variance |
| Electricity sales *(GWh)* | **225** | 147 | 78 |
| Revenue  | **151** | 98 | 53 |
| Earnings  | **72** | 38 | 34 |

---

**Sales**

The increase in electricity sales reflected an increase in hydroelectric production in Belize associated with higher rainfall levels.

**Revenue and Earnings**

Revenue and earnings were favourably impacted by the mark-to-market accounting of natural gas derivatives at Aitken Creek, which resulted in unrealized gains of $20 million in 2022 compared to $12 million in 2021.

Excluding the impact of mark-to-market accounting, revenue and earnings increased by $43 million and $26 million, respectively. The increases were driven by Aitken Creek due to higher margins on gas sold, reflecting market conditions, as well as losses realized on natural gas contracts in 2021, as certain contracts were settled that year in consideration of favourable forward curves. Higher hydroelectric production in Belize also contributed to the increases in revenue and earnings.

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 resultant earnings volatility can be significant.

---

| | | |
|:---|:---|:---|
| **13** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Corporate and Other** |  |  | Variance | Variance |
| *($ millions)* | **2022** | 2021 | FX | Other |
| Net expenses | **(179)** | (121) | (2) | (56) |

---

The increase in net expenses, net of foreign exchange, largely reflected market conditions, including losses on total return swaps and foreign exchange contracts, as well as higher finance costs. A lower income tax recovery also contributed to results. The increase in net expenses was partially offset by a reduction in operating expenses reflecting lower stock-based compensation costs.

Results for the Corporate and Other segment include the impact of hedging activities associated with share-based compensation and foreign exchange, and therefore can fluctuate depending on market conditions. On a consolidated basis, the overall earnings impact was favourable as lower stock based compensation costs and the translation of U.S. dollar-denominated subsidiary earnings at the higher U.S.-to-Canadian dollar foreign exchange rate was greater than losses on derivatives associated with hedging activities.

**NON-U.S. GAAP FINANCIAL MEASURES**

Adjusted Common Equity Earnings, Adjusted Basic EPS, Adjusted Payout Ratio and Capital Expenditures are Non-U.S. 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 U.S. 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 U.S. GAAP measure to the Adjusted Payout Ratio. These adjusted measures reflect the removal of items that management excludes in its key decision-making processes and evaluation of operating results.

Capital Expenditures include additions to property, plant and equipment and additions to intangible assets, as shown on the consolidated statements of cash flows. It also includes Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project, consistent with Fortis' evaluation of operating results and its role as project manager during the construction of this Major Capital Project.

---

| | | | |
|:---|:---|:---|:---|
| **Non-U.S. GAAP Reconciliation** | | | |
| *($ millions, except as indicated)* | **2022** | 2021 | Variance |
| &nbsp;&nbsp;&nbsp;**Adjusted Common Equity Earnings, Adjusted Basic EPS**<br>**and Adjusted Payout Ratio** |  |  |  |
| Common Equity Earnings | **1330** | 1231 | 99 |
| Adjusting items: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unrealized gain on mark-to-market of derivatives <sup>(1)</sup> | **(20)** | (12) | (8) |
| &nbsp;&nbsp;&nbsp;&nbsp;Lake Erie Connector project suspension costs <sup>(2)</sup> | **10** |  | 10 |
| &nbsp;&nbsp;&nbsp;&nbsp;Revaluation of deferred income tax assets <sup>(3)</sup> | **9** |  | 9 |
| Adjusted Common Equity Earnings | **1329** | 1219 | 110 |
| Adjusted Basic EPS <sup>(4)</sup> *($)*  | **2.78** | 2.59 | 0.19 |
| Adjusted Payout Ratio <sup>(5)</sup> *(%)*  | **78.1** | 79.2 | (1.1) |
| **Capital Expenditures** |  |  |  |
| Additions to property, plant and equipment | **3587** | 3189 | 398 |
| Additions to intangible assets | **278** | 197 | 81 |
| Adjusting item: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Wataynikaneyap Transmission Power Project <sup>(6)</sup> | **169** | 178 | (9) |
| Capital Expenditures | **4034** | 3564 | 470 |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Represents timing differences related to the accounting of natural gas derivatives at Aitken Creek, net of income tax expense of $7 million in 2022 (2021 - $5 million), included in the Energy Infrastructure segment*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Represents costs incurred upon the suspension of the Lake Erie Connector project, net of income tax recovery of $4 million, included in the ITC segment*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Represents the revaluation of deferred income tax assets resulting from the reduction in the corporate income tax rate in the state of Iowa, included in the ITC segment*

<sup>(4)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Calculated using Adjusted Common Equity Earnings divided by weighted average common shares of 478.6 million in 2022 (2021 - 470.9 million)*

<sup>(5)</sup> <sup>&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Calculated using dividends paid per common share of $2.17 in 2022 (2021 - $2.05) divided by Adjusted Basic EPS*

<sup>(6)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Represents Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project, included in the Other Electric segment*

---

| | | |
|:---|:---|:---|
| **14** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

**REGULATORY HIGHLIGHTS**

**General**

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 deemed or targeted capital structure applied to an approved Rate Base. PBR mechanisms generally apply a formula that incorporates inflation and assumed productivity improvements for a set term.

The ability to recover prudently incurred costs of providing service and earn the regulator-approved ROE or 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.

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

Additional information about regulation and the regulatory matters discussed below is provided in Note 2 in the 2022 Annual Financial Statements. Also refer to "Business Risks - Utility Regulation" on page 25.

**Significant Regulatory Developments**

**ITC**

*ITC Midwest Capital Structure Complaint:* In May 2022, ICAT filed a complaint with FERC under Section 206 of the Federal Power Act requesting that ITC Midwest's common equity component of capital structure be reduced from 60% to 53%. ICAT alleged that ITC Midwest does not meet FERC's three-part test for authorizing the use of the utility's actual capital structure for rate-making purposes. In November 2022, FERC issued an order denying the complaint, and in December 2022, ICAT filed a request for rehearing with FERC. The Corporation continues to believe the complaint is without merit, and as at December 31, 2022, ITC Midwest has not recorded a regulatory liability related to the complaint.

*MISO Base ROE:* In August 2022, the D.C. Circuit Court issued a decision vacating certain FERC orders that had established the methodology for setting the base ROE for transmission owners operating in the MISO region, including ITC. This matter dates back to complaints filed at FERC in 2013 and 2015 challenging the MISO base ROE then in effect. The court has remanded the matter to FERC for further process, the timing and outcome of which is unknown. Although any potential impact to Fortis is uncertain, every 10-basis point change in ROE at ITC impacts Fortis' annual EPS by approximately $0.01.

*Transmission Incentives:* In 2021, FERC issued a supplemental NOPR on transmission incentives modifying the proposal in the initial NOPR released by FERC in 2020. The supplemental NOPR proposes to eliminate the 50-basis point RTO ROE incentive adder for RTO members that have been members for longer than three years. The timing and outcome of this proceeding is unknown.

**UNS Energy**

*TEP General Rate Application:* In June 2022, TEP filed a general rate application with the ACC requesting new rates effective September 1, 2023 using a December 31, 2021 test year. The application reflects a US$136 million net increase in non-fuel and fuel-related revenue, as well as proposals to eliminate certain adjustor mechanisms, and modify an existing adjustor to provide more timely recovery of clean energy investments. The timing and outcome of this proceeding is unknown.

**Central Hudson**

*CIS Implementation:* In December 2022, the PSC released a report into the deployment by Central Hudson of its new CIS. The PSC also issued an Order to Commence Proceeding and Show Cause, which directed Central Hudson to explain why the PSC should not pursue civil or administrative penalties or initiate a proceeding to review the prudence of the CIS implementation costs. Central Hudson was also required to submit a plan to eliminate bi-monthly bill estimates and to evaluate the customer impacts of such a change. Central Hudson's response was filed in January 2023. The timing and outcome of this proceeding is unknown.

**FortisBC Energy and FortisBC Electric**

*GCOC Proceeding:* In 2021, the BCUC initiated a proceeding including a review of the common equity component of capital structure and the allowed ROE. FortisBC filed a final argument with the BCUC in December 2022 and the proceeding remains ongoing, with a decision expected in the second quarter of 2023.

---

| | | |
|:---|:---|:---|
| **15** | FORTIS INC. | **DECEMBER 31, 2022** |

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------

**Management Discussion and Analysis**

**FortisAlberta**

*2023/2024 GCOC Proceeding:* In January 2022, the AUC initiated proceedings to establish the cost of capital parameters for Alberta regulated utilities for 2023 and to consider a formula-based approach to setting the allowed ROE for 2024 and beyond. In March 2022, the AUC issued a decision extending the existing allowed ROE of 8.5% using a 37% equity component of capital structure through 2023. The GCOC proceeding for 2024 and beyond remains ongoing, and a decision is expected in the third quarter of 2023.

*2023 COS Application:* In July 2022, the AUC issued a decision largely accepting the forecast requested in FortisAlberta's COS application. The associated compliance filing, including the updated 2023 revenue requirement, was approved by the AUC in December 2022.

*Third PBR Term:* In July 2021, the AUC issued a decision confirming that Alberta distribution utilities will be subject to a third PBR term commencing in 2024 with going-in rates based on the 2023 COS rebasing. The AUC also initiated a new proceeding to consider the design of the third PBR term. FortisAlberta is participating in this proceeding and a decision from the AUC is expected in 2023.

*REA Cost Recovery:* In 2021, the AUC determined that costs attributable to REAs, approximating $10 million annually, can no longer be recovered from FortisAlberta's rate payers, effective January 1, 2023. FortisAlberta filed an appeal with the Alberta Court of Appeal, asserting that the AUC erred in preventing the company from recovering these costs from its own rate payers to the extent that such costs cannot be recovered directly from REAs. The appeal was heard in December 2022, and a decision from the Court is expected in first quarter of 2023.

**FINANCIAL POSITION** 

---

| | | | |
|:---|:---|:---|:---|
| **Significant Changes between December 31, 2022 and 2021** | **Significant Changes between December 31, 2022 and 2021** | **Significant Changes between December 31, 2022 and 2021** | **Significant Changes between December 31, 2022 and 2021** |
| **Balance Sheet Account** | **Variance** | **Variance** | |
| *($ millions)* | **FX** | **Other** | **Explanation** |
| Accounts receivable and other current assets | **56** | **772** | Due to: (i) the flow through of higher energy supply costs; (ii) an increase in the fair value of energy contracts at UNS Energy; (iii) higher wholesale electricity revenue at UNS Energy; and (iv) slower collections at Central Hudson. |
| Inventories | **26** | **157** | Reflects an increase in the cost and amount of natural gas in storage. |
| Other assets | **57** | **201** | Reflects an increase in the fair value of energy contracts at UNS Energy and equity contributions associated with the Wataynikaneyap Power project. |
| Regulatory assets (current and long-term) | **87** | **333** | Due to: (i) the normal operation of rate stabilization accounts, reflecting the flow through of higher commodity costs; (ii) the deferral of incremental restoration costs associated with significant weather events; (iii) unrealized losses on natural gas derivatives at FortisBC Energy; and (iv) higher energy management costs to be recovered in customer rates. The increase was partially offset by the normal operation of employee future benefit deferrals. |
| Property, plant and equipment, net | **1722** | **2125** | Due to capital expenditures, partially offset by depreciation. |
| Intangible assets, net | **71** | **134** | Largely reflects investment in land rights and computer software at UNS Energy, partially offset by amortization. |
| Goodwill | **744** | **—** |  |
| Accounts payable & other current liabilities | **90** | **628** | Due to: (i) higher energy supply costs; (ii) an increase in trade accounts payable, reflecting the timing of payments; (iii) higher income taxes payable; and (iv) an decrease in the fair value of natural gas derivatives at FortisBC Energy. |
| Other liabilities | **57** | **(320)** | Reflects a decrease in employee future benefit liabilities driven by higher discount rates. |
| Regulatory liabilities (current and long-term) | **157** | **536** | Reflects unrealized gains on energy contracts at UNS Energy, which are utilized to reduce exposure to changes in energy prices, and the normal operation of rate stabilization accounts and employee future benefit and future cost of removal deferrals. |

---

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| | | |
|:---|:---|:---|
| **16** | FORTIS INC. | **DECEMBER 31, 2022** |

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------

**Management Discussion and Analysis**

---

| | | | |
|:---|:---|:---|:---|
| **Significant Changes between December 31, 2022 and 2021** | **Significant Changes between December 31, 2022 and 2021** | **Significant Changes between December 31, 2022 and 2021** | **Significant Changes between December 31, 2022 and 2021** |
| **Balance Sheet Account** | **Variance** | **Variance** | |
| *($ millions)* | **FX** | **Other** | **Explanation** |
| Deferred income tax liabilities | **154** | **279** | Due to higher temporary differences associated with ongoing capital investment. |
| Long-term debt (including current portion) | **1190** | **1887** | Reflects debt issuances partially offset by debt repayments, and higher borrowings under committed credit facilities, in support of the Corporation's Capital Plan. |
| Shareholders' equity | **983** | **759** | Due primarily to: (i) Common Equity Earnings for 2022, less dividends declared on common shares; and (ii) the issuance of common shares, largely under the DRIP. |
| Non-controlling interests | **117** | **67** | Reflects net earnings for 2022, less dividends declared by the Corporation's subsidiaries, attributable to non-controlling interests. |

---

**LIQUIDITY AND CAPITAL RESOURCES**

**Cash Flow Requirements**

At the subsidiary level, it is expected that operating expenses and interest costs will be paid from Operating Cash Flow, with varying levels of residual cash flow available for capital expenditures and/or dividend payments to Fortis. Remaining 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 growth is generally derived from borrowings under the Corporation's committed credit facility, the operation of the DRIP and issuances of common shares, preference equity and long-term debt. The subsidiaries pay dividends to Fortis and receive equity injections from Fortis when required. Both Fortis and its subsidiaries initially borrow through their committed credit facilities and periodically replace these borrowings with long-term financing. Financing needs also arise to refinance maturing debt.

Credit facilities are syndicated primarily with large banks in Canada and the U.S., with no one bank holding more than approximately 20% of the total revolving credit facilities. Approximately $5.6 billion of the total credit facilities are committed with maturities ranging from 2023 through 2027. Available credit facilities are summarized in the following table.

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| | | | | |
|:---|:---|:---|:---|:---|
| **Credit Facilities** | | | | |
| As at December 31 | Regulated | Corporate |  |  |
| *($ millions)* | Utilities | and Other | **2022** | 2021 |
| Total credit facilities <sup>(1)</sup> | 3795 | 2055 | **5850** | 4846 |
| Credit facilities utilized: |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Short-term borrowings | (253) |  | **(253)** | (247) |
| &nbsp;&nbsp;&nbsp;&nbsp;Long-term debt (including current portion) | (922) | (735) | **(1657)** | (1305) |
| Letters of credit outstanding | (76) | (52) | **(128)** | (115) |
| **Credit facilities unutilized** | 2544 | 1268 | **3812** | 3179 |

---

<sup>(1)</sup> *Additional information about the Corporation's credit facilities is provided in Note 14 in the 2022 Annual Financial Statements*

In 2022, Central Hudson increased its available credit facilities from US$230 million to US$320 million.

In May 2022, the Corporation amended its unsecured $1.3 billion revolving term committed credit facility agreement to extend the maturity to July 2027, and to establish a sustainability-linked loan structure based on the Corporation's achievement of targets for diversity on the Board and Scope 1 GHG emissions for 2022 through 2025. Maximum potential annual margin pricing adjustments are +/- 5 basis points and +/- 1 basis point for drawn and undrawn funds, respectively.

Also in May 2022, the Corporation entered into an unsecured US$500 million non-revolving term credit facility. The facility has an initial one-year term, is repayable at any time without penalty, provides the Corporation with additional, cost effective short-term financing and liquidity, and enhances financial flexibility.

---

| | | |
|:---|:---|:---|
| **17** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

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.

As at December 31, 2022, consolidated fixed-term debt maturities/repayments are expected to average $1,437 million annually over the next five years and approximately 73% of the Corporation's consolidated long-term debt, excluding credit facility borrowings, had maturities beyond five years.

In November 2022, Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts, or debt securities in an aggregate principal amount of up to $2.0 billion. As at December 31, 2022, $2.0 billion remained available under the short-form base shelf prospectus.

Fortis is well positioned with strong liquidity. 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 currently expect to continue to have reasonable access to long-term capital in 2023.

Fortis and its subsidiaries were in compliance with debt covenants as at December 31, 2022 and are expected to remain compliant in 2023.

---

| | | | |
|:---|:---|:---|:---|
| **Cash Flow Summary** | | | |
| **Summary of Cash Flows** | | | |
| Years ended December 31 |  |  |  |
| *($ millions)* | **2022** | 2021 | Variance |
| Cash and cash equivalents, beginning of year | **131** | 249 | (118) |
| Cash from (used in): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating activities | **3074** | 2907 | 167 |
| &nbsp;&nbsp;&nbsp;&nbsp;Investing activities | **(4059)** | (3488) | (571) |
| &nbsp;&nbsp;&nbsp;&nbsp;Financing activities | **1035** | 451 | 584 |
| Effect of exchange rate changes on cash and cash equivalents | **28** | 12 | 16 |
| **Cash and cash equivalents, end of year** | **209** | 131 | 78 |

---

**Operating Activities**

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

**Investing Activities**

The increase in cash used in investing activities reflects higher capital expenditures in 2022, as well as the higher U.S.-to-Canadian dollar exchange rate. See "Performance at a Glance - Capital Expenditures" on page 5 and "Capital Plan" on page 21. Planned equity contributions associated with the Wataynikaneyap Power project in 2022 also impacted the use of cash as compared to the prior year.

**Financing Activities**

Cash flow related to financing activities will fluctuate largely as a result of changes in the subsidiaries' capital expenditures and the amount of Operating Cash Flow available to fund those capital expenditures, which together impact the amount of funding required from debt and common equity issuances. See "Cash Flow Requirements" on page 17.

---

| | | |
|:---|:---|:---|
| **18** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| **Debt Financing** | **Month<br>Issued** | **Interest Rate**<br>*(%)* | | **Maturity** | **Amount**<br>*($ millions)* | **Amount**<br>*($ millions)* | **Use of Proceeds** |
| **Long-Term Debt Issuances** | **Month<br>Issued** | **Interest Rate**<br>*(%)* | | **Maturity** | **Amount**<br>*($ millions)* | **Amount**<br>*($ millions)* | **Use of Proceeds** |
| Year ended December 31, 2022 | **Month<br>Issued** | **Interest Rate**<br>*(%)* |  | **Maturity** | **Amount**<br>*($ millions)* | **Amount**<br>*($ millions)* | **Use of Proceeds** |
| ***ITC*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Secured first mortgage bonds | January | 2.93 |  | 2052 | **US** | **150** | <sup>(1) (2) (3) (4)</sup> |
| &nbsp;&nbsp;&nbsp;&nbsp;Secured senior notes | May | 3.05 |  | 2052 | **US** | **75** | <sup>(1) (3) (4)</sup> |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured senior notes | September | 4.95 | <sup>(5)</sup> | 2027 | **US** | **600** | <sup>(1) (4) (6)</sup> |
| &nbsp;&nbsp;&nbsp;&nbsp;Secured first mortgage bonds | October | 3.87 |  | 2027 | **US** | **75** | <sup>(2)</sup> |
| &nbsp;&nbsp;&nbsp;&nbsp;Secured first mortgage bonds | October | 4.53 |  | 2052 | **US** | **75** | <sup>(2)</sup> |
| ***UNS Energy*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured senior notes | February | 3.25 |  | 2032 | **US** | **325** | <sup>(4) (6)</sup> |
| ***Central Hudson*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured senior notes | January | 2.37 |  | 2027 | **US** | **50** | <sup>(4) (6)</sup> |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured senior notes | January | 2.59 |  | 2029 | **US** | **60** | <sup>(4) (6)</sup> |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured senior notes | September | 5.07 |  | 2032 | **US** | **100** | <sup>(1) (4)</sup> |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured senior notes | September | 5.42 |  | 2052 | **US** | **10** | <sup>(1) (4)</sup> |
| ***FortisBC Energy*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured debentures | November | 4.67 |  | 2052 | **150** | **150** | <sup>(2)</sup> |
| ***FortisAlberta*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Senior unsecured debentures | May | 4.62 |  | 2052 | **125** | **125** | <sup>(1)</sup> |
| ***FortisBC Electric*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured debentures | March | 4.16 |  | 2052 | **100** | **100** | <sup>(1)</sup> |
| ***Newfoundland Power*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;First mortgage sinking fund bonds | April | 4.20 |  | 2052 | **75** | **75** | <sup>(1) (4) (6)</sup> |
| ***Caribbean Utilities*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured senior notes | November | 5.88 |  | 2052 | **US** | **80** | <sup>(1) (3)</sup> |
| ***Fortis*** |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Unsecured senior notes | May | 4.43 | <sup>(7)</sup> | 2029 | **500** | **500** | <sup>(4) (8)</sup> |

---

<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Repay short-term and/or credit facility borrowings*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Fund or refinance, in part or in full, a portfolio of new and/or existing eligible green projects*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Fund capital expenditures*

<sup>(4)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;General corporate purposes*

<sup>(5)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*ITC entered into interest rate swaps which reduced the effective interest rate to 3.54%. See Note 25 to the 2022 Annual Financial Statements*

<sup>(6)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Repay maturing long-term debt*

<sup>(7)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*The Corporation entered into cross-currency interest rate swaps to effectively convert the debt into US$391 million with an interest rate of 4.34%. See Note 25 to the 2022 Annual Financial Statements*

<sup>(8)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Fund the June 2022 redemption of the Corporation's $500 million, 2.85% senior unsecured notes due December 2023*

---

| | | | |
|:---|:---|:---|:---|
| **Common Equity Financing** | | | |
| **Common Equity Issuances and Dividends Paid** | **Common Equity Issuances and Dividends Paid** | **Common Equity Issuances and Dividends Paid** | **Common Equity Issuances and Dividends Paid** |
| Years ended December 31 | Years ended December 31 | Years ended December 31 | Years ended December 31 |
| *($ millions, except as indicated)* | **2022** | 2021 | Variance |
| Common shares issued: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash <sup>(1)</sup> | **53** | 60 | (7) |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-cash <sup>(2)</sup> | **366** | 358 | 8 |
| **Total common shares issued** | **419** | 418 | 1 |
| **Number of common shares issued *(# millions)*** | **7.4** | 8.0 | (0.6) |
| Common share dividends paid: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Cash | **(673)** | (608) | (65) |
| &nbsp;&nbsp;&nbsp;&nbsp;Non-cash <sup>(3)</sup> | **(364)** | (356) | (8) |
| **Total common share dividends paid** | **(1037)** | (964) | (73) |
| Dividends paid per common share *($)* | **2.17** | 2.05 | 0.12 |

---

<sup>(1)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Includes common shares issued under stock option and employee share purchase plans*

<sup>(2)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;Common shares issued under the DRIP and stock option plan*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Common share dividends reinvested under the DRIP*

---

| | | |
|:---|:---|:---|
| **19** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

On November 17, 2022 and February 9, 2023, Fortis declared a dividend of $0.565 per common share payable on March 1, 2023 and June 1, 2023, respectively. The payment of dividends is at the discretion of the Board and depends on the Corporation's financial condition and other factors.

---

| | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|
| **Contractual Obligations** | | | | | | | |
| **Contractual Obligations** | **Contractual Obligations** | **Contractual Obligations** | | | | | |
| As at December 31, 2022 |  |  |  |  |  |  |  |
| *($ millions)* | **Total** | Year 1 | Year 2 | Year 3 | Year 4 | Year 5 | Thereafter |
| Long-term debt: |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Principal <sup>(1)</sup> | **28578** | 2481 | 1434 | 518 | 2434 | 1977 | 19734 |
| &nbsp;&nbsp;&nbsp;&nbsp;Interest | **17159** | 1105 | 1056 | 1020 | 988 | 908 | 12082 |
| Finance leases <sup>(2)</sup> | **1177** | 35 | 35 | 35 | 35 | 36 | 1001 |
| Other obligations <sup>(3)</sup> | **422** | 116 | 86 | 77 | 30 | 29 | 84 |
| Other commitments: <sup>(4)</sup> |  |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas and fuel purchase obligations | **5720** | 1024 | 516 | 461 | 374 | 328 | 3017 |
| &nbsp;&nbsp;&nbsp;&nbsp;Waneta Expansion capacity agreement | **2472** | 54 | 55 | 56 | 58 | 59 | 2190 |
| &nbsp;&nbsp;&nbsp;&nbsp;Renewable power purchase agreements | **1926** | 131 | 131 | 131 | 131 | 130 | 1272 |
| &nbsp;&nbsp;&nbsp;&nbsp;Power purchase obligations | **1691** | 334 | 253 | 191 | 192 | 113 | 608 |
| &nbsp;&nbsp;&nbsp;&nbsp;ITC easement agreement | **380** | 14 | 14 | 14 | 14 | 14 | 310 |
| &nbsp;&nbsp;&nbsp;&nbsp;Debt collection agreement | **106** | 3 | 3 | 3 | 3 | 3 | 91 |
| &nbsp;&nbsp;&nbsp;&nbsp;Renewable energy credit purchase agreements | **77** | 18 | 14 | 7 | 7 | 6 | 25 |
| &nbsp;&nbsp;&nbsp;&nbsp;Other | **132** | 21 | 9 | 20 | 3 | 3 | 76 |
|  | **59840** | 5336 | 3606 | 2533 | 4269 | 3606 | 40490 |

---

<sup>(1)</sup> *Amounts not reduced by unamortized deferred financing and discount costs of $166 million. Additional information is provided in Note 14 of the 2022 Annual Financial Statements*

<sup>(2)</sup> *Additional information is provided in Note 15 of the 2022 Annual Financial Statements*

<sup>(3)</sup> *Primarily includes commitments with respect to long-term compensation and employee future benefit arrangements*

<sup>(4)</sup> *Represents unrecorded commitments. Additional information is provided in Note 26 of the 2022 Annual Financial Statements*

**Other Contractual Obligations**

The Corporation's regulated utilities are obligated to provide service to customers within their respective service territories. Capital Expenditures are forecast to be approximately $4.3 billion for 2023 and approximately $22.3 billion over the five-year 2023-2027 Capital Plan. 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. The Wataynikaneyap Partnership has loan agreements in place to finance the project during construction. In the event a lender under the loan agreements realizes security on the loans, Fortis may be required to accelerate its equity capital contributions, which may be in excess of the amount otherwise required of Fortis under the funding framework, to a maximum total funding of $235 million.

UNS Energy has joint generation performance guarantees with participants at Four Corners and Luna, with agreements expiring in 2041 and 2046, respectively, and at San Juan and Navajo through decommissioning. The participants have guaranteed that in the event of payment default, each non-defaulting participant will bear its proportionate share of expenses otherwise payable by the defaulting participant. In exchange, the non-defaulting participants are entitled to receive their proportionate share of the generation capacity of the defaulting participant. In the case of San Juan and Navajo, participants would seek financial recovery from the defaulting party. There is no maximum amount under these guarantees, except for a maximum of $339 million for Four Corners. As at December 31, 2022, there was no obligation under these guarantees.

Central Hudson is a participant in an investment with other utilities to jointly develop, own and operate electric transmission projects in New York State. Central Hudson's maximum commitment is $74 million, for which it has issued a parental guarantee. As at December 31, 2022, there was no obligation under this guarantee.

As at December 31, 2022, FortisBC Holdings Inc., a non-regulated holding company, had $142 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 $128 million as at December 31, 2022 and the unrecorded commitments in the table above, the Corporation had no off-balance sheet arrangements.

---

| | | |
|:---|:---|:---|
| **20** | FORTIS INC. | **DECEMBER 31, 2022** |

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------

**Management Discussion and Analysis**

**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.

---

| | | | | |
|:---|:---|:---|:---|:---|
| **Consolidated Capital Structure** | **2022** | **2022** | 2021 | 2021 |
| As at December 31 | *($ millions)* | *(%)* | *($ millions)* | *(%)* |
| Debt <sup>(1)</sup> | **28792** | **55.8** | 25784 | 55.2 |
| Preference shares | **1623** | **3.1** | 1623 | 3.5 |
| Common shareholders' equity and non-controlling interests <sup>(2)</sup> | **21219** | **41.1** | 19293 | 41.3 |
|  | **51634** | **100.0** | 46700 | 100.0 |

---

<sup>(1)</sup> *Includes long-term debt and finance leases, including current portion, and short-term borrowings, net of cash*

<sup>(2)</sup> *Includes shareholders equity, net of preference shares, and non-controlling interests. Non-controlling interests represented 3.5% as at December 31, 2022 (December 31, 2021 - 3.5%)*

**Outstanding Share Data**

As at February 9, 2023, the Corporation had issued and outstanding 482.2 million common shares and the following First Preference Shares: 5.0 million Series F; 9.2 million Series G; 7.7 million Series H; 2.3 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 9, 2023, an additional 2.3 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 the level of holding company debt.

---

| | | | |
|:---|:---|:---|:---|
| As at December 31, 2022 | **Rating** | **Type** | **Outlook** |
| S&P | A- | Corporate | Stable |
| | BBB+ | Unsecured debt | |
| DBRS Morningstar | A (low) | Corporate | Stable |
| | A (low) | Unsecured debt | |
| Moody's | Baa3 | Issuer | Stable |
| | Baa3 | Unsecured debt | |

---

In December 2022, S&P lowered Central Hudson's unsecured debt credit rating to BBB+ from A- and revised the rating outlook to stable from negative. S&P noted that the change was due to projected weakening in the company's financial measures due to the effects of rising inflation and higher interest rates combined with an elevated capital spending program and increasing operations and maintenance costs.

**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, to meet customer growth, and to deliver cleaner energy.

Capital Expenditures of $4.0 billion were consistent with the 2022 Capital Plan, with $600 million of capital investment focused on delivering cleaner energy to customers.

---

| | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> | **2022 Capital Expenditures** <sup>(1)</sup> |
| | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | | | |
| *($ millions, except as indicated)* | ITC | UNS<br>Energy | Central<br>Hudson | FortisBC<br>Energy | Fortis<br>Alberta | FortisBC<br>Electric | Other Electric | **Total<br>Regulated<br>Utilities** | **Non-Regulated** <sup>(2)</sup> | **Total** |
| **Total** | 1212 | 709 | 293 | 589 | 510 | 130 | 562 | **4005** | **29** | **4034** |

---

<sup>(1)</sup> *&nbsp;&nbsp;&nbsp;&nbsp;See "Non-U.S. GAAP Financial Measures" on page 14*

<sup>(2)</sup> *Energy Infrastructure segment*

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| | | |
|:---|:---|:---|
| **21** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

---

| | | | | | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|:---|
| **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> | **Forecast 2023 Capital Expenditures** <sup>(1)(2)</sup> |
| | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | **Regulated Utilities** | | | |
| *($ millions, except as indicated)* | ITC | UNS<br>Energy | Central<br>Hudson | FortisBC<br>Energy | Fortis<br>Alberta | FortisBC<br>Electric | Other Electric | **Total**<br>**Regulated**<br>**Utilities** | **Non-Regulated** | **Total** |
| **Total** | 1103 | 1006 | 384 | 536 | 556 | 132 | 579 | **4296** | **31** | **4327** |

---

<sup>(1)</sup> *Represents a forward-looking non-GAAP financial measure calculated in the same manner as Capital Expenditures. See "Non-U.S. GAAP Financial Measures" on page 14.*

<sup>(2)</sup> *Excludes the non-cash equity component of AFUDC*

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **2023-2027 Capital Plan** <sup>(1)</sup> | **2023-2027 Capital Plan** <sup>(1)</sup> | **2023-2027 Capital Plan** <sup>(1)</sup> | **2023-2027 Capital Plan** <sup>(1)</sup> | **2023-2027 Capital Plan** <sup>(1)</sup> | **2023-2027 Capital Plan** <sup>(1)</sup> | **2023-2027 Capital Plan** <sup>(1)</sup> |
| *($ billions)* | 2023 | 2024 | 2025 | 2026 | 2027 | **Total** <sup>(2) (3)</sup> |
| Five-year capital plan | 4.3 | 4.2 | 4.5 | 4.5 | 4.8 | **22.3** |

---

<sup>(1)</sup> *Capital Plan is a forward-looking non-GAAP financial measure calculated in the same manner as Capital Expenditures. See "Non-U.S. GAAP Financial Measures" on page 14*

<sup>(2)</sup> *Reflects an assumed U.S.:CAD foreign exchange rate of 1.30. On average, Fortis estimates that a five-cent increase or decrease in the U.S. dollar relative to the Canadian dollar would increase or decrease Capital Expenditures by approximately $500 million over the five-year planning period*

<sup>(3)</sup> *Excludes the non-cash equity component of AFUDC*

The 2023-2027 Capital Plan is $2.3 billion higher than the prior five-year plan that totalled $20 billion. The increase is driven by organic growth, largely reflecting regional transmission projects associated with the MISO LRTP at ITC, additional cleaner energy investments in Arizona to support TEP's planned exit from coal by 2032, and enhancements to distribution infrastructure reliability and capacity, as well as investments to support customer growth, across the Corporation's regulated utilities. Approximately $500 million of the increase is driven by a higher assumed U.S.-to-Canadian dollar exchange rate over the five-year period.

In total, Fortis expects to invest $5.9 billion in cleaner energy over the next five years. These investments will focus on connecting renewables to the grid, including Tranche 1 of MISO's LRTP, renewable and storage investments in Arizona and the Caribbean, and cleaner fuel solutions in British Columbia. The plan incorporates key customer affordability considerations, recognizing the impacts of inflation and elevated commodity costs on customer rates, while ensuring reliable and resilient energy delivery service as we transition to a cleaner energy future.

The investments included in the 2023-2027 Capital Plan are summarized as follows:

![chart-364ebca8bdcb4debbac.jpg](chart-364ebca8bdcb4debbac.jpg)

<sup>(1) &nbsp;&nbsp;&nbsp;&nbsp;</sup> *Includes clean generation and battery storage*

<sup>(2)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Includes RNG and LNG*

<sup>(3)&nbsp;&nbsp;&nbsp;&nbsp;</sup>*Includes facilities, equipment and vehicles not included in other categories*

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| | | |
|:---|:---|:---|
| **22** | FORTIS INC. | **DECEMBER 31, 2022** |

---

------

**Management Discussion and Analysis**

The Capital Plan is low risk and highly executable, with 99% of planned expenditures to occur at the regulated utilities and only 17% relating to Major Capital Projects. Geographically, 55% of planned expenditures are expected in the U.S., including 26% at ITC, with 41% in Canada and the remaining 4% in the Caribbean.

Planned Capital Expenditures are based on forecasts of energy demand as well as labour and material costs, including inflation, supply chain availability, general economic conditions, foreign exchange rates and other factors. These could change and cause actual expenditures to differ from forecast.

While global supply chain constraints and rising inflation remain issues of potential concern that continue to evolve, the Corporation does not expect a material impact on its 2023-2027 Capital Plan, although certain planned expenditures may shift within the five years. The Corporation continues to proactively work to mitigate supply chain constraints by identifying high priority materials and consolidating buying power to improve outcomes, increasing inventory levels, and closely working with suppliers to ensure material availability.

---

| | | | |
|:---|:---|:---|:---|
| **Midyear Rate Base** <sup>(1)</sup>  | **Midyear Rate Base** <sup>(1)</sup>  | **Midyear Rate Base** <sup>(1)</sup>  | **Midyear Rate Base** <sup>(1)</sup>  |
| *($ billions)* | **2022** | 2023 | 2027 |
| ITC | **10.5** | 11.1 | 14.1 |
| UNS Energy | **6.7** | 7.0 | 9.1 |
| Central Hudson | **2.6** | 2.7 | 3.6 |
| FortisBC Energy | **5.4** | 5.8 | 7.6 |
| FortisAlberta | **4.0** | 4.2 | 5.0 |
| FortisBC Electric | **1.6** | 1.7 | 2.0 |
| Other Electric | **3.3** | 3.8 | 4.7 |
| **Total** | **34.1** | 36.3 | 46.1 |

---

<sup>(1)</sup> *Simple average of Rate Base at beginning and end of the year*

Total midyear Rate Base is forecast to grow to $46.1 billion by 2027 underpinned by the five-year Capital Plan, representing a CAGR of 6.2%.

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| | | | | | |
|:---|:---|:---|:---|:---|:---|
| | | | Forecast | Forecast | |
| **Major Capital Projects** <sup>(1)</sup> | Pre- | **Actual** |  | 2024- | Expected |
| *($ millions)* | 2022 | **2022** | 2023 | 2027 | Completion |
| ITC |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;MISO LRTP |  | **—** |  | 923 | Post-2027 |
| UNS Energy |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Renewable Generation |  | **—** |  | 417 | Various |
| &nbsp;&nbsp;&nbsp;&nbsp;Vail-to-Tortolita Transmission Project | 21 | **46** | 106 | 272 | 2027 |
| FortisBC Energy |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Tilbury LNG Storage Expansion | 16 | **9** | 17 | 487 | Post-2027 |
| &nbsp;&nbsp;&nbsp;&nbsp;AMI Project |  | **3** | 11 | 410 | Post-2027 |
| &nbsp;&nbsp;&nbsp;&nbsp;Eagle Mountain Woodfibre Gas Line Project <sup>(2)</sup> |  | **—** |  | 420 | 2027 |
| &nbsp;&nbsp;&nbsp;&nbsp;Tilbury 1B Project | 29 | **11** | 27 | 316 | Post-2027 |
| &nbsp;&nbsp;&nbsp;&nbsp;Okanagan Capacity Upgrade | 16 | **3** | 12 | 188 | 2025 |
| Other Electric |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Wataynikaneyap Transmission Power Project <sup>(3)</sup> | 355 | **169** | 117 | 20 | 2024 |
| **Total** |  | **241** | 290 | 3453 |  |

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<sup>(1)</sup> *Includes applicable AFUDC*

<sup>(2)</sup> *Net of forecast customer contributions*

<sup>(3)</sup> *Fortis' share of estimated capital spending. Under the funding framework, Fortis will be funding its equity component only.*

*MISO LRTP* 

In July 2022, the MISO board approved the first tranche of projects associated with the LRTP, representing 18 transmission projects across the MISO Midwest subregion with total associated costs estimated at US$10 billion. Six of these projects run through ITC's MISO operating companies' service territories, including Michigan and Iowa, where right of first refusal provisions currently exist for incumbent transmission owners. ITC estimates transmission investments of US$1.4 billion to US$1.8 billion through 2030 associated with six of the 18 projects, with capital expenditures of approximately $900 million (US$700 million) included in the Corporation's 2023-2027 Capital Plan. Other projects within ITC's MISO service territory may be subject to competitive bidding, depending on the state in which they are located.

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| **23** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

*Renewable Generation*

Planned renewable generation investments supporting the transition to cleaner energy as outlined in TEP's 2020 IRP. Excludes energy storage investments which are not yet defined. In February 2022, the ACC acknowledged TEP's 2020 IRP, and found it to be reasonable and in the public interest.

*Vail-to-Tortolita Transmission Project*

Construction and upgrades to connect existing TEP substations to a new 230kV line within TEP's service territory. Construction is expected to begin in 2023 with an anticipated completion date of 2027.

*Tilbury LNG Storage Expansion*

This project replaces the original LNG storage tank at the Tilbury site and increases the available regasification capacity to provide backup gas supply for lower mainland customers. FortisBC Energy has filed a CPCN application for this project with the BCUC, and if approved, the project is expected to begin in 2023.

*AMI Project*

Replacement of residential and small commercial meters with advanced meters and installation of bypass valves to support the safety, resiliency, and efficient operation of the gas distribution system. FortisBC Energy has filed a CPCN application with the BCUC for this project.

*Eagle Mountain Woodfibre Gas Line Project*

Gas line expansion to a proposed LNG site in Squamish, British Columbia. In April 2022, Woodfibre LNG Limited issued a Notice to Proceed to its prime contractor with respect to the project, however, the project remains contingent on certain conditions of Woodfibre LNG Limited and on FortisBC Energy receiving the remaining regulatory and permitting approvals.

*Tilbury 1B Project*

Construction of additional liquefaction and dispensing, including on-shore piping, in support of marine bunkering and to further optimize the Tilbury Phase 1A Expansion Project. The project received an Order in Council from the Government of British Columbia in 2017. An initial project scope has been filed with regulators to support the federal impact assessment and provincial environmental assessment required to further expand the Tilbury site. Engineering design and related studies will continue in 2023.

*Okanagan Capacity Upgrade*

Construction of a new section of pipeline and associated facilities to address expected load growth in the Okanagan region. FortisBC Energy has filed a CPCN application with the BCUC for this project.

*Wataynikaneyap Transmission Power Project* 

Construction of an 1,800 kilometer, OEB-regulated transmission line to connect 17 remote First Nations communities in Northwestern Ontario to the main electricity grid, in which Fortis holds a 39% equity interest. FortisOntario is responsible for construction management and operation of the transmission line. In August 2022, Phase 1 of the project was completed, energizing the 230 kV line from Dinorwic to Pickle Lake, Ontario. As at December 31, 2022, the project was 73% complete, with 700 kilometers of transmission line energized and three First Nation communities connected to the Ontario electric grid. Construction is expected to be completed in 2024.

**Additional Investment Opportunities**

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

*Inflation Reduction Act of 2022*

In August 2022, the IRA was passed into U.S. law which included, among other items, a focus on energy security and climate change programs. With incentives and clean energy tax credits encouraging investments in clean energy, energy storage, electric vehicles and manufacturing, the IRA aligns with Fortis' cleaner energy goals and provides an opportunity for continued investment in a cleaner energy future.

*ITC - MISO LRTP*

The MISO LRTP is expected to consist of four tranches. Incremental opportunity associated the first tranche of projects is outlined above. MISO is expected to identify projects associated with the second tranche of the LRTP in the first half of 2024, which is expected to provide further investment opportunities at ITC.

*UNS Energy - TEP 2020 IRP*

The TEP 2020 IRP outlines the resource energy transition required to meet customers' energy needs through 2035 as TEP exits coal-fired resources by 2032 and replaces it with wind and solar resources. This transition is expected to reduce carbon emissions 80 percent by 2035. This plan supports reliable and affordable service from sustainable resources and is expected to provide incremental capital investment opportunity of US$2 billion to US$4 billion through 2035. The IRP may be impacted by various federal and state energy policies, including policies currently under consideration. TEP is expected to file its 2023 IRP with the ACC in the second half of 2023.

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| **24** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

*FortisBC Energy - LNG*

LNG infrastructure opportunities in British Columbia include 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 close to international shipping lanes.

With respect to further Tilbury expansion, in July 2022, FortisBC Energy's parent company, FortisBC Holdings Inc., entered into an agreement with an Indigenous community to provide the ability to participate, through equity ownership, in certain future LNG investments if the parties are able to satisfy certain obligations. Any proposed transaction is subject to regulatory approvals and certain conditions precedent.

*Other Opportunities*

Includes incremental regulated transmission investment and grid modernization projects at ITC; energy storage projects, grid modernization, infrastructure resiliency, and transmission investments at UNS Energy; further gas infrastructure opportunities at FortisBC Energy; and cleaner energy infrastructure, as well as climate change adaptation investments across our jurisdictions.

**BUSINESS RISKS**

Fortis has an ERM program that identifies and evaluates the severity and probability of risks to its business. The Fortis Board, through its audit committee, oversees Fortis' ERM program ensuring that management has an effective risk management system to support strategic planning. The ERM program at the subsidiary level is overseen by each subsidiary's board of directors and any material risks identified form part of Fortis' ERM program. Materiality thresholds are reviewed annually. Systems of internal controls are used by management to monitor and manage identified risks. A summary of the Corporation's significant business risks follows.

**Utility Regulation** 

Regulated utility assets represented approximately 99% of the Corporation's total assets as at December 31, 2022. Regulatory jurisdictions include five Canadian provinces, nine U.S. states and three Caribbean countries, as well FERC regulation for transmission assets in the U.S.

Regulators administer legislation covering material aspects of the utilities' business including: customer rates, 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 by its regulator in setting customer rates.

The ability to recover the actual cost of service and earn the approved ROE or ROA typically depends upon achieving the forecasts established in the rate-setting process. For those utilities subject to PBR mechanisms, rates reflect assumed inflation rates and productivity improvement factors, and variances therefrom could adversely affect rates of return. Failure to recover costs and/or earn a return could have a Material Adverse Effect.

For transmission operations, the underlying elements of FERC-established formula rates can be challenged by third parties which could result in rate reductions and customer refunds. These underlying elements include the ROE, ROE adders and deemed capital structure, as well as operating and capital expenditures.

In addition, the U.S. 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 U.S. federal energy matters.

While Fortis is well-positioned to maintain constructive regulatory relationships through local management teams and subsidiary board of directors comprised mostly of independent local members, it cannot predict future legislative or regulatory changes, whether caused by economic, political or other factors. The Corporation and its utilities may experience challenges and compliance costs in responding to such regulatory changes in an effective and timely manner. Any such regulatory changes or operational impacts could have a Material Adverse Effect.

**Physical Risks**

The provision of electric and gas service is subject to physical risks, including impacts from severe weather and natural disasters, wars, terrorism, vandalism, critical equipment failure and other catastrophic events within and outside the Corporation's service territories.

Certain electric utilities operate in remote or 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, hurricanes, storm surges, washouts, landslides, earthquakes, avalanches, snow or ice storms, and other acts of nature. Also, the operation of electricity transmission and distribution assets has the potential to cause fires, mainly as a result of equipment failure, falling trees or lightning strikes to lines or equipment.

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.

Accidents or natural disasters affecting any of the Corporation's electricity or gas utilities can lead to service disruption, spills and commensurate environmental liability, or other liability.

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| **25** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

Generating equipment and facilities are subject to physical risks, including equipment breakdown or damage from fire, floods or other natural disasters, that may result in the uncontrolled release of water, interruption of fuel supply, lower-than-expected operational efficiency or performance, and service disruption.

The foregoing 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.

Electricity and gas systems require ongoing maintenance, improvement and replacement. 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.

Service disruption, other effects and liability, whether caused by the failure to properly implement or complete approved maintenance and capital expenditures, severe weather or other physical risks, if not mitigated through insurance policies or the recovery of such costs in customer rates, could result in loss. Any of the foregoing potential impacts of physical risk could have a Material Adverse Effect.

The foregoing physical risks can be intensified by the "Climate Change" risks discussed below.

**Climate Change**

*Climate-Related Physical Risk*

Climate change may negatively impact the ability to provide reliable and safe electric and gas service. The changing climate is predicted to lead to more frequent and severe weather events which may impact or disrupt the reliability of electric or gas systems. The physical risks associated with a changing climate and more frequent and intense weather events requires the Corporation's utilities to respond to continue delivering reliable service to customers.

Severe weather impacts the Corporation's service territories, primarily in the form of thunderstorms, flooding, wildfires, hurricanes, storm surges, atmospheric rivers and snow, or ice storms. Increased frequency of extreme weather events could increase the cost of providing service through increased repairs and use of contingency plans. Extreme weather conditions and changes in air temperature require system backup and can result in system stress, including service disruptions, and decreased efficiency of operating facilities over time. 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.

Longer-term climate change impacts, such as sustained higher temperatures, higher sea levels, larger storm surges and floods, could result in service disruption, shortened asset life, increased repair and replacement costs, and costs associated with strengthened design standards and systems. The impacts of climate change can intensify the "Physical Risks" described on page 25.

The physical risks posed by the impacts of climate change and 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-Related Transition Risk*

As economies transition toward decarbonization and increase renewable energy use under various national and international commitments, risks arise related to associated policy, legal, technological and market changes, which may have related capital and financial implications for the Corporation and its utilities.

The impacts of the transition to a cleaner energy future will require the Corporation's utilities to effectively manage, among other things, evolving regulatory and legislative requirements, new resiliency standards, the integration of new technologies and impacts on customer demand and rates. Failure to appropriately respond to climate change and decarbonize may disrupt the ability of the utilities to provide safe and cost-effective service, which could cause reputational harm and other impacts.

Fortis expects the pace of government policy and regulatory changes to accelerate in the coming years (see "Environmental Regulation" on page 27). Further, the emergence of initiatives designed to reduce GHG emissions, increase renewable energy use, and control or limit the effects of climate change has increased the incentive for the development of new technologies that produce renewable energy, enable more efficient storage of energy and reduce energy consumption. As new technologies become widely available, infrastructure design risks and time delays may emerge. Utility energy delivery systems will require technological changes and updates in order to effectively deliver increasing amounts of renewable energy to customers (see "Technology Developments" on page 28).

The availability of regulatory mechanisms or the ability of the Corporation's utilities to pass related costs on to customers remains uncertain. Regulatory lag in relation to the adoption of climate change initiatives and/or the availability of regulatory recovery mechanisms in certain jurisdictions could contribute to financial harm to Fortis and its utilities (see "Utility Regulation" on page 25).

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| **26** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

Fortis has a plan to reduce GHG direct emissions 50% by 2030 and 75% by 2035 without the use of carbon offsets or new technology. Technological advancements will be required in order for the Corporation to eliminate the last 25% of its GHG direct emissions by 2050 to achieve its net-zero target while preserving system reliability and customer affordability. In addition to the development and implementation of relevant energy technologies, the Corporation's ability to achieve its climate-related targets depends upon many factors, including the size of the Corporation's service territory, capacity needs remaining in line with current expectations, the impacts of future regulations or legislation, or the adoption of alternative energy products by the public, any of which could cause actual results and the ability to achieve such targets to materially differ from expectations. The ultimate impact of achieving or failing to achieve such targets could cause reputational damage which could result in a Material Adverse Effect.

**Growth**

Fortis has a history of both growth through acquisitions and organic growth from capital investment in existing service territories. 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 as 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 commodity price fluctuations, supply and labour costs, supply chain constraints, 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 cost overruns in customer rates, which may have a Material Adverse Effect.

**Environmental Regulation**

The Corporation's businesses are subject to environmental laws and regulations, including those which concern emissions into the air, discharges into water or soil, use of water, hazardous waste disposal and containment, and the investigation and remediation of contamination, among others.

The risk of contamination of air, soil and water associated with electricity operations 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 gas operations primarily relate to leaks and other accidents involving gas systems. The key environmental risks for hydroelectric generation operations include dam failures and the creation of artificial water flows that may disrupt natural habitats.

Failure to comply with environmental laws and regulations, or to obtain or comply with any necessary environmental permits pursuant to such laws and regulations, could result in injunctions, fines or other penalties. Further, liabilities relating to contamination investigation and remediation, and related 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, regardless of whether such contamination was caused by the business at the time it owned the property, whether it resulted from non-compliance with applicable environmental laws and regulations, or whether it resulted from any act or omission of the business. These liabilities could result in substantial monetary judgments for clean-up costs, damages, fines and/or penalties. To the extent not fully covered by insurance or through regulatory mechanisms, these foregoing costs could have a Material Adverse Effect.

Environmental laws and regulations continue to develop and may result in significant additional expense. In particular, the management of GHG emissions and related decarbonization requirements is a major concern due to new and emerging federal, state and provincial GHG laws, regulations and guidelines. Regulation and the pace of regulatory change to address reliability, resiliency, resource planning and safety is expected to increase in response to climate change. Future legislation could impact generation assets, operations, energy supply, operational costs, reporting obligations and other material aspects of the Corporation's business. Increased compliance costs or additional operating restrictions from revised or additional regulation could have a Material Adverse Effect (see "Climate Change" at page 26).

**Pandemics and Public Health Crises**

The Corporation could be negatively impacted by widespread outbreaks of communicable diseases or other public health crises that cause economic and/or other disruptions. Outbreaks of communicable diseases, as well as efforts to reduce the health impacts and control disease spread, can lead to restrictions on business operations, including business closures and the potential impacts of reduced labour availability and productivity, supply chain disruptions, project construction delays, disruptions to capital markets, governmental and regulatory action, and a prolonged reduction in economic activity. An extended economic slowdown could reduce energy sales and adversely impact the ability of customers, contractors and suppliers to fulfill their obligations and could disrupt operations and capital expenditure programs or cause impairment of goodwill (see "General Economic Conditions" on page 29).

The Corporation's utilities provide essential services and must be operational and maintained throughout any pandemic or public health crisis, though such events can challenge operations and increase operating costs. The duration and severity of a pandemic or public health crisis, could have a Material Adverse Effect.

**Health and Safety** 

The operations of the Corporation's utilities inherently involve risk to the health and safety of both employees and the public. Personal injury or loss of life could result from failure to implement or observe appropriate health and safety procedures and gives rise to operational, reputational or financial impacts, any of which could have a Material Adverse Effect. In addition, failure to comply with health and safety regulations could result in fines, penalties, reputational damage, litigation, increased capital and operating costs or adverse regulatory outcomes.

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| **27** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

**Natural Gas Competitiveness**

Approximately 23% of the Corporation's revenue is derived from the delivery of natural gas. In British Columbia, which accounts for 82% of the Corporation's natural gas revenue, natural gas primarily competes with electricity for space and hot water heating load. Upfront capital costs for gas service continue to present competitive challenges for natural gas compared to electricity service. If gas becomes less competitive due to price or other factors, such as the carbon intensity of natural gas relative to other energy sources, 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 and, in the extreme, could ultimately lead to an inability to recover the utility's cost of service through customer rates.

Government policy could further impact the competitiveness of natural gas in British Columbia. As governments develop policies to address climate change, any resultant changes to energy policy may impact the competitiveness of natural gas relative to other energy sources.

Additionally, there are other competitive challenges that are impacting the penetration of natural gas into new housing stock such as the carbon intensity of the energy source and the type of housing stock being built. As part of their own climate change policy plans, local governments may use various tools at their disposal such as franchise agreements, permits, building codes and zoning bylaws to impose limitations on energy sources permitted in new and existing developments. Municipalities can also provide incentives, such as higher density allowance, to builders to adopt carbon free energy options for their developments. These actions and policies may hinder the Corporation's ability to attract new natural gas customers or retain existing customers.

A decrease in the competitiveness of natural gas due to pricing, government policy or other factors could have a Material Adverse Effect.

**Cybersecurity and Information and Operations Technology**

As operators of critical energy infrastructure, the Corporation's utilities are at risk of cybercrime. The ability of the Corporation's utilities to operate effectively is dependent upon using and maintaining complex information systems and infrastructure that: (i) support the operation of generation, transmission and distribution facilities, including electric and gas facilities; (ii) provide customers with billing, consumption and load settlement information, where applicable; and (iii) support financial and general operations. The Corporation also engages third-party service providers to help facilitate the management of the Corporation's information security systems, communication tools and data processing.

Information and operations technology systems, including those of the Corporation's third-party service providers, may be vulnerable to unauthorized access or disruption due to cyber- and other attacks, including hacking, malware, acts of war or terrorism, and acts of vandalism, among others. Further, geopolitical conflicts may further increase the sophistication, magnitude or frequency of cyberattacks, some of which may even be initiated by nation state actors. Any such event could result in the disruption of energy service and other business operations, property damage, corruption or unavailability of critical data, and the misappropriation and/or disclosure of sensitive, confidential and proprietary business information or personal information of customers and/or employees.

A material cybersecurity breach of the Corporation's information security systems or those of a third-party service provider 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 Developments** 

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 available to customers 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.

Further, the implementation of new information technology systems into the business, including those impacting utility operations and customer billing systems, carries risk that any such system will not operate as expected. Failure to maintain, upgrade, replace or properly implement such new information technology systems could result in increased risk of a cybersecurity incident and have an adverse effect on operational efficiency, revenue or reputation (see "Cybersecurity and Information and Operations Technology" above).

**Weather Variability and Seasonality**

Electricity consumption varies significantly in response to seasonal weather changes which have been and will continue to be impacted by climate change (see "Climate Change" on page 26). 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. Hydroelectric generation is sensitive to rainfall levels and unexpected variations in seasonal rainfall levels can negatively impact operations.

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| **28** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

Weather and seasonality have a significant impact on gas distribution volumes as a major portion of natural gas is used for space heating by residential customers. The earnings of the Corporation's gas utilities are typically highest in the first and fourth quarters. 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. The absence or the discontinuance of key regulatory mechanisms could result in significant and prolonged weather variations from seasonal norms having a Material Adverse Effect.

**Required Approvals**

The acquisition, ownership and operation of electric and gas businesses require numerous licences, permits, agreements, orders, certificates, consultations, and other approvals from various levels of government, regulators, government agencies and/or other third parties. There is no assurance that: (i) such approvals 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.

**Reliability Standards**

The Energy Policy Act requires owners, operators and users of the bulk electric system in the U.S. 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 and Alberta. 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, including as a result of the exclusion of related costs from customer rates and other potentially significant penalties.

**Indigenous Peoples' Land Claims** 

In British Columbia, the Corporation's utilities provide service to customers on Indigenous Peoples' lands and maintain facilities on lands that are subject to Indigenous Peoples' land claims. Various treaty negotiation processes involving Indigenous Peoples and the Governments of British Columbia and Canada are underway, but the basis for potential settlements is unclear and not all Indigenous Peoples are participating in such processes. 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 processes will not have a Material Adverse Effect.

FortisAlberta has distribution assets on Indigenous Peoples' lands in Alberta with access permits held by a third party. Some of these permits require approvals 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.

Certain jointly owned facilities and portions of TEP's transmission lines are located on tribal lands pursuant to leases, land easements and other rights-of-way that are effective for specified time periods. The inability to receive future approvals for continued access to the facilities and land 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. A divergence in the interests of TEP and those of the joint owners or operators could have a Material Adverse Effect.

Wataynikaneyap Partnership, which is owned 51% by 24 First Nations communities and 49% by a partnership between Fortis (80%) and Algonquin Power & Utilities Corp. (20%), is 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, any of which could have a Material Adverse Effect.

**General Economic Conditions**

Fluctuations in general economic conditions, inflation, energy prices, employment levels, personal disposable incomes, housing starts, industrial activity and other factors may lower energy demand and reduce sales and reduced capital spending, particularly to the extent that related customer and Rate Base growth are impacted. A severe and prolonged economic downturn could also impair customers' ability to pay their bills in a timely manner. Each of these factors could lead to the impairment of goodwill or other long-term assets, and could have a Material Adverse Effect. Further, the impact of macroeconomic factors, including, but not limited to, international relations and geopolitical events, could cause weaker economic conditions or increase the volatility of the equity capital markets, which could impact the business and financial condition of the Corporation or adversely impact the Corporation's share price.

**Commodity Price Volatility**

Purchased power and gas, 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; and (ii) price-risk management strategies such as the use of derivative contracts that effectively fix costs (see "Financial Instruments - Derivatives" on page 35).

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| **29** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

There is no assurance that current regulator-approved mechanisms or strategies will continue to exist in the future. Additionally, despite these mechanisms and strategies, severe and prolonged commodity price increases could result in rates that customers are unable to pay and/or could affect consumption and sales growth, which 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 and is not being generated by the Corporation's utilities. 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 result in a loss and/or increase in the cost of purchased power and gas, which could have a Material Adverse Effect. The cost and availability of purchased power and gas may be adversely impacted by factors discussed under "Climate Change" on page 26, "Environmental Regulation" on page 27 and "Commodity Price Volatility" on page 29.

**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 MISO by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors.

FortisAlberta has a concentration of credit risk as 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.

Central Hudson has seen an increase in accounts receivable due to the suspension of collection efforts in response to the COVID-19 Pandemic, as well as higher commodity prices. Central Hudson continues to proactively contact customers regarding past-due balances to advise them of financial assistance available through federal and state programs, and collection efforts are expected to expand in 2023. Under its regulatory framework, Central Hudson can defer uncollectible write-offs that exceed 10 basis points above the amounts collected in customer rates for future recovery.

UNS Energy, Central Hudson, FortisBC Energy, Aitken Creek and Fortis may be exposed to credit risk from non-performance by counterparties to derivative contracts. 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 credit risk management strategies will continue to be effective. Significant counterparty defaults could have a Material Adverse Effect.

**Supply Chain**

Domestic and global supply chain issues may delay the delivery or result in shortages of certain materials, equipment and other resources that are critical to the operation of the Corporation's utilities. Failure to eliminate or manage the constraints in the supply chain may impact the availability of items that are necessary to support operations as well as materials that are required for continued infrastructure growth and could have a Material Adverse Effect.

**Interest Rates** 

Generally, 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. While a rising interest environment could result in higher allowed ROEs, such ROE changes tend to lag as a result of regulatory timelines. Borrowings under variable-rate credit facilities and long-term debt, as well as new debt issuances, are also exposed to interest rate changes. Although interest costs at the regulated utilities are generally recovered through customer rates, the discontinuance of regulatory mechanisms that permit the flow-through of actual interest costs, the impact of regulatory lag at UNS Energy, and higher finance costs on holding company debt could have a Material Adverse Effect.

**Foreign Exchange Exposure**

As at December 31, 2022, 67% of the Corporation's assets were located outside Canada and 59% of 2022 revenue was derived from foreign operations. The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, FortisTCI, Fortis Belize and Belize Electricity is, or is pegged to, the U.S. dollar. The earnings and cash flow from, and net investments in, these entities are exposed to fluctuations in the U.S. dollar-to-Canadian dollar exchange rate. The Corporation's $22.3 billion five-year Capital Plan for 2023 through 2027 also includes exposure to foreign exchange.

Fortis has limited its U.S. dollar currency exposure through hedging. The Corporation has issued and designated U.S. dollar-denominated long-term debt as an effective hedge of foreign net investments. Fortis has also entered into foreign exchange contracts and cross-currency swaps to manage a portion of its exposure to foreign currency risk.

Given only partial hedging, earnings and cash flow continue to be impacted by exchange rate fluctuations. In addition, there is no assurance that existing hedging strategies will continue to be effective, and therefore a significant, prolonged decrease in the U.S. dollar-to-Canadian dollar exchange rate could have a Material Adverse Effect.

**Access to Capital** 

The Corporation and certain of its subsidiaries have incurred material amounts of indebtedness. Ongoing access to cost-effective capital is required to fund, among other things, capital expenditures and the repayment of maturing debt.

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|:---|:---|:---|
| **30** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

Operating Cash Flow may not be sufficient to fund the repayment of all outstanding liabilities when due or fund 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 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, credit ratings, and the environmental, social and governance profile of Fortis and its subsidiaries. Changes in credit ratings could affect credit risk spreads on new long-term debt and credit facilities, as well as their availability.

Fortis is a holding company and, as such, has no revenue-generating operations of its own. The Corporation's subsidiaries are separate legal entities and have no independent obligation to pay dividends to Fortis. Prior to paying dividends to the Corporation, the subsidiaries have financial obligations that must be satisfied, including, among others, their operating expenses and obligations to creditors. Furthermore, the Corporation's utilities are required by regulation to maintain a minimum equity-to-total capital ratio that may restrict their ability to pay dividends to the Corporation or may require the Corporation to contribute capital to such subsidiaries. The future enactment of laws or regulations may prohibit or further restrict the ability of the Corporation's subsidiaries to pay dividends or to repay intercorporate indebtedness. In addition, in the event of a subsidiary's liquidation or reorganization, the Corporation's right to participate in a distribution of assets is subject to the prior claims of the subsidiary's creditors. As a result, the Corporation's ability to generate cash flow to service its debt obligations is reliant on the ability of its subsidiaries to generate sustained earnings and cash flows and to pay dividends and repay loans.

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 17.

**Taxation**

Earnings at Fortis and its subsidiaries could be impacted by changes in income tax rates and other tax legislation in Canada, the U.S. and other international jurisdictions. The nature, timing or impact of changes in tax laws cannot be predicted and could have a Material Adverse Effect. Although income taxes at the regulated utilities are generally recovered in customer rates, tax-related regulatory lag can result in recovery delays or non-recovery for certain periods. 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.

**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 to insure such assets 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 losses from actual damage, liabilities or business interruption will be fully covered by insurance; (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 in insurance coverage or claims payment could have a Material Adverse Effect. The availability and cost of certain types of insurance may be adversely impacted by the risks described under "Climate Change" on page 26.

**Talent Management**

The delivery of safe, reliable and cost-effective service depends on the attraction, development and retention of a skilled workforce as well as filling strategic positions. Like its peers, Fortis faces demographic challenges and competitive markets relating to trades, technical and professional staff, particularly considering its significant 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. Significant failures in attracting or retaining a skilled workforce or filling strategic positions within the Corporation or its utilities 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 regulators may not allow full recovery in customer rates, and could have a Material Adverse Effect.

**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. Regulatory deferral mechanisms are in place at many of the Corporation's utilities that permit the flow through in customer rates of certain impacts associated with market fluctuations. Severe and prolonged market disruptions, significant declines in the market values of investments held to meet plan obligations, discount rate changes, participant demographics, changes in laws and regulations, as well as changes in existing regulatory treatment of post-retirement benefit costs, may increase plan expenses or require additional plan funding and could have a Material Adverse Effect.

**Political Environment**

The political environment, at the local, national or global level, may impact energy laws, governmental energy policies or regulatory decisions. For example, political pressure or intervention to address rising energy prices and customer affordability concerns may impact regulatory decisions, as well as the period over which the Corporation's utilities recover allowed costs.

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|:---|:---|:---|
| **31** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

The business is further exposed to risks associated with international relations and geopolitical events. Political, economic or social instability or events, trade disputes, increased tariffs, changes in laws or the imposition of onerous regulations applicable to existing operations, currency restrictions, and the impacts of changes in political leadership could lead to an increase in commodity prices, impact the availability and cost of energy or generally affect global economic conditions, any of which could have a Material Adverse Effect (see "Environmental Regulation" at page 27 and "General Economic Conditions" at page 29).

**Reputation, Relationships and Stakeholder Activism**

There can be no assurance that internal processes, controls or audits will ensure compliance with the Corporation's internal policies, including its Code of Conduct, or anti-bribery and anti-corruption laws. Employees, affiliates, independent contractors or agents may violate such policies and laws, which may potentially lead to reputational damage, in addition to potential fines, penalties or litigation, any of which could have a Material Adverse Effect.

The Corporation's operations and growth prospects require strong relationships with key stakeholders, including regulators, governments and agencies, Indigenous communities, landowners, and environmental organizations. Inadequately managing expectations and issues important to stakeholders, including those arising during construction of Major Capital Projects, could affect the Corporation's reputation as well as have a significant impact on its operations and infrastructure development. See "Required Approvals" and "Indigenous Land Claims" at page 29.

External stakeholders are increasingly challenging companies regarding climate change, sustainability, diversity, returns (including ROEs and ROAs), 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 manage or respond to stakeholder activism could have a Material Adverse Effect.

**Legal, Administrative and Other Proceedings**

Legal, administrative and other 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**

**Critical Accounting Estimates**

*General*

The preparation of the 2022 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, 2022, Fortis recognized regulatory assets of $4.0 billion (2021 - $3.6 billion) and regulatory liabilities of $3.9 billion (2021 - $3.2 billion).

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

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. There is no assurance that actual settlement amounts and the related settlement periods will not be materially different from those estimated. 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.

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| **32** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

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| | | | | |
|:---|:---|:---|:---|:---|
| *Employee Future Benefits* |  |  |  |  |
| **Key Estimates and Assumptions** | **Defined Benefit**<br>**Pension Plans** | **Defined Benefit**<br>**Pension Plans** | **OPEB Plans** | **OPEB Plans** |
| Years ended December 31 | **Defined Benefit**<br>**Pension Plans** | **Defined Benefit**<br>**Pension Plans** | **OPEB Plans** | **OPEB Plans** |
| *($ millions, except as indicated)* | **2022** | 2021 | **2022** | 2021 |
| Funded status: <sup>(1)</sup> |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Benefit obligation <sup>(2)</sup> | **(3063)** | (3922) | **(582)** | (747) |
| &nbsp;&nbsp;&nbsp;&nbsp;Plan assets | **3079** | 3722 | **389** | 440 |
|  | **16** | (200) | **(193)** | (307) |
| Net benefit cost <sup>(2)</sup>  | **19** | 64 | **26** | 35 |
| Key assumptions: *(weighted average %)* |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Discount rate: <sup>(3)</sup> |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;During the year | **2.97** | 2.60 | **2.97** | 2.60 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;As at December 31 | **5.27** | 3.00 | **5.36** | 2.97 |
| &nbsp;&nbsp;&nbsp;&nbsp;Expected long-term rate of return on plan assets <sup>(4)</sup> | **5.87** | 5.40 | **5.00** | 4.88 |
| &nbsp;&nbsp;&nbsp;&nbsp;Rate of compensation increase | **3.33** | 3.30 | **—** |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Health care cost trend increase rate <sup>(5)</sup> | **—** |  | **4.48** | 4.49 |

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<sup>(1)</sup> *Periodic actuarial valuations determine funding contributions for the pension plans and U.S. OPEB plans, while Canadian OPEB plans are unfunded*

<sup>(2)</sup> *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*

<sup>(3)</sup> *Reflects market interest rates on high-quality bonds with cash flows that match the timing and amount of expected pension payments*

<sup>(4)</sup> *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*

<sup>(5)</sup> *Actuarially determined, the projected 2023 rate is 6.17% and is assumed to decrease over the next 12 years to the ultimate rate of 4.48% in 2034 and thereafter*

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| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Sensitivity Analysis** | **Rate of Return** | **Rate of Return** | **Discount Rate** | **Discount Rate** | **Health Care Costs<br>Trend Rate** | **Health Care Costs<br>Trend Rate** |
| Year ended December 31, 2022 | **1% change** | **1% change** | **1% change** | **1% change** | **1% change** | **1% change** |
| *($ millions)* | **Increase** | **Decrease** | **Increase** | **Decrease** | **Increase** | **Decrease** |
| **Defined benefit pension plans:** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net benefit cost | **(33)** | **27** | **(35)** | **62** | **n/a** | **n/a** |
| &nbsp;&nbsp;&nbsp;&nbsp;Projected benefit obligation | **17** | **(49)** | **(337)** | **401** | **n/a** | **n/a** |
| **OPEB plans:** |  |  |  |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Net benefit cost | **(5)** | **5** | **(12)** | **12** | **17** | **(13)** |
| &nbsp;&nbsp;&nbsp;&nbsp;Accumulated benefit obligation | **—** | **—** | **(70)** | **85** | **64** | **(57)** |

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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.

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.

*Depreciation and Amortization*

As at December 31, 2022, Fortis recognized property, plant and equipment and intangible assets of $43.2 billion (2021 - $39.2 billion) representing 67% of total assets (2021 - 68%). Depreciation and amortization of these assets totalled $1.6 billion for 2022 (2021 - $1.4 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 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, 2022, this regulatory liability was $1.3 billion (2021 - $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.

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| **33** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

*Goodwill Impairment*

As at December 31, 2022, Fortis recognized goodwill of $12.5 billion (2021 - $11.7 billion), representing 19% of total assets (2021 - 20%). The increase in goodwill was due to the impact of foreign exchange associated with the translation of U.S. dollar-denominated goodwill.

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

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

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, 2022, deferred income tax liabilities, current income tax payable included in accounts payable, deferred income taxes included in regulatory assets, and deferred income taxes included in regulatory liabilities totalled $4.1 billion, $88 million, $1.9 billion and $1.4 billion, respectively (2021 - $3.6 billion, $31 million, $1.8 billion and $1.3 billion, respectively). Income tax expense was $289 million in 2022 (2021 - $234 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 and liabilities reflect temporary differences between the tax and accounting basis of assets and 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. A valuation allowance is recognized in earnings to the extent that future tax recovery is not assessed as "more likely than not".

At the regulated utilities, differences between the income tax expense or recovery recognized under U.S. GAAP and reflected in customer rates, which is expected to be recovered from, or refunded to, customers in future rates, are recognized as regulatory assets or liabilities. These 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.

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, British Columbia and Alberta). The Corporation's 2018 to 2022 taxation years are still open for audit in Canadian jurisdictions, and its 2018 to 2022 taxation years are still open for audit in U.S. jurisdictions. The impact of such income tax compliance examinations could be material to the Corporation's financial statements (see "Business Risks - Taxation" on page 31).

In August 2022, the IRA was passed into U.S. law. The legislation will be funded, in part, by the introduction of a new 15% corporate alternative minimum income tax, effective for tax years beginning after December 31, 2022. While this tax is expected to be applicable to Fortis, the Corporation does not currently expect it to have a material impact on its financial results, Operating Cash Flow or credit ratings.

In November 2022, the Department of Finance Canada released revised draft legislation which included a proposal on interest deductibility. It is unknown when the legislation may be enacted. In addition, the 2021 Canadian federal budget included proposed changes in relation to international taxation. There has been no significant update on this proposal, and it is unknown when draft legislation may be available. Changes in tax legislation could affect the results of operations, financial condition and cash flows of the Corporation as discussed under "Business Risks - Taxation" on page 31. Fortis will continue to assess the impacts as more details on the tax proposals become available.

*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.

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|:---|:---|:---|
| **34** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

*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 - Legal, Administrative and Other Proceedings" on page 32, for which no amounts have been accrued because the outcomes currently cannot be reasonably determined. Further information is provided in Note 26 in the 2022 Annual Financial Statements.

**FINANCIAL INSTRUMENTS**

**Long-Term Debt and Other**

As at December 31, 2022, the carrying value of long-term debt, including the current portion, was $28.6 billion (2021 - $25.5 billion) compared to an estimated fair value of $25.8 billion (2021 - $28.8 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**

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

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

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, 2022, unrealized losses of $84 million (2021 - $20 million) were recognized as regulatory assets and unrealized gains of $224 million (2021 - $52 million) were recognized as regulatory liabilities.

*Energy contracts not subject to regulatory deferral* 

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

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

Unrealized gains or losses associated with changes in the fair value of these energy contracts are recognized in revenue. In 2022, unrealized gains of $34 million (2021 - $21 million) were recognized in revenue.

*Total return swaps* 

The Corporation holds total return swaps to manage the cash flow risk associated with forecast future cash settlements of certain stock-based compensation obligations. The swaps have a combined notional amount of $114 million and terms of one to three years expiring at varying dates through January 2025. Fair value is measured using an income valuation approach based on forward pricing curves. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. In 2022, unrealized losses of $22 million (2021 - unrealized gains of $17 million) were recognized in other income, net.

*Foreign exchange contracts* 

The Corporation holds U.S. dollar-denominated foreign exchange contracts to help mitigate exposure to foreign exchange rate volatility. The contracts expire at varying dates through May 2024 and have a combined notional amount of $352 million. Fair value was measured using independent third-party information. Unrealized gains and losses associated with changes in fair value are recognized in other income, net. In 2022, unrealized losses of $9 million (2021 - $11 million) were recognized in other income, net.

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| **35** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

*Interest rate swaps*

ITC entered into forward-starting interest rate swaps to manage the interest rate risk associated with planned borrowings. The swaps, which had a combined notional value of US$450 million, were terminated in September 2022 with the issuance of US$600 million senior notes and realized gains of $52 million (US$39 million) were recognized in other comprehensive income, which will be reclassified to earnings as a component of interest expense over five years.

*Cross-Currency interest rate swaps*

In May 2022, the Corporation entered into cross-currency interest rate swaps with a 7-year term to effectively convert its $500 million, 4.43% unsecured senior notes to US$391 million, 4.34% debt. The Corporation designated this notional U.S. debt as an effective hedge of its foreign net investments and unrealized gains and losses associated with exchange rate fluctuations on the notional U.S. debt are recognized in other comprehensive income, consistent with the translation adjustment related to the net investments. Other changes in the fair value of the swaps are also recognized in other comprehensive income but are excluded from the assessment of hedge effectiveness. Fair value is measured using a discounted cash flow method based on SOFR rates. In 2022, unrealized losses of $17 million were recorded in other comprehensive income.

*Other investments*

UNS Energy holds investments in money market accounts, and ITC and Central Hudson hold investments in trust associated with supplemental retirement benefit plans for select employees, which include mutual funds and money market accounts. These investments are recorded at fair value based on quoted market prices in active markets. Gains and losses are recognized in other income, net. In 2022, unrealized losses of $11 million (2021 - unrealized gains of $5 million) were recognized in other income, net.

**Derivative Fair Values**

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

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| | | | | |
|:---|:---|:---|:---|:---|
| *($ millions)* | **Level 1** <sup>(1)</sup> | **Level 2** <sup>(1)</sup> | **Level 3** <sup>(1)</sup> | **Total** |
| **As at December 31, 2022** |  |  |  |  |
| **Assets** <sup>(2)</sup> |  |  |  |  |
| Energy contracts subject to regulatory deferral | **—** | **304** | **—** | **304** |
| Energy contracts not subject to regulatory deferral | **—** | **49** | **—** | **49** |
| Other investments | **150** | **—** | **—** | **150** |
|  | **150** | **353** | **—** | **503** |
| **Liabilities** <sup>(3)</sup> |  |  |  |  |
| Energy contracts subject to regulatory deferral | **—** | **(164)** | **—** | **(164)** |
| Energy contracts not subject to regulatory deferral | **—** | **(8)** | **—** | **(8)** |
| Foreign exchange contracts, total return and cross-currency interest rate swaps | **—** | **(26)** | **—** | **(26)** |
|  | **—** | **(198)** | **—** | **(198)** |
| As at December 31, 2021 |  |  |  |  |
| **Assets** <sup>(2)</sup> |  |  |  |  |
| Energy contracts subject to regulatory deferral |  | 78 |  | 78 |
| Energy contracts not subject to regulatory deferral |  | 16 |  | 16 |
| Foreign exchange contracts, total return and interest rate swaps | 23 | 2 |  | 25 |
| Other investments | 137 |  |  | 137 |
|  | 160 | 96 |  | 256 |
| **Liabilities** <sup>(3)</sup> |  |  |  |  |
| Energy contracts subject to regulatory deferral |  | (46) |  | (46) |
| Energy contracts not subject to regulatory deferral |  | (3) |  | (3) |
|  |  | (49) |  | (49) |

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

<sup>(2)</sup> *Included in cash and cash equivalents, accounts receivable and other current assets or other assets*

<sup>(3)</sup> *Included in accounts payable and other current liabilities or other liabilities*

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| **36** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

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| | | |
|:---|:---|:---|
| **Derivative Volumes** | | |
| As at December 31 | **2022** | 2021 |
| **Energy contracts subject to regulatory deferral** <sup>(1)</sup> |  |  |
| Electricity swap contracts *(GWh)* | **586** | 509 |
| Electricity power purchase contracts *(GWh)* | **224** | 731 |
| Gas swap contracts *(PJ)* | **185** | 151 |
| Gas supply contract premiums *(PJ)* | **148** | 144 |
| **Energy contracts not subject to regulatory deferral** <sup>(1)</sup> |  |  |
| Wholesale trading contracts *(GWh)* | **1886** | 1886 |
| Gas swap contracts *(PJ)* | **34** | 29 |

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<sup>(1)</sup> *Energy contracts settle on various dates through 2029*

**SELECTED ANNUAL FINANCIAL INFORMATION**

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| | | | |
|:---|:---|:---|:---|
| Years ended December 31 |  |  |  |
| *($ millions, except as indicated)* | **2022** | 2021 | 2020 |
| Revenue | **11043** | 9448 | 8935 |
| Net earnings  | **1514** | 1405 | 1389 |
| Common Equity Earnings | **1330** | 1231 | 1209 |
| EPS: *($)* |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Basic | **2.78** | 2.61 | 2.60 |
| &nbsp;&nbsp;&nbsp;&nbsp;Diluted | **2.78** | 2.61 | 2.60 |
| Total assets  | **64252** | 57659 | 55481 |
| Long-term debt (excluding current portion)  | **25931** | 23707 | 23113 |
| Dividends declared: *($)* |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Per common share | **2.200** | 2.080 | 1.965 |
| &nbsp;&nbsp;&nbsp;&nbsp;Per first preference share: |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Series F | **1.2250** | 1.2250 | 1.2250 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Series G | **1.0983** | 1.0983 | 1.0983 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Series H <sup>(1)</sup> | **0.4588** | 0.4588 | 0.5003 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Series I <sup>(2)</sup> | **0.9157** | 0.3926 | 0.4987 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Series J | **1.1875** | 1.1875 | 1.1875 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Series K | **0.9823** | 0.9823 | 0.9823 |
| &nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;Series M | **0.9783** | 0.9783 | 0.9783 |

---

<sup>(1)</sup> *The annual dividend per share was reset to $0.4588 for the five-year period from June 1, 2020 up to but excluding June 1, 2025*

<sup>(2)</sup> *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*

2022/2021

For a discussion of the changes in revenue, net earnings, Common Equity Earnings, EPS, total assets and long-term debt see "Performance at a Glance" on page 3, "Operating Results" on page 9, and "Financial Position" on page 16.

**2021/2020**

The increase in revenue was due primarily to: (i) higher flow-through costs in customer rates; (ii) Rate Base growth; (iii) new customer rates, effective January 1, 2021 and higher wholesale sales at TEP; and (iv) higher retail electricity sales, primarily in Western Canada and the Caribbean, partially offset by lower sales in Arizona due to unfavourable weather. The increase in revenue was partially offset by an unfavourable foreign exchange impact of $345 million and a $40 million favourable base ROE adjustment recognized at ITC in 2020 as a result of the May 2020 FERC decision.

Common Equity Earnings increased by $22 million compared to 2020. Growth in Common Equity Earnings was tempered by the unfavourable impact of foreign exchange of $48 million, and significant one-time items recognized in 2020 of $14 million. The significant items in 2020 included an adjustment to ITC's base ROE, partially offset by the finalization of U.S. tax reform. These impacts were partially offset by unrealized mark-to-market gains of $12 million in 2021 on natural gas derivatives at Aitken Creek.

---

| | | |
|:---|:---|:---|
| **37** | FORTIS INC. | **DECEMBER 31, 2022** |

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------

**Management Discussion and Analysis**

Excluding the impact of the above noted items, the Corporation delivered higher earnings of $72 million reflecting: (i) Rate Base growth; (ii) higher earnings in Arizona primarily due to new customer rates at TEP effective January 1, 2021, partially offset by lower sales due to unfavourable weather and higher operating costs; (iii) continued recovery in the Caribbean from economic conditions experienced in 2020 associated with the COVID-19 Pandemic; and (iv) higher sales at FortisAlberta associated with favourable weather, partially offset by a higher effective income tax rate. This growth was partially offset by lower hydroelectric production in Belize, and lower earnings at Aitken Creek due to realized losses on natural gas contracts.

In addition to the above-noted items impacting earnings, the change in EPS reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

The increase in total assets was due to capital expenditures in 2021 as well as an increase in employee future benefit balances, driven by higher discount rates, partially offset by unfavourable foreign exchange on the translation of U.S. dollar-denominated assets.

**FOURTH QUARTER RESULTS**

---

| | | | |
|:---|:---|:---|:---|
| **Sales** | | | |
| *(GWh, except as indicated)* | **2022** | 2021 | Variance |
| **Regulated Utilities** |  |  |  |
| UNS Energy |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Retail Electricity | **2264** | 2206 | 58 |
| &nbsp;&nbsp;&nbsp;&nbsp;Wholesale Electricity | **1247** | 1749 | (502) |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas *(PJ)* | **5** | 5 |  |
| Central Hudson |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Electricity | **1158** | 1203 | (45) |
| &nbsp;&nbsp;&nbsp;&nbsp;Gas *(PJ)* | **8** | 6 | 2 |
| FortisBC Energy *(PJ)* | **75** | 74 | 1 |
| FortisAlberta | **4200** | 4147 | 53 |
| FortisBC Electric  | **967** | 927 | 40 |
| Other Electric | **2443** | 2449 | (6) |
| **Non-Regulated**  |  |  |  |
| Energy Infrastructure | **83** | 13 | 70 |

---

The decrease in electricity sales was driven by UNS Energy due to lower wholesale electricity sales, partially offset by higher retail electricity sales due to favourable weather and customer growth. The decrease was partially offset by higher electricity sales in: (i) Fortis Belize, due to higher hydroelectric production associated with rainfall levels; and (ii) FortisAlberta, due to higher load from industrial customers and higher average consumption by residential customers.

The increase in gas sales was driven by Central Hudson due to higher average consumption by commercial and industrial customers.

---

| | | | | | | |
|:---|:---|:---|:---|:---|:---|:---|
| **Revenue and Common Equity Earnings** | **Revenue** | **Revenue** | **Revenue** | **Earnings** | **Earnings** | **Earnings** |
| *($ millions, except as indicated)* | **2022** | 2021 | Variance | **2022** | 2021 | Variance |
| **Regulated Utilities** |  |  |  |  |  |  |
| ITC | **500** | 418 | 82 | **126** | 103 | 23 |
| UNS Energy | **716** | 540 | 176 | **45** | 33 | 12 |
| Central Hudson | **396** | 283 | 113 | **37** | 39 | (2) |
| FortisBC Energy | **725** | 592 | 133 | **84** | 78 | 6 |
| FortisAlberta | **169** | 156 | 13 | **34** | 23 | 11 |
| FortisBC Electric | **136** | 133 | 3 | **14** | 14 |  |
| Other Electric | **448** | 401 | 47 | **40** | 29 | 11 |
| **Non-regulated** |  |  |  |  |  |  |
| Energy Infrastructure | **78** | 60 | 18 | **49** | 40 | 9 |
| Corporate and Other | **—** |  |  | **(59)** | (31) | (28) |
| **Total** | **3168** | 2583 | 585 | **370** | 328 | 42 |
| Weighted average number of common shares outstanding *(# millions)* | Weighted average number of common shares outstanding *(# millions)* | Weighted average number of common shares outstanding *(# millions)* | Weighted average number of common shares outstanding *(# millions)* | **481.1** | 473.7 | 7.4 |
| Basic EPS *($)* |  |  |  | **0.77** | 0.69 | 0.08 |

---

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| | | |
|:---|:---|:---|
| **38** | FORTIS INC. | **DECEMBER 31, 2022** |

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------

**Management Discussion and Analysis**

The increase in revenue was due primarily to: (i) higher flow-through costs in customer rates, driven by higher commodity prices; (ii) Rate Base growth; (iii) higher wholesale and transmission revenue, as well as retail electricity sales at UNS Energy; and (iv) favourable foreign exchange of $106 million.

The increase in Common Equity Earnings was driven by: (i) Rate Base growth; (ii) higher retail electricity sales and transmission revenue at UNS Energy; (iii) higher earnings from the energy infrastructure segment driven by hydroelectric production in Belize, as well as the favourable impact of market conditions at Aitken Creek; and (iv) the timing of expenses at FortisAlberta. The translation of U.S. dollar-denominated subsidiary earnings at the higher U.S.-to-Canadian dollar foreign exchange rate and lower stock based compensation costs also contributed to results with these impacts exceeding the related losses associated with hedging activities. The increase in earnings was partially offset by higher corporate costs, reflecting higher finance costs and a lower income tax recovery, as well as lower earnings at Central Hudson, reflecting the finalization of the company's rate application in late 2021 with retroactive application to July 1, 2021.

The increase in basic EPS reflects higher Common Equity Earnings, as discussed above, partially offset by an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

---

| | | | |
|:---|:---|:---|:---|
| **Cash Flows** | | | |
| *($ millions)* | **2022** | 2021 | Variance |
| Cash and cash equivalents, beginning of period | **395** | 225 | 170 |
| Cash from (used in): |  |  |  |
| &nbsp;&nbsp;&nbsp;&nbsp;Operating activities | **869** | 717 | 152 |
| &nbsp;&nbsp;&nbsp;&nbsp;Investing activities | **(1152)** | (985) | (167) |
| &nbsp;&nbsp;&nbsp;&nbsp;Financing activities | **103** | 174 | (71) |
| Effect of exchange rate changes on cash and cash equivalents | **(6)** |  | (6) |
| **Cash and cash equivalents, end of period** | **209** | 131 | 78 |

---

**Operating Activities**

Operating Cash Flow increased due to: (i) higher cash earnings, reflecting Rate Base growth, as well as higher retail electricity sales and transmission revenue in Arizona; (ii) favourable changes in regulatory deferrals due to the timing of flow-through costs in customer rates, and (iii) the higher U.S.-to-Canadian dollar exchange rate. The increase was partially offset by the timing of inventory purchases at UNS Energy.

**Investing Activities**

The variance reflects higher capital expenditures in accordance with the Corporation's 2022 Capital Plan.

**Financing Activities**

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, 2022** | **3168** | **370** | **0.77** | **0.77** |
| **September 30, 2022** | **2553** | **326** | **0.68** | **0.68** |
| **June 30, 2022** | **2487** | **284** | **0.59** | **0.59** |
| **March 31, 2022** | **2835** | **350** | **0.74** | **0.74** |
| December 31, 2021 | 2583 | 328 | 0.69 | 0.69 |
| September 30, 2021 | 2196 | 295 | 0.63 | 0.62 |
| June 30, 2021 | 2130 | 253 | 0.54 | 0.54 |
| March 31, 2021 | 2539 | 355 | 0.76 | 0.76 |

---

Generally, within each calendar year, quarterly results fluctuate 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 U.S. are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.

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|:---|:---|:---|
| **39** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

Generally, from one calendar year to the next, quarterly results reflect: (i) continued organic growth driven by the Corporation's Capital Plan; (ii) any significant temperature fluctuations from seasonal norms; (iii) the timing and significance of any regulatory decisions; (iv) changes in the U.S.-to-Canadian dollar exchange rate; (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.

**December 2022/December 2021** 

See "Fourth Quarter Results" on page 38.

**September 2022/September 2021** 

Common Equity Earnings increased by $31 million and basic EPS increased by $0.05 in comparison to the third quarter of 2021 due to: (i) Rate Base growth, mainly at ITC; (ii) higher retail electricity sales, transmission revenue and earnings associated with the Oso Grande generating facility in Arizona; (iii) higher earnings from the energy infrastructure segment mainly due to mark-to-market accounting of natural gas derivatives and higher hydroelectric production in Belize; and (iv) the impact of new customer rates and the timing of operating costs at Central Hudson.

Growth was tempered by the timing of expenses in Alberta and a favourable adjustment recognized in 2021 related to interest rate swaps at ITC. Results for the third quarter of 2022 were also impacted by significant items at ITC, including costs associated with the suspension of the Lake Erie Connector project, and the revaluation of deferred income tax assets due to a reduction in the corporate income tax rate in the state of Iowa. The impact of mark-to-market losses associated with hedging activities was more than offset by lower stock-based compensation costs and the translation of U.S. dollar-denominated subsidiary earnings at the higher U.S.-to-Canadian dollar foreign exchange rate. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

**June 2022/June 2021**

Common Equity Earnings increased by $31 million and basic EPS increased by $0.05 in comparison to the second quarter of 2021 due to: (i) Rate Base growth; (ii) higher earnings from the energy infrastructure segment, largely reflecting favourable changes in the mark-to-market accounting of natural gas derivatives at Aitken Creek; and (iii) a higher U.S.-to-Canadian dollar foreign exchange rate. Growth was partially offset by losses on investments that support retirement benefits at UNS Energy and ITC, reflecting market conditions, and the timing of quarterly earnings from Arizona and Alberta. In comparison to the second quarter of 2021, results from UNS Energy were tempered, as expected, by the timing of earnings related to the Oso Grande generating facility, and earnings from FortisAlberta were lower due to the timing of operating expenses. The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

**March 2022/March 2021**

Common Equity Earnings decreased by $5 million and basic EPS decreased by $0.02 in comparison to the first quarter of 2021 due to higher unrealized losses of $14 million on the mark-to-market accounting of natural gas derivatives at Aitken Creek. Excluding this impact, the Corporation delivered earnings growth driven by Rate Base growth at ITC and the western Canadian utilities, and higher sales in the Caribbean. Growth was partially offset by lower hydroelectric production in Belize, and lower earnings at Central Hudson mainly due to the costs of implementing a new CIS.

Earnings in Arizona were broadly consistent with the first quarter of 2021. The impact of higher electricity sales and lower planned generation maintenance costs was offset by the timing of earnings related to the Oso Grande generating facility, as expected. Losses on retirement investments also unfavourably impacted earnings at UNS Energy in the quarter.

The change in basic EPS also reflected an increase in the weighted average number of common shares outstanding, largely associated with the Corporation's DRIP.

**RELATED-PARTY AND INTER-COMPANY TRANSACTIONS**

Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions in 2022 or 2021.

The lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy of $37 million in 2022 (2021 - $38 million) are inter-company transactions between non-regulated and regulated entities, which were not eliminated on consolidation.

As at December 31, 2022, accounts receivable included $7 million due from Belize Electricity (2021 - $22 million).

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| | | |
|:---|:---|:---|
| **40** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

Fortis periodically provides short-term financing to subsidiaries to support capital expenditures and seasonal working capital requirements, the impacts of which are eliminated on consolidation. As at December 31, 2022, there were no inter-segment loans outstanding (2021 - $126 million). Interest charged on inter-segment loans was not material in 2022 and 2021.

**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 U.S. securities laws. As of December 31, 2022, 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 U.S. securities laws. Based on that evaluation, the CEO and CFO concluded that such DCP are effective as of December 31, 2022.

**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, 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 U.S. 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, 2022, 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, 2022, the Corporation's ICFR was effective.

During the year ended December 31, 2022, 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**

Fortis continues to enhance shareholder value through the execution of its Capital Plan, the balance and strength of its diversified portfolio of regulated utility businesses, and growth opportunities within and proximate to its service territories. While energy price volatility, global supply chain constraints and persistent inflation are issues of potential concern that continue to evolve, the Corporation does not currently expect there to be a material impact on its operations or financial results in 2023.

Fortis is executing on the transition to a cleaner energy future and is on track to achieve its corporate-wide targets to reduce GHG emissions by 50% by 2030 and 75% by 2035. Upon achieving this target, 99% of the Corporation's assets will support energy delivery and renewable, carbon-free generation. The Corporation's additional 2050 net-zero direct GHG emissions target reinforces Fortis' commitment to decarbonize over the long-term, while preserving customer reliability and affordability.

The Corporation's $22.3 billion five-year Capital Plan is expected to increase midyear Rate Base from $34.1 billion in 2022 to $46.1 billion by 2027, translating into a five-year CAGR of 6.2%.

Beyond the five-year Capital Plan, additional opportunities to expand and extend growth include: further expansion of the electric transmission grid in the U.S. to facilitate the interconnection of cleaner energy, including infrastructure investments associated with the IRA and the MISO LRTP; climate adaptation and grid resiliency investments; renewable gas solutions and LNG infrastructure in British Columbia; and the acceleration of cleaner energy infrastructure investments across our jurisdictions.

Fortis expects its long-term growth in Rate Base will drive earnings that support dividend growth guidance of 4-6% annually through 2027. This dividend growth guidance will also provide flexibility to fund more capital with internally-generated funds and is premised on the assumptions and material factors listed under "Forward-Looking Information".

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|:---|:---|:---|
| **41** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

**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: forecast capital expenditures for 2023-2027, including cleaner energy investments; forecast Rate Base and Rate Base growth for 2023 and through 2027; targeted annual dividend growth through 2027; the expectation that Fortis is well-positioned to capitalize on evolving industry opportunities, including additional investment opportunities beyond the Capital Plan; the expectation that volatility in energy prices, global supply chain constraints and persistent inflation will not have a material impact on operations or financial results in 2023 or the 2023-2027 capital plan; the 2030 GHG emissions reduction target; the 2035 GHG emissions reduction target and projected asset mix; the expectation to achieve the 2030 and 2035 GHG emissions reduction targets without the use of carbon offsets; the 2050 net-zero direct GHG emissions target and how that target is expected to be achieved; TEP's IRP and the expectation to exit coal by 2032; the expected timing, outcome and impact of regulatory proceedings and decisions; the expected or potential funding sources for operating expenses, interest costs and capital expenditures; the expectation that maintaining the targeted capital structure of the regulated operating subsidiaries will not have an impact on the Corporation's ability to pay dividends in the foreseeable future; the 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 in 2023; the expected uses of proceeds from debt financings; the targeted capital structure; the nature, timing, benefits and expected costs of certain capital projects, including ITC's transmission projects associated with the MISO LRTP, renewable generation projects at UNS Energy, the Vail-to-Tortolita Transmission Project, the Tilbury LNG Storage Expansion, the AMI Project; the Eagle Mountain Woodfibre Gas Line Project, the Tilbury 1B Project, the Okanagan Capacity Upgrade, the Wataynikaneyap Transmission Power Project, and additional opportunities beyond the capital plan, including investments associated with the IRA, the MISO LRTP, TEP's IRP, climate adaptation and grid resiliency, and renewable gas solutions and LNG infrastructure in British Columbia; the expectation that the introduction of a corporate alternative minimum income tax will not have a material impact on financial results, Operating Cash Flow or credit ratings; the expectation that long-term growth in Rate Base will drive earnings that support dividend growth guidance of 4-6% annually through 2027; and the expectation that the dividend growth guidance will provide flexibility to fund more capital internally.*

*Forward-looking information involves significant risks, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information including, without limitation: no material impact from volatility in energy prices, global supply chain constraints and persistent inflation; reasonable regulatory decisions and the expectation of regulatory stability; the successful execution of the capital plan; no material capital project or financing cost overrun; sufficient human resources to deliver service and execute the capital plan; the realization of additional opportunities beyond the capital plan; no significant variability in interest rates; the Board exercising its discretion to declare dividends, taking into account the financial performance and condition of the Corporation; 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.*

*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 2023 include, but are not limited to: uncertainty regarding changes in utility regulation, including the outcome of regulatory proceedings at the Corporation's utilities; the physical risks associated with the provision of electric and gas service, which are exacerbated by the impacts of climate change; risks related to environmental laws and regulations; risks associated with capital projects and the impact on the Corporation's continued growth; risks associated with cybersecurity and information and operations technology; the impact of weather variability and seasonality on heating and cooling loads, gas distribution volumes and hydroelectric generation; risks associated with commodity price volatility and supply of purchased power; and risks related to general economic conditions, including inflation, interest rate and foreign exchange risks.* 

*All forward-looking information herein is given as of February 9, 2023. 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.*

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|:---|:---|:---|
| **42** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

**GLOSSARY**

**2022 Annual Financial Statements:** the Corporation's audited consolidated financial statements and notes thereto for the year ended December 31, 2022

**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-U.S. GAAP Financial Measures" on page 14

**Adjusted Payout Ratio:** dividends per common share divided by Adjusted Basic EPS as shown under "Non-U.S. GAAP Financial Measures" on page 14

**AFUDC:** allowance for funds used during construction

**Aitken Creek:** Aitken Creek Gas Storage ULC, a direct 93.8%-owned subsidiary of FortisBC Holdings Inc.

**AMI:** Advanced Metering Infrastructure

**ACC:** Arizona Corporation Commission

**AUC:** Alberta Utilities Commission

**BCUC:** British Columbia Utilities Commission

**BECOL:** Belize Electric Company Limited, an indirect wholly owned subsidiary of Fortis (now known as Fortis Belize)

**Belize Electricity:** Belize Electricity Limited, in which Fortis indirectly holds a 33% equity interest

**Board:** Board of Directors of the Corporation

**CAGR(s):** compound average growth rate of a particular item. CAGR = (EV/BV) <sup>1-N</sup> -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. Calculated on a constant U.S. dollar to Canadian dollar exchange rate

**Capital Expenditures:** cash outlay for additions to property, plant and equipment and intangible assets as shown in the Annual Financial Statements, as well as Fortis' 39% share of capital spending for the Wataynikaneyap Transmission Power Project. See "Non-US GAAP Financial Measures" on page 14

**Capital Plan:** forecast Capital Expenditures. Represents a non-U.S. GAAP financial measure calculated in the same manner as Capital Expenditures

**Caribbean Utilities:** Caribbean Utilities Company, Ltd., an indirect approximately 60%-owned (as at December 31, 2022) 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

**CIS:** customer information system

**Common Equity Earnings:** net earnings attributable to common equity shareholders

**Corporation:** Fortis Inc.

**COS:** cost of service

**COVID-19 Pandemic:** declared by the World Health Organization in March 2020 as a result of a novel coronavirus

**CPCN:** Certificate of Public Convenience and Necessity

**CRMP:** Cybersecurity Risk Management Program

**DBRS Morningstar:** DBRS Limited

**D.C. Circuit Court:** U.S. Court of Appeals for the District of Columbia Circuit

**DCP:** disclosure controls and procedures

**DRIP:** dividend reinvestment plan

**EPRI:** Electric Power Research Institute

**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

**Fortis Belize:** Fortis Belize Limited, an indirect wholly owned subsidiary of Fortis (formerly known as BECOL)

**Four Corners:** Four Corners Generating Station, Units 4 and 5

**FX:** foreign exchange associated with the translation of U.S. dollar-denominated amounts. Foreign exchange is calculated by applying the change in the U.S.-to-Canadian dollar FX rates to the prior period U.S. dollar balance.

**GCOC:** generic cost of capital

**GHG:** greenhouse gas

**GWh:** gigawatt hour(s)

**ICFR:** internal control over financial reporting

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|:---|:---|:---|
| **43** | FORTIS INC. | **DECEMBER 31, 2022** |

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**Management Discussion and Analysis**

**ICAT:** Iowa Coalition for Affordable Transmission

**IRA:** Inflation Reduction Act of 2022

**IRP:** Integrated Resource Plan

**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

**LNG:** liquefied natural gas

**LRTP**: Long Range Transmission Plan

**Luna:** Luna Energy Facility

**kV:** kilovolt

**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, 2022

**MISO:** Midcontinent Independent System Operator, Inc.

**Moody's:** Moody's Investor Services, Inc.

**MW:** megawatt(s)

**Navajo:** Navajo Generating Station

**Newfoundland Power:** Newfoundland Power Inc., a direct wholly owned subsidiary of Fortis

**Non-U.S. GAAP Financial Measures:** financial measures that do not have a standardized meaning prescribed by U.S. GAAP

**NOPR**: notice of proposed rulemaking

**NYSE:** New York Stock Exchange

**OEB:** Ontario Energy Board

**OPEB:** other post-employment benefits

**Operating Cash Flow:** cash from operating activities

**PBR:** performance-based rate-setting

**PJ:** petajoule(s)

**PSC**: New York State Public Service Commission

**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

**REA: Rural Electrification Association**

**RNG:** renewable natural gas

**ROA:** rate of return on Rate Base

**ROE:** rate of return on common equity

**RTO:** regional transmission organization

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

**San Juan:** San Juan Generating Station Unit 1

**SEDAR:** Canadian System for Electronic Document Analysis and Retrieval

**SOFR:** Secured Overnight Financing Rate

**TCFD:** Task Force for Climate-Related Financial Disclosures

**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.

**U.S.:** United States of America

**U.S. GAAP:** accounting principles generally accepted in the U.S.

**Waneta Expansion:** Waneta Expansion hydroelectric generation facility

**Wataynikaneyap Partnership:** Wataynikaneyap Power Limited Partnership

---

| | | |
|:---|:---|:---|
| **44** | FORTIS INC. | **DECEMBER 31, 2022** |

---

## Exhibit 99.4

**Exhibit 99.4**

**<u>Rule 13a-14(a) or Rule 15d-14(a) Certification - Chief Executive Officer</u>**

I, David G. Hutchens, certify that:

1. I have reviewed this annual report on Form 40-F of Fortis Inc.;

2.&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d)&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)&nbsp;&nbsp;&nbsp;&nbsp;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.

<u>/s/ David G. Hutchens&nbsp;&nbsp;&nbsp;&nbsp;</u>

David G. Hutchens

President and Chief Executive Officer

St. John's, Canada

February 10, 2023

## Exhibit 99.5

**Exhibit 99.5**

**<u>Rule 13a-14(a) or Rule 15d-14(a) Certification - Chief Financial Officer</u>**

I, Jocelyn H. Perry, certify that:

1.&nbsp;&nbsp;&nbsp;&nbsp;I have reviewed this annual report on Form 40-F of Fortis Inc.;

2.&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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:

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)&nbsp;&nbsp;&nbsp;&nbsp;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;

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(c)&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(d)&nbsp;&nbsp;&nbsp;&nbsp;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.&nbsp;&nbsp;&nbsp;&nbsp;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):

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(a)&nbsp;&nbsp;&nbsp;&nbsp;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

&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;&nbsp;(b)&nbsp;&nbsp;&nbsp;&nbsp;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.

<u>/s/ Jocelyn H. Perry&nbsp;&nbsp;&nbsp;&nbsp;</u>

Jocelyn H. Perry

Executive Vice President, Chief Financial Officer

St. John's, Canada

February 10, 2023

## Exhibit 99.6

**Exhibit 99.6**

**<u>Rule 13a-14(b) Certification Chief Executive Officer</u>**

In connection with the annual report of Fortis Inc. (the "Company") on Form 40-F for the fiscal year ended December 31, 2022 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, David G. Hutchens, 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.&nbsp;&nbsp;&nbsp;&nbsp;The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

&nbsp;&nbsp;&nbsp;&nbsp;

2.&nbsp;&nbsp;&nbsp;&nbsp;The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

<u>/s/ David G. Hutchens&nbsp;&nbsp;&nbsp;&nbsp;</u>

David G. Hutchens

President and Chief Executive Officer

St. John's, Canada

February 10, 2023

## Exhibit 99.7

**Exhibit 99.7**

**<u>Rule 13a-14(b) Certification Chief Financial Officer</u>**

In connection with the annual report of Fortis Inc. (the "Company") on Form 40-F for the fiscal year ended December 31, 2022 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, Jocelyn H. Perry, Executive Vice President, 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.&nbsp;&nbsp;&nbsp;&nbsp;The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.&nbsp;&nbsp;&nbsp;&nbsp;The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

<u>/s/ Jocelyn H. Perry&nbsp;&nbsp;&nbsp;&nbsp;</u>

Jocelyn H. Perry

Executive Vice President, Chief Financial Officer

St. John's, Canada

February 10, 2023

## Exhibit 99.8

**Exhibit 99.8**

**<u>Consent of Report of Independent Registered Public Accounting Firm</u>**

We consent to the incorporation by reference in Registration Statement No. 333-264838 on Form S-8, Registration Statement No. 333-226663 and its Post-Effective Amendment No. 1 on Form S-8, Registration Statement No. 333-236213 and its Post-Effective Amendment No. 2 on Form S-8, Registration Statement No. 333-268493 on Form F-10EF, and Registration Statement No. 333-249039 on Form F-3 and to the use of our reports dated February 9, 2023 relating to the consolidated financial statements of Fortis Inc. and the effectiveness of Fortis Inc.'s internal control over financial reporting appearing in this Annual Report on Form 40-F for the year ended December 31, 2022.

<u>/s/ Deloitte LLP&nbsp;&nbsp;&nbsp;&nbsp;</u>

Chartered Professional Accountants

St. John's, Canada

February 10, 2023

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