Exhibit

EX-99.1 2 a991aif2018.htm EXHIBIT 99.1 Exhibit

Exhibit 99.1

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2018

February 14, 2019

ANNUAL INFORMATION FORM

For the year ended December 31, 2018

Dated February 14, 2019



CONTENTS

Forward-Looking Information	2	Social and Environmental Policies	25
Definitions	3	Environmental, Sustainability and
Corporate Structure	5	Regulatory Oversight	26
Name and Incorporation	5	Environmental Contingencies	27
Inter-Corporate Relationships	5	Capital Structure and Dividends	27
General Development of the Business	6	Description of Capital Structure	27
Overview	6	Dividends and Distributions	27
Three-Year History	6	Debt Covenant Restrictions on Dividend Distributions	28
Outlook	7	Credit Ratings	29
Description of the Business	7	Directors and Officers	31
Regulated Utilities	8	Audit Committee	33
ITC	8	Members	33
UNS Energy	11	Education and Experience	33
Central Hudson	15	Pre-Approval Policies and Procedures	34
FortisBC Energy	16	External Auditor Service Fees	34
FortisAlberta	18	Transfer Agent and Registrar	34
FortisBC Electric	19	Interests of Experts	35
Other Electric	20	Additional Information	35
Non-Regulated	23
Energy Infrastructure	23	Exhibit A: Summary of Terms and Conditions of Authorized Securities	36
Corporate and Other	23
Human Resources	24	Exhibit B: Market for Securities	39
Legal Proceedings and Regulatory Actions	25	Exhibit C: Audit Committee Mandate	41
Risk Factors	25	Exhibit D: Material Contracts	49
Corporate Social Responsibility	25



ANNUAL INFORMATION FORM	1	December 31, 2018

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 included in this AIF 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: the satisfaction of the conditions, receipt of approvals and the expected timing of the closing of the sale of the Corporation's interest in the Waneta Expansion; the Corporation's forecast capital expenditures for the period 2019 to 2023; the Corporation's forecast rate base for the period 2019 through 2023; the expectation that long-term sustainable growth in rate base will support continuing growth in earnings and dividends; target average annual dividend growth through 2023; the expectation that allocated revenues recognized by ITC from Canadian entities reserving transmission over the Ontario or Manitoba interface are not expected to be material to ITC; the expectation that TEP has sufficient generating capacity, together with existing PPAs and expected generation plant additions, to satisfy the requirements of its customer base and meet future peak demand requirements; the expectation that changes in energy supply costs may increase electricity prices in a manner that adversely affects Newfoundland Power's sales; and TEP's expected share of mine reclamation costs.

Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; no material capital project and financing cost overrun related to any of the Corporation's capital projects; sufficient human resources to deliver service and execute the capital program; the Board of Directors exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel, coal and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; no significant changes in government energy plans, environmental laws and regulations that may materially negatively affect the Corporation and its subsidiaries; the ability to obtain and maintain licences and permits; retention of existing service areas; 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 First Nations; and favourable labour relations.

Forward‑looking information involves significant risks, uncertainties and assumptions. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. For additional information with respect to certain of these risks or factors, reference should be made to the MD&A for the year ended December 31, 2018 under the heading "Business Risk Management" and to the continuous disclosure materials filed from time to time by Fortis with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2019 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation's utilities; the impact of fluctuations in foreign exchange rates; risk associated with the impacts of less favourable economic conditions on the Corporation's results of operations; risk associated with the completion of the Corporation's 2018 capital expenditure program, including completion of major capital projects in the timelines anticipated and at the expected amounts; and uncertainty in the timing and access to capital markets to arrange sufficient and cost-effective financing to finance, among other things, capital expenditures and the repayment of maturing debt.

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



Conversions 1 litre = 0.22 imperial gallons 1 kilometre = 0.62 miles Conversion using the above factors on rounded numbers appearing in this AIF may produce small differences from reported amounts as a result. Some information in this AIF is set forth in metric units and some is set forth in imperial units.		Measurements GW Gigawatt(s) GWh Gigawatt hour(s) km Kilometre(s) kV Kilovolt(s) kW Kilowatt(s) MW Megawatt(s) MWh Megawatt hour(s) TJ Terajoule(s) PJ Petajoule(s)



ANNUAL INFORMATION FORM	2	December 31, 2018

DEFINITIONS

Financial information in this AIF has been prepared in accordance with US GAAP and is presented in Canadian dollars ($) unless otherwise specified. Except as otherwise noted, the information in this AIF is given as of December 31, 2018.

Certain terms used in this 2018 Annual Information Form are defined below:

"2018 Annual Information Form" or "AIF" means this annual information form of the Corporation in respect of the year ended December 31, 2018;

"ACGS" means Aitken Creek Gas Storage ULC;

"Aitken Creek" means the Aitken Creek natural gas storage facility;

"Algoma Power" means Algoma Power Inc.;

"APS" means Arizona Public Service Company;

"AUC" means the Alberta Utilities Commission;

"BC Hydro" means the BC Hydro and Power Authority;

"BCUC" means the British Columbia Utilities Commission;

"BECOL" means Belize Electric Company Limited;

"Belize Electricity" means Belize Electricity Limited;

"BEPC" means Brilliant Expansion Power Corporation;

"Board" means the Board of Directors of the Corporation;

"BPC" means Brilliant Power Corporation;

"Canadian Niagara Power" means Canadian Niagara Power Inc.;

"Caribbean Utilities" means Caribbean Utilities Company, Ltd.;

"Central Hudson" means Central Hudson Gas & Electric Corporation;

"CH Energy Group" means CH Energy Group, Inc.;

"CMS" means Consumers Energy Company;

"Cornwall Electric" means Cornwall Street Railway, Light and Power Company, Limited;

"Corporation" means Fortis Inc.;

"CPA" means the Canal Plant Agreement;

"CBT" means Columbia Basin Trust;

"CPC" means Columbia Power Corporation;

"DBRS" means DBRS Limited;

"DTE" means DTE Electric Company;

"EDGAR" means the SEC's system for Electronic Data Gathering, Analysis and Retrieval available at www.sec.gov;

"FERC" means the Federal Energy Regulatory Commission;

"FHI" means FortisBC Holdings Inc.;

"Fitch" means Fitch Ratings Inc.;

"Fortis" means Fortis Inc.;

"FortisAlberta" means FortisAlberta Inc.;

"FortisAlberta Holdings" means FortisAlberta Holdings Inc.;

"FortisBC Electric" means, collectively, the operations of FortisBC Inc. and its parent company, FortisBC Pacific Holdings Inc.;

"FortisBC Energy" means FortisBC Energy Inc.;

"FortisOntario" means FortisOntario Inc.;

"FortisTCI" means, collectively, FortisTCI Limited and Turks and Caicos Utilities Limited;

"FortisUS" means FortisUS Inc.;

"FortisUS Holdings" means FortisUS Holdings Nova Scotia Limited;

"FortisWest" means FortisWest Inc.;

"GHG" means greenhouse gas;

"GIC" means GIC Private Limited;

"GSMIP" means the Gas Supply Mitigation Incentive Plan of FortisBC Energy;



ANNUAL INFORMATION FORM	3	December 31, 2018

"IESO" means the Independent Electricity System Operator of Ontario;

"IPL" means Interstate Power and Light Company;

"ITC" means ITC Holdings together with all of its subsidiaries;

"ITC Great Plains" means ITC Great Plains, LLC;

"ITC Holdings" means ITC Holdings Corp.;

"ITC Interconnection" means ITC Interconnection LLC;

"ITC Investment Holdings" means ITC Investment Holdings Inc.;

"ITC Midwest" means ITC Midwest LLC;

"ITC MISO Regulated Operating Subsidiaries" means ITCTransmission, METC and ITC Midwest together;

"ITCTransmission" means International Transmission Company;

"ITC Regulated Operating Subsidiaries" means collectively, ITCTransmission, METC, ITC Midwest, ITC Great Plains and ITC Interconnection;

"Maritime Electric" means Maritime Electric Company, Limited;

"MD&A" means the Corporation's Management Discussion and Analysis in respect of the year ended December 31, 2018;

"METC" means Michigan Electric Transmission Company;

"MISO" means the Midcontinent Independent System Operator, Inc.;

"Moody's" means Moody's Investors Service, Inc.;

"NB Power" means New Brunswick Power Corporation;

"NL Hydro" means Newfoundland and Labrador Hydro Corporation;

"Newfoundland Power" means Newfoundland Power Inc.;

"NYSE" means the New York Stock Exchange;

"PEI" means Prince Edward Island;

"PNM" means Public Service Company of New Mexico;

"PPA" means power purchase agreement;

"PUB" means the Newfoundland and Labrador Board of Commissioners of Public Utilities;

"S&P" means Standard & Poor's Financial Services LLC;

"SEC" means the United States Securities and Exchange Commission;

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

"SPP" means Southwest Power Pool, Inc.;

"SRP" means Salt River Project Agricultural Improvement and Power District;

"T&D" means transmission and distribution;

"TEP" means Tucson Electric Power Company;

"TransCanada" means TransCanada Pipelines Limited;

"TSX" means the Toronto Stock Exchange;

"UNS Electric" and "UNSE" mean UNS

Electric, Inc.;

"UNS Energy" means UNS Energy Corporation;

"UNS Gas" means UNS Gas, Inc.;

"Waneta Expansion" means the 335-MW Waneta Expansion hydroelectric generating facility;

"Waneta Partnership" means the Waneta Expansion Limited Partnership; and

"Wataynikaneyap Partnership" means the Wataynikaneyap Power Limited Partnership.



ANNUAL INFORMATION FORM	4	December 31, 2018

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 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.

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.

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 14, 2019. The principal subsidiaries together comprise approximately 88% of the Corporation's consolidated assets as at December 31, 2018 and approximately 84% of the Corporation's 2018 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, 2018.



Subsidiary	Jurisdiction of Incorporation	Votes attaching to voting securities beneficially owned, controlled or directed by the Corporation (%)
ITC⁽¹⁾	Michigan, United States	80.1
UNS Energy ⁽²⁾	Arizona, United States	100
Central Hudson ⁽³⁾	New York, United States	100
FortisBC Energy ⁽⁴⁾	British Columbia, Canada	100
FortisAlberta ⁽⁵⁾	Alberta, Canada	100
Newfoundland Power ⁽⁶⁾	Newfoundland and Labrador, Canada	95

⁽¹⁾

ITC Holdings, a Michigan corporation, owns all of the shares of ITC Great Plains, ITC Interconnection, ITC Midwest, ITCTransmission and METC. ITC Investment Holdings, a Michigan corporation, owns all of the shares of ITC Holdings. FortisUS, a Delaware corporation, owns 80.1% of the voting securities of ITC Investment Holdings. FortisUS Holdings, a Canadian Corporation, owns all of the shares of FortisUS. Fortis owns all of the shares of FortisUS Holdings. 19.9% of the voting securities of ITC Investment Holdings are owned by an affiliate of GIC.


⁽²⁾	UNS Energy owns all of the shares of TEP, UNS Electric and UNS Gas. FortisUS owns all of the shares of UNS Energy.


⁽³⁾	CH Energy Group, Inc., a New York corporation, owns all of the shares of Central Hudson. FortisUS owns all of the shares of CH Energy Group.


⁽⁴⁾	FHI, a British Columbia corporation, owns all of the shares of FortisBC Energy. Fortis owns all of the shares of FHI.


⁽⁵⁾	FortisAlberta Holdings, an Alberta corporation, owns all of the shares of FortisAlberta. FortisWest, a Canadian corporation, owns all of the shares of FortisAlberta Holdings. Fortis owns all of the shares of FortisWest.


⁽⁶⁾	Fortis owns all of the common shares and certain of the First Preference Shares, Series A, B, D and G of Newfoundland Power, which, as at February 14, 2019, represent 95% of its voting securities. The remaining 5% of Newfoundland Power's voting securities consist of First Preference Shares, Series A, B, D and G, which are primarily held by the public.



ANNUAL INFORMATION FORM	5	December 31, 2018

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Fortis is a leader in the North American regulated electric and gas utility industry, with 2018 revenue of $8.4 billion and total assets of $53 billion as at December 31, 2018. The Corporation's 8,800 employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries. In 2018 the Corporation's electricity systems met a combined peak demand of 33,295 MW and its gas distribution systems met a peak day demand of 1,599 TJ.

Three-Year History

Over the past three years, Fortis has experienced significant growth in its business operations. Total assets have almost doubled from $28.8 billion as at December 31, 2015 to $53.1 billion as at December 31, 2018. The Corporation's shareholders' equity has also grown significantly from $10.4 billion as at December 31, 2015 to $18.5 billion as at December 31, 2018. Net earnings attributable to common equity shareholders have increased from $728 million in 2015 to $1,100 million in 2018.

The growth in business operations reflects the Corporation's profitable growth strategy for its principal regulated utilities. This strategy includes a combination of organic growth through the Corporation's consolidated capital expenditure program and growth from acquisitions.

In April 2016 the Corporation completed the acquisition of ACGS for approximately $349 million, plus the cost of working gas inventory. ACGS owns 93.8% of Aitken Creek, with the remaining share owned by BP Canada Energy Company. Aitken Creek is the only underground gas storage facility in British Columbia and has a total working gas capacity of 77 billion cubic feet. The facility is an integral part of western Canada's natural gas transmission network.

In October 2016 the Corporation and GIC acquired all of the outstanding common shares of ITC, the largest independent transmission company in the U.S., for an aggregate purchase price of approximately $15.7 billion (US$11.8 billion) on closing, including approximately $6.3 billion (US$4.8 billion) of ITC consolidated indebtedness. ITC is a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC.

In connection with the acquisition of ITC, Fortis became an SEC registrant in May 2016 and in October 2016 the Corporation's common shares commenced trading on the NYSE. The Corporation filed a business acquisition report in connection with its acquisition of ITC on SEDAR and EDGAR on November 23, 2016.

In January 2019 the Corporation announced it has entered into a definitive agreement with CBT and CPC to sell its 51% interest in the Waneta Expansion for approximately $1 billion. Fortis expects the transaction to close in the second quarter of 2019 following the satisfaction of customary closing conditions and the receipt of routine approvals. The sale of the Corporation's interest in the Waneta Expansion completes the asset sale portion of the Corporation's capital funding strategy.

The Corporation's gross consolidated capital expenditures for 2018 were approximately $3.2 billion. Over the past three years, including 2018, gross consolidated capital expenditures totalled $8.3 billion. Organic asset growth has been driven by the capital expenditure programs at the Corporation's regulated utilities. Organic growth in non‑regulated operations has been driven by the acquisition of Aitken Creek in April 2016.



ANNUAL INFORMATION FORM	6	December 31, 2018

Outlook

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

The Corporation's $17.3 billion five-year capital program is expected to increase rate base from $26.1 billion in 2018 to approximately $32.0 billion in 2021 and $35.5 billion in 2023, translating into three and five-year compound annual growth rates of 7.1% and 6.3%, respectively. The five-year capital program addresses system capacity and improves safety and reliability for the benefit of customers through investments that improve and automate the electricity grid, address natural gas system capacity and gas line network integrity, increase cyber protection and allow the grid to deliver cleaner energy.

Fortis is focused on securing further growth opportunities at its subsidiaries, which include the ITC Lake Erie Connector Project, gas infrastructure opportunities at FortisBC Energy and renewable energy investments, including storage, at UNS Energy.

Fortis expects long-term sustainable growth in rate base to support continuing growth in earnings and dividends. Fortis is targeting average annual dividend growth of 6% through 2023. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital program, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence.

DESCRIPTION OF THE BUSINESS

Fortis is principally a North American electric and gas utility holding company. Most of the Corporation's regulated utilities operate as the sole supplier of electricity and/or gas within their respective service territories. Fortis is primarily an energy delivery company with 93% of its assets dedicated to energy delivery. The Corporation's regulated utilities own and operate facilities that generate, transmit and/or distribute electricity and/or natural gas to their customers. Competition in the regulated electric business is primarily from alternative energy sources and on-site generation by industrial customers. The Corporation faces competition in its transmission business which may restrict its ability to grow this business outside of its established service territories.

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

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

As at December 31, 2018, approximately 67% of the Corporation's assets were located outside of Canada and approximately 60% of the Corporation's revenue was derived from foreign operations.



ANNUAL INFORMATION FORM	7	December 31, 2018

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



		Customers	Peak Demand ⁽¹⁾		Electric T&D Lines (km) ⁽²⁾	Gas T&D Lines (km)	Generating Capacity (MW)	Revenue (millions)		GWh Sales	Gas Volumes (PJ)	Employees
Regulated Utilities
ITC		—	23,634	MW	25,400	—	—	$	1,504	—	—	692
UNS Energy		680,000	3,107 93	MW TJ	22,400	5,000	3,377	2,202		17,406	13	2,049
Central Hudson		380,000	1,114 153	MW TJ	15,100	2,350	64	924		5,118	24	1,014
FortisBC Energy		1,030,000	1,353	TJ	—	49,500	—	1,187		—	212	1,846
FortisAlberta		564,000	2,743	MW	88,900	—	—	579		17,154	—	1,110
FortisBC Electric		176,000	663	MW	7,300	—	225	408		3,250	—	525
Other Electric
	Newfoundland Power	268,000	1,362	MW	12,600	—	139	662		5,876	—	623
	Maritime Electric	81,000	280	MW	6,100	—	145	203		1,257	—	202
	FortisOntario	66,000	257	MW	3,500	—	5	201		1,293	—	206
	Caribbean Utilities	30,000	94	MW	750	—	161	258		629	—	236
	FortisTCI	15,000	41	MW	650	—	91	88		237	—	173
Non-Regulated
Energy Infrastructure		—	—		—	—	386 ⁽³⁾	184		853	—	65
Corporate and Other		—	—		—	—	—	—		—	—	59
Total		3,290,000	33,295 1,599	MW TJ	182,700	56,850	4,593	$	8,400	53,073	249	8,800


⁽¹⁾	Electric (MW) or gas (TJ)


⁽²⁾	Circuit km


⁽³⁾	Includes the Corporation's 51% controlling ownership interest in the 335-MW Waneta Expansion

Regulated Utilities

ITC

ITC's business consists mainly of the electric transmission operations of the ITC Regulated Operating Subsidiaries. Through ITC's Regulated Operating Subsidiaries, it owns and operates high-voltage 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 systems. ITC's business strategy is to own, operate, maintain and invest in transmission infrastructure in order to enhance system integrity and reliability, reduce transmission constraints and support new generating resources to interconnect to ITC's transmission system. ITC owns and operates more than 25,000 circuit km of transmission lines.

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

ITC's principal transmission service customers are DTE, CMS and IPL. One or more of these customers together have consistently represented a significant percentage of ITC's operating revenue. Nearly all of ITC's revenues are from transmission customers in the United States. Although ITC may recognize allocated revenues from time to time from Canadian entities reserving transmission over the Ontario or Manitoba interface, these revenues have not been and are not expected to be material to ITC.



ANNUAL INFORMATION FORM	8	December 31, 2018

Market and Sales

Revenues

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

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

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

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

Point-to-point revenues consist of revenues generated from a type of transmission service for which the customer pays for transmission capacity reserved along a specified path between two points on an hourly, daily, weekly or monthly basis. Point-to-point revenues also include other components pursuant to schedules under the MISO and SPP 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 by MISO to ITC's MISO Regulated Operating Subsidiaries as compensation for the services performed in operating the transmission system. Such services include monitoring of reliability data, current and next day analysis, implementation of emergency procedures and outage coordination and switching.

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

The following table compares the composition of ITC's 2018 and 2017 revenue by customer class.



	Revenue (%)
	2018	2017
Network revenues	66.7	67.4
Regional cost-sharing revenues	28.9	28.1
Point-to-point	1.2	1.5
Scheduling, control and dispatch	1.3	1.1
Other	1.9	1.9
Total	100.0	100.0



ANNUAL INFORMATION FORM	9	December 31, 2018

Contracts

ITCTransmission

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

Master Operating Agreement. This agreement governs the primary day-to-day operational responsibilities. The agreement 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. This agreement established, re-established and maintains the interconnection of DTE's electricity generating assets with ITCTransmission's transmission system.

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

METC

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

Amended and Restated Easement Agreement. Under this 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. Under this 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. This 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. This agreement specifies the terms and conditions under which CMS and METC maintain the interconnection of CMS' generation resources and METC's transmission assets.



ANNUAL INFORMATION FORM	10	December 31, 2018

ITC Midwest

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

Distribution-Transmission Interconnection Agreement. This 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 parties' property, assets and facilities and the construction of new facilities or modification of existing facilities.

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

UNS Energy

UNS Energy is a vertically integrated utility services holding company, headquartered in Tucson, Arizona. It is engaged through its subsidiaries in the regulated electric generation and energy delivery business, primarily in the State of Arizona, serving approximately 680,000 electricity and gas customers. UNS Energy is primarily comprised of three wholly owned regulated utilities: TEP, UNS Electric and UNS Gas.

TEP, UNS Energy's largest operating subsidiary, is a vertically integrated regulated electric utility that generates, transmits and distributes electricity. TEP serves approximately 425,000 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 United States.

UNS Electric is a vertically integrated regulated electric utility that generates, transmits and distributes electricity to approximately 97,000 retail customers in Arizona's Mohave and Santa Cruz counties, which have a combined population of approximately 253,000.

TEP and UNS Electric currently own generation resources with an aggregate capacity of 3,377 MW, including 57 MW of solar capacity. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. TEP has sufficient generation capacity that, together with existing PPAs and expected generation plant additions, are expected to satisfy the requirements of its customer base and meet future peak demand requirements. As at December 31, 2018, approximately 37% of the generating capacity was fuelled by coal.

UNS Gas is a regulated gas distribution utility that serves approximately 158,000 retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties, which have a combined population of approximately 731,000.

Market and Sales

UNS Energy's electricity sales were 17,406 GWh in 2018, compared to 14,971 GWh in 2017. Earnings for UNS Energy's electric utilities are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment. Gas volumes were 13 PJ in 2018 and 2017. Revenue was $2,202 million in 2018, compared to $2,080 million in 2017.



ANNUAL INFORMATION FORM	11	December 31, 2018

The following table provides the composition of UNS Energy's 2018 and 2017 revenue, electricity sales, and gas volumes by customer class.



	Revenue (%)		GWh Sales (%)		PJ Volumes (%)
	2018	2017	2018	2017	2018	2017
Residential	37.6	38.1	26.9	31.1	58.8	56.4
Commercial	22.1	23.1	16.2	19.2	24.5	24.7
Industrial	14.4	14.5	17.7	20.3	2.0	2.1
Other ⁽¹⁾	25.9	24.3	39.2	29.4	14.7	16.8
Total	100.0	100.0	100.0	100.0	100.0	100.0


⁽¹⁾	Includes electricity sales and gas volumes to other entities for resale and revenue from sources other than from the sale of electricity and gas

Power Supply

TEP meets the electricity supply requirements of its retail and wholesale customers with its owned electrical generating capacity of 3,076 MW and its T&D system consisting of approximately 15,900 km of line. In 2018 TEP met a peak demand of 2,682 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 as of December 31, 2018 is set forth in the following table.



Generation Source	Unit No.	Location	Date in Service	Total Capacity (MW)	Operating Agent	TEP's Share (%)	TEP's Share (MW)
Coal
Springerville Station ⁽¹⁾	1	Springerville, AZ	1985	387	TEP	100.0	387
Springerville Station	2	Springerville, AZ	1990	406	TEP	100.0	406
San Juan Station	1	Farmington, NM	1976	340	PNM	50.0	170
Navajo Station ⁽²⁾	1	Page, AZ	1974	750	SRP	7.5	56
Navajo Station ⁽²⁾	2	Page, AZ	1975	750	SRP	7.5	56
Navajo Station ⁽²⁾	3	Page, AZ	1976	750	SRP	7.5	56
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 ⁽³⁾	2	Gila Bend, AZ	2003	550	SRP	100.0	550
Gila River Power Station	3	Gila Bend, AZ	2003	550	SRP	75.0	413
Luna Generating Station	1	Deming, NM	2006	555	PNM	33.3	185
Sundt Station ⁽⁴⁾	1	Tucson, AZ	1958	81	TEP	100.0	81
Sundt Station ⁽⁴⁾	2	Tucson, AZ	1960	81	TEP	100.0	81
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
DeMoss Petrie		Tucson, AZ	2001	75	TEP	100.0	75
North Loop		Tucson, AZ	2001	94	TEP	100.0	94
Solar
Utility-Scale Renewables		Various	2002-2017	46	TEP	100.0	46
Total Capacity							3,076


⁽¹⁾	Springerville Generating Station Unit 2 is owned by San Carlos Resources Inc., a wholly-owned subsidiary of TEP.


⁽²⁾	TEP, along with the other participants at the Navajao Generation Station plan to discontinue operations of the generating station by the end of 2019.


⁽³⁾	In 2017, TEP entered into a 20-year tolling PPA with SRP to purchase and receive all 550 MW of capacity, power and ancillary services from Gila River Unit 2, which includes a three-year option to purchase the unit.


⁽⁴⁾	TEP plans to discontinue operations of H. Wilson Sundt Generation Station Units 1 & 2 by the end of 2020.



ANNUAL INFORMATION FORM	12	December 31, 2018

UNS Electric meets the electricity supply requirements of its retail customers through a mix of its own generation and PPAs. UNS Electric owns and operates several gas and diesel‑fuelled generating plants, with a collective electrical generation capacity of 301 MW. In 2018 UNS Electric met a peak demand of 425 MW by utilizing its generation capacity and purchasing power on the wholesale market.

UNS Electric's generating capacity as of December 31, 2018 is set forth in the following table.



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

Owned Utility-Scale Renewable Resources

TEP owned 46 MW of photovoltaic solar generation capacity as at December 31, 2018 as set forth in the following table.



Generation Source	Location	Date/Projected Date In Service	In Service Capacity (MW)	Developing Capacity (MW)
Solar
Fort Huachuca Phase I & II ⁽¹⁾	Sierra Vista, AZ	2014-2017	18	—
Springerville	Springerville, AZ	2004-2014	13	—
UASTP Phase I & II ⁽²⁾	Tucson, AZ	2010-2011	5	—
Sundt Areva Solar Thermal	Tucson, AZ	2014	5	—
Solon Prairie Fire ⁽²⁾	Tucson, AZ	2012	4	—
Small PV, Solar (<5MW)	Various	Various	1	—
Wind
New Mexico Wind Project	Chaves Country, NM	2020	—	150
Total Capacity			46	150


⁽¹⁾	TEP has a 30-year easement agreement to facilitate operations on behalf of the U.S. Department of the Army.


⁽²⁾	The University of Arizona Science and Technology Park I & II and Solon Prairie Fire are located on properties held under land easements and leases.

UNS Electric owned 11 MW of photovoltaic solar generation capacity as at December 31, 2018 as set forth in the following table.



Generation Source	Location	Date/Projected Date In Service	Resource Type	In Service Capacity (MW)
Rio Rico	Rio Rico, AZ	2014	Solar	6
Jacobson	Kingman, AZ	2017	Solar	4
La Senita	Kingman, AZ	2011	Solar	1
Total Owned Solar Capacity				11



ANNUAL INFORMATION FORM	13	December 31, 2018

Renewable Power Purchase Agreements

As at December 31, 2018, TEP had renewable PPAs for 159 MW from solar resources, 80 MW from wind resources, and 4 MW associated with the purchase of landfill gas as presented in the following table. The solar PPAs contain options that allow TEP to purchase all or part of the related project at a future date.



Generation Source	Location	Date/Projected Date In Service	In Service Capacity (MW)	Under Development Capacity (MW)
Solar
Red Horse	Willcox, AZ	2015	41	—
Avalon I	Sahuarita, AZ	2014	28	—
Avra Valley	Marana, AZ	2012	25	—
Picture Rocks	Marana, AZ	2012	20	—
Avalon II	Sahuarita, AZ	2016	17	—
Valencia	Tucson, AZ	2013	10	—
E.On Tech Park	Tucson, AZ	2012	5	—
Gato Montes	Tucson, AZ	2012	5	—
Small PPAs, Solar (<5MW)	Various	Various	8	—
Wilmot Solar	Tucson, AZ	2021	—	100
Wind
Macho Springs	Deming, NM	2011	50	—
Red Horse Wind	Willcox, AZ	2015	30	—
Borderlands Wind	Catron County, NM	2020	—	99
Biogas
Sundt - Los Reales ⁽¹⁾	Tucson, AZ	1998	4	—
Total Capacity			243	199


⁽¹⁾	Purchase of landfill gas for use at Sundt

As at December 31, 2018, UNS Electric had renewable PPAs for 55 MW from solar resources and 40 MW from wind resources as set forth in the following table.



Generation Source	Location	Date/Projected Date In Service	Resource Type	In Service Capacity (MW)
GrayHawk Solar	Kingman, AZ	2018	Solar	46
Red Horse Wind	Willcox, AZ	2016	Wind	30
Kingman Wind Farm	Kingman, AZ	2011	Wind	10
Black Mountain Solar	Kingman, AZ	2012	Solar	9
Total PPA Renewable Capacity				95

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 ten years in advance, with a view to hedging at least 70-90% of expected monthly energy volumes prior to the beginning of each month.

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



ANNUAL INFORMATION FORM	14	December 31, 2018



Station	Natural Gas Transportation Counterparty	Contract Expiration Date(s)
Gila	Transwestern Pipeline Co./El Paso Natural Gas Company, LLC	2019-2040
Luna	El Paso Natural Gas Company, LLC	2022
Sundt	El Paso Natural Gas Company, LLC	2023-2040
DeMoss Petrie	Southwest Gas Corporation	Retail Tariff
North Loop	Southwest Gas Corporation	Retail Tariff

Central Hudson

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

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

Central Hudson's electric T&D system consists of more than 15,000 circuit km of line and met a peak demand of 1,114 MW in 2018.

Central Hudson's natural gas system consists of approximately 2,350 km of T&D pipelines and met a peak day demand of 153 TJ in 2018.

Market and Sales

Central Hudson's electricity sales were 5,118 GWh in 2018, compared to 4,891 GWh in 2017. Natural gas sales volumes in 2018 were 24 PJ, compared to 22 PJ in 2017. Revenue was $924 million in 2018, compared to $872 million in 2017.

The following table compares the composition of Central Hudson's 2018 and 2017 revenue, electricity sales and gas volumes by customer class.



	Revenue (%)		GWh Sales (%)		PJ Volumes (%)
	2018	2017	2018	2017	2018	2017
Residential	65.4	61.5	42.4	40.5	26.9	25.1
Commercial	29.2	27.6	38.5	39.0	35.6	34.5
Industrial	3.8	3.8	17.9	19.0	21.6	20.5
Other	0.2	5.6	0.5	0.6	7.2	7.6
Sales for Resale	1.4	1.5	0.7	0.9	8.7	12.3
Total	100.0	100.0	100.0	100.0	100.0	100.0

Power Supply

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

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



ANNUAL INFORMATION FORM	15	December 31, 2018

Central Hudson's PPA to purchase capacity from the Danskammer Generating Facility expired in July 2018 and was not renewed.

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 1,030,000 residential, commercial and industrial and transportation customers in more than 135 communities. FortisBC Energy provides T&D services to customers, and obtains natural gas supplies on behalf of most residential, commercial and industrial customers.

FortisBC Energy owns and operates approximately 49,500 km of natural gas pipelines and met a peak day demand of 1,353 TJ in 2018.

Market and Sales

FortisBC Energy's natural gas sales volumes were 212 PJ in 2018, compared to 221 PJ in 2017. Revenue was $1,187 million in 2018 compared to $1,198 million in 2017.

The following table compares the composition of FortisBC Energy's 2018 and 2017 revenue and natural gas volumes by customer class.



	Revenue (%)		PJ Volumes (%)
	2018	2017	2018	2017
Residential	57.7	58.7	36.3	37.1
Commercial	27.7	28.8	23.1	23.5
Industrial	3.2	2.1	2.8	1.8
Transportation	11.4	10.4	37.8	37.6
Total	100.0	100.0	100.0	100.0

Gas Purchase Agreements

To ensure supply of adequate resources for reliable natural gas deliveries to its customers, FortisBC Energy purchases natural gas supply from counterparties, including producers, aggregators and marketers. FortisBC Energy contracts for approximately 154 PJ of baseload and seasonal supply, of which the majority is sourced in northeast British Columbia and transported on Westcoast Energy Inc.'s T‑South pipeline system. The remainder is sourced in Alberta and transported on TransCanada's pipeline transportation system.

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

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 day; (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.



ANNUAL INFORMATION FORM	16	December 31, 2018

FortisBC Energy holds approximately 35 PJs of total storage capacity. FortisBC Energy owns Tilbury and Mount Hayes liquefied natural gas peak shaving facilities, which provide on-system storage capacity and deliverability. FortisBC Energy also contracts for underground storage capacity and deliverability from third parties in northeast British Columbia, Alberta and the Pacific Northwest of the United States. On a combined basis, FortisBC Energy's Tilbury and Mount Hayes facilities, the contracted storage facilities, and other peaking arrangements can deliver up to 0.73 PJs per day of supply to FortisBC Energy on the coldest days of the heating season. The heating season typically occurs from December to February.

Mitigation Activities

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

Under the GSMIP revenue sharing model, which is approved by the BCUC, FortisBC Energy can earn an incentive payment for mitigation activities. Historically, FortisBC Energy has earned approximately $1.7 million annually through GSMIP, while the remaining savings are credited back to customers through reduced rates. Subject to the BCUC's approval, FortisBC Energy earned an incentive payment of approximately $2.6 million for the gas contract year ended October 31, 2018.

The current GSMIP program was approved by the BCUC following a comprehensive review in 2011. The BCUC has approved extensions of the program through October 31, 2019.

Price-Risk Management Plan

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

On June 17, 2016, the BCUC approved FortisBC Energy's 2015 Price-Risk Management Application which included FortisBC Energy's request to implement a medium-term (maximum three years out) hedging program including specific market price targets and commodity rate-setting enhancements. During 2018 the market price targets and maximum volume limits were reached and, therefore, the price risk strategies were implemented.

On June 13, 2017, FortisBC Energy filed a request to extend and amend the terms of the previously approved price-risk management plan. The BCUC directed FortisBC Energy to amend the 2017 application or file a revised application to address questions regarding the price risk management objectives and strategies. FortisBC Energy filed a revised 2018 Price Risk Management Application on January 5, 2018, which is being reviewed by the BCUC.

Unbundling

A Customer Choice program at FortisBC Energy allows eligible commercial and residential customers to buy their natural gas commodity supply from FortisBC Energy or from third-party marketers. FortisBC Energy continues to provide the delivery service of the natural gas to all its customers. For the year ended December 31, 2018, approximately 4% of eligible commercial customers and 3% of eligible residential customers purchased their commodity supply from alternate providers.



ANNUAL INFORMATION FORM	17	December 31, 2018

FortisAlberta

FortisAlberta is a regulated electricity distribution utility operating in Alberta. Its business is the ownership and operation of regulated electricity distribution facilities that distribute electricity, generated by other market participants, from high-voltage transmission substations to end-use customers. FortisAlberta is not involved in the generation, transmission or direct retail sale of electricity. FortisAlberta operates the electricity distribution system in a substantial portion of southern and central Alberta, totalling approximately 89,000 circuit km of distribution lines. Many of FortisAlberta's customers are located in rural and suburban areas around and between the cities of Edmonton and Calgary. FortisAlberta's distribution network serves approximately 564,000 customers, comprised of residential, commercial, farm, oil and gas and industrial consumers, and met a peak demand of 2,743 MW in 2018.

Market and Sales

FortisAlberta's annual energy deliveries were 17,154 GWh in 2018 compared to 17,018 GWh in 2017. Revenue was $579 million in 2018 compared to $600 million in 2017.

The following table compares the composition of FortisAlberta's 2018 and 2017 revenue and energy deliveries by customer class.



	Revenue (%)		GWh Deliveries (%) ⁽¹⁾
	2018	2017	2018	2017
Residential	30.9	30.7	18.5	18.1
Large commercial, industrial and oil field	21.2	20.8	59.0	59.6
Farms	12.3	13.0	8.6	8.5
Small commercial	12.2	12.2	8.4	8.1
Small oil field	8.4	8.7	5.2	5.3
Other ⁽²⁾	15.0	14.6	0.3	0.4
Total	100.0	100.0	100.0	100.0


⁽¹⁾	GWh percentages exclude FortisAlberta's GWh deliveries to "transmission-connected" customers. These deliveries were 7,024 GWh in 2018 and 6,691 GWh in 2017, based on an interim settlement that is expected to be finalized in May 2019, and consisted primarily of energy deliveries to large-scale industrial customers directly connected to the transmission grid.


⁽²⁾	Includes revenue from sources other than the delivery of energy, including revenues resulting from street-lighting services, rate riders, deferrals and adjustments

Franchise Agreements

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

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



ANNUAL INFORMATION FORM	18	December 31, 2018

FortisBC Electric

FortisBC Electric is an integrated regulated electric utility that owns hydroelectric generating plants, high voltage transmission lines, and a large network of distribution assets, all of which are located in the southern interior of British Columbia. FortisBC Electric serves approximately 176,000 customers and met a peak demand of 663 MW in 2018. 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; the 335‑MW Waneta Expansion, owned by the Waneta Partnership between Fortis, CBT and CPC; and the 149-MW Brilliant hydroelectric plant, the 120‑MW Brilliant hydroelectric expansion plant and the 185-MW Arrow Lakes generating station, all owned by CBT and CPC.

Market and Sales

FortisBC Electric has a diverse customer base comprised of residential, commercial, industrial and municipal wholesale, and other industrial customers. Electricity sales were 3,250 GWh in 2018, compared to 3,305 GWh in 2017. Revenue was $408 million in 2018, compared to $398 million in 2017.

The following table compares the composition of FortisBC Electric's 2018 and 2017 revenue and electricity sales by customer class.



	Revenue (%)		GWh Sales (%)
	2018	2017	2018	2017
Residential	51.1	51.0	40.8	41.5
Commercial	27.1	26.8	30.1	29.4
Wholesale	13.3	13.7	17.6	17.9
Industrial	8.5	8.5	11.5	11.2
Total	100.0	100.0	100.0	100.0

Generation and Power Supply

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

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

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



Plant	Capacity (MW)	Owners
Canal Plant	580	BC Hydro
Waneta Dam	493	BC Hydro
Waneta Expansion	335	Waneta Partnership
Kootenay River System	225	FortisBC Electric
Brilliant Dam	149	Brilliant Power Corporation
Brilliant Expansion	120	Brilliant Expansion Power Corporation
Total	1,902



ANNUAL INFORMATION FORM	19	December 31, 2018

Brilliant Power Corporation, Brilliant Expansion Power Corporation, Teck Metals Ltd., Waneta Partnership 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 United States, 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 licenses and flows in perpetuity. Should the CPA be terminated, the output of FortisBC Electric's Kootenay River system plants would, with the water and storage authorized under its existing licences and on a long‑term average, be approximately the same power output as FortisBC Electric receives under the CPA. The CPA does not affect FortisBC Electric's ownership of its physical generation assets. The CPA continues in force until terminated by any of the parties by giving no less than five years' notice at any time on or after December 31, 2030.

FortisBC Electric's remaining electricity supply is acquired through short and long-term PPAs with a number of counterparties, including electricity produced by the Waneta Expansion, a hydroelectric project owned by the Waneta Partnership, which is 51% owned by Fortis and 49% owned by a subsidiary of each of CBT and CPC. During 2018, FortisBC Electric purchased capacity and energy from the market to meet its peak energy requirements and optimize its overall power supply portfolio. Spot market and contracted purchases provided approximately 15% of FortisBC Electric's energy supply requirements in 2018. 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 is comprised 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 provides integrated electric utility service through its three regulated operating utilities in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario.

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

Wataynikaneyap Partnership is partnership between 24 First Nations communities and Fortis with a mandate of connecting remote First Nations Communities to the electricity grid in Ontario through the development of new transmission lines. In March 2018 the project reached a significant milestone with the formal announcement of a funding framework among Wataynikaneyap Partnership, the Government of Canada and the Government of Ontario. In January 2019 Fortis reduced its equity investment in Wataynikaneyap Partnership from 49% to 39% to facilitate the inclusion of two additional First Nations communities into the partnership.



ANNUAL INFORMATION FORM	20	December 31, 2018

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



	Customers	Peak Demand (MW)	T&D Lines (km) ⁽¹⁾	Generating Capacity (MW)	Resource Type(s)
Newfoundland Power	268,000	1,362	12,600	139	Hydroelectric, Gas, Diesel
Maritime Electric	81,000	280	6,100	145	Thermal, Diesel
FortisOntario ⁽²⁾	66,000	257	3,500	5	Natural Gas Cogeneration
Caribbean Utilities ⁽³⁾	30,000	94	750	161	Diesel
FortisTCI	15,000	41	650	91	Diesel
Total	460,000	2,034	23,600	541


⁽¹⁾	Circuit km


⁽²⁾	FortisOntario also owns a 10% interest in certain regional electric distribution companies serving approximately 40,000 customers.


⁽³⁾	Includes 24 km of high-voltage submarine cable

Market and Sales

Electricity sales attributable to Other Electric were 9,292 GWh in 2018, compared to 9,196 GWh in 2017. Revenue was $1,412 million in 2018, compared to $1,363 million in 2017.

The following table compares the composition of revenue and electricity sales by customer class for Other Electric in 2018 and 2017.



	Revenue (%)		GWh Sales (%)
	2018	2017	2018	2017
Residential	54.3	54.4	55.6	55.8
Commercial and Industrial	43.5	42.6	44.3	43.9
Other ⁽¹⁾	2.2	3.0	0.1	0.3
Total	100.0	100.0	100.0	100.0

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

Power Supply

Newfoundland Power

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

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

Future changes in supply costs, including costs associated with the Nalcor Energy Muskrat Falls hydroelectric generation development and associated transmission assets, may increase electricity prices in a manner that adversely affects Newfoundland Power's sales. In 2017 Nalcor Energy indicated that the cost of the Muskrat Falls project is projected to reach $12.7 billion. A public inquiry into the Muskrat Falls project, commissioned by the Government of Newfoundland and Labrador, began in 2018 and is scheduled to conclude by December 31, 2019. The Government of Newfoundland and Labrador has also requested the PUB to examine options to mitigate the impact of the Muskrat Falls project on electricity prices. This process by the PUB is ongoing.



ANNUAL INFORMATION FORM	21	December 31, 2018

Newfoundland Power experienced losses of electricity supply from NL Hydro in January 2013 and January 2014, which prevented Newfoundland Power from meeting its customers' requirements. The PUB conducted an inquiry and hearing into these system supply issues and power interruptions. The results indicated that significant concerns remain in relation to the adequacy and reliability of supply from NL Hydro.

Maritime Electric

Maritime Electric purchases approximately 78% of the electricity required to meet its customers' needs from NB Power, a New Brunswick Crown corporation. The balance is met through the purchase of wind energy produced on PEI by facilities owned by the PEI Energy Corporation and from company‑owned on-Island generation, used primarily for peaking, submarine-cable loading issues and emergency purposes.

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

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

FortisOntario

The power requirements of FortisOntario's service territories are met through various sources. Canadian Niagara Power purchases its power requirements for Fort Erie and Port Colborne from IESO and purchases approximately 80% of energy requirements for Gananoque through monthly energy purchases from Hydro One Networks Inc. and 20% from the five hydroelectric generating plants of EO Generation LP. Algoma Power purchases 100% of its energy from IESO.

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

Cornwall Electric purchases substantially all of its power requirements from Hydro-Québec Energy Marketing under two fixed‑term contracts, the first providing approximately 237 GWh of energy per year and up to 45 MW of capacity at any one time, and the second contract providing 100 MW of capacity and energy and a minimum of 300 GWh of energy per year. Both contracts expire in December 2019. In 2016 Cornwall Electric successfully negotiated a new contract that commences January 2020 and expires December 2030. The new contract will provide 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 and is committed to purchasing 60% and 40%, respectively, of its diesel fuel requirements for its diesel-powered generating plant. Caribbean Utilities executed two 24-month fuel supply contracts in June 2018 with the option to renew for two additional terms of 18 months at the end of each term.

FortisTCI

FortisTCI relies upon in-house diesel-powered generation to produce electricity for its customers. In 2018 FortisTCI commissioned its fourth 8-MW Wartsila 30V32 engine. In addition, FortisTCI installed and commissioned two photovoltaic systems under its Utility Owned Renewable Energy Program with a total aggregate size of 250 kW (direct current).

FortisTCI has a renewable contract with a major supplier for all of its diesel fuel requirements associated with the generation of electricity. The approximate fuel requirements under this contract are 14 million imperial gallons per annum.



ANNUAL INFORMATION FORM	22	December 31, 2018

Non-Regulated

Energy Infrastructure

The Corporation's Energy Infrastructure segment is primarily comprised of long-term contracted generation assets in British Columbia and Belize, and a gas storage facility in British Columbia (Aitken Creek). Generation assets in British Columbia include the Corporation's 51% controlling ownership interest in the 335-MW Waneta Expansion. All of the output of the Waneta Expansion is sold to BC Hydro and FortisBC Electric under 40-year contracts. As described earlier, in January 2019 the Corporation entered into a definitive agreement to sell its interest in the Waneta Expansion. FortisBC Electric operates and maintains the Waneta Expansion and will continue to operate the facility following the sale.

Generation assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW held through the Corporation's subsidiary BECOL. All of the output of these facilities is sold to Belize Electricity under 50-year PPAs expiring in 2055 and 2060.

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

Market and Sales

Energy sales were 853 GWh in 2018, compared to 889 GWh in 2017. Revenue was $184 million in 2018, compared to $226 million in 2017.

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 reporting as separate segments. The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses of FHI.



ANNUAL INFORMATION FORM	23	December 31, 2018

HUMAN RESOURCES

As of December 31, 2018, Fortis and its subsidiaries had 8,800 employees, with 52% in Canada, 43% in the U.S. and 5% in other countries. The following table provides the breakdown of employees by reportable segment.



	Employees	Participation in a Collective Agreement		Union(s)	Collective Agreement(s) Expiry Date(s)
Regulated Utilities
ITC	692	None		—	—
UNS Energy	2,049	51	%	International Brotherhood of Electrical Workers	June 2019 – July 2022
Central Hudson	1,014	59	%	International Brotherhood of Electrical Workers	March 2021 – April 2022
FortisBC Energy ⁽¹⁾	1,846	66	%	International Brotherhood of Electrical Workers, Canadian Office and Professional Employees Union	March 2019 – June 2023
FortisAlberta	1,110	79	%	United Utility Workers' Association of Canada	December 2020
FortisBC Electric	525	70	%	International Brotherhood of Electrical Workers, Canadian Office and Professional Employees Union	December 2019 – March 2022
Other Electric ⁽²⁾	1,440	40	%	International Brotherhood of Electrical Workers, Canadian Union of Public Employees, Power Workers' Union	September 2017 ⁽³⁾ – December 2019
Non-Regulated
Energy Infrastructure ⁽⁴⁾	65	None		—	—
Corporate and Other ⁽⁵⁾	59	None		—	—
Total	8,800	53	%


⁽¹⁾	Includes employees at FHI.


⁽²⁾	Includes employees at Newfoundland Power, Maritime Electric, FortisOntario, Caribbean Utilities and FortisTCI. Excludes Belize Electricity.

⁽³⁾

The two collective agreements between Newfoundland Power and IBEW Local 1620 covering 337 Newfoundland Power employees expired on September 30, 2017. Collective agreement negotiations began in the fourth quarter of 2017. Conciliation proceedings occurred in the second quarter of 2018 and no tentative agreements have been reached to date. An application filed by Newfoundland Power to establish essential employees in the event of a labour dispute is under review by the PUB.


⁽⁴⁾	Includes employees at Aitken Creek (staffed by FortisBC Midstream Inc.), BECOL and FortisBC Alternative Energy Services Inc. The Waneta Expansion is staffed by employees of FortisBC Electric.


⁽⁵⁾	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 strive to maintain positive and constructive relationships with labour associations and unions. Approximately 53% of the Corporation's employees are covered by a collective bargaining agreement.

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



ANNUAL INFORMATION FORM	24	December 31, 2018

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, 2018, 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 30 of the 2018 Audited Consolidated Financial Statements, which are incorporated by reference in this AIF and available on SEDAR.

The Corporation's utilities primarily operate under a cost of service regulation, in combination with performance-based rate-setting mechanisms in certain jurisdictions, and are regulated by the regulatory body in their respective operating jurisdiction. There have not been any: (a) penalties or sanctions imposed against the Corporation by a court relating to securities legislation or by a securities regulatory authority during the year ended December 31, 2018; (b) other penalties or sanctions imposed by a court or regulatory body against the Corporation that would likely be considered important to a reasonable investor in making an investment decision; or (c) settlement agreements entered into by the Corporation before a court relating to securities legislation or with a securities regulatory authority during the year ended December 31, 2018.

For information with respect to the nature of regulation and material regulatory decisions and applications associated with each of the Corporation's utilities, refer to the "Regulatory Highlights" section of the MD&A and to Notes 2 and 9 of the Corporation's 2018 Audited Consolidated Financial Statements, each of which are incorporated by reference in this AIF and available on SEDAR.

RISK FACTORS

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

CORPORATE SOCIAL RESPONSIBILITY

Fortis is committed to operating in an environmentally and socially responsible manner. Having strong, reliable infrastructure and adapting its systems to deliver energy more efficiently and to facilitate cleaner energy on the grid are ways the Corporation helps create a lower-carbon economy and deliver on customer expectations.

Social and Environmental Policies

The Corporation and its utilities each have a range of social and environmental policies, programs and practices. Fortis has a Code of Business Conduct and Ethics which sets out the Corporation's standards for the ethical conduct of its business, applicable to all of its directors, officers and employees, and to the extent feasible also to consultants, contractors and representatives of Fortis and its subsidiaries. To ensure implementation, Fortis and its utilities hold regular employee training and require all employees to sign, understand and deliver on the Code of Business Conduct and Ethics.

The Code of Business Conduct and Ethics is supported by other policies that outline the behaviour expected by management and employees including the Anti-Corruption Policy and Respectful Workplace Policy. Defined whistleblower and complaint management processes are in place at all Fortis operating subsidiaries to support reporting behaviour not aligned with the Code of Business Conduct and Ethics and other workplace policies.

The Corporation's Diversity Policy describes the principles and objectives for diversity among the Board and the Corporation's executive leadership, including a commitment to maintaining a Board where at least one-third of its independent directors are represented by each gender - a level that Fortis currently exceeds. For further information on the Corporation's Diversity Policy, refer to the Corporation's Management Information Circular dated March 16, 2018, which is available on SEDAR.



ANNUAL INFORMATION FORM	25	December 31, 2018

Each of the operating subsidiaries are also responsible for implementing additional policies, programs and practices that take into account the jurisdiction and operations of the subsidiary. Social and environmental policies in place at the Corporation's utilities include, among others: Health, Safety, and Environmental Policies; Diversity Policies; Equal Opportunity Policies; Respectful Workplace, Workplace Harassment and Violence Policies; Disability Non-Discrimination Policies; and Accommodation Policies.

Environmental, Sustainability and Regulatory Oversight

Fortis believes that responsible environmental and sustainability management is good for the planet, business and its customers. The Corporation is focused on operating its energy networks in a sustainable manner, helping its customers in their transition to a lower-carbon economy and achieving its goal of delivering safe, reliable and efficient energy over the long term. The Corporation's environmental statement sets out its commitment to comply with all applicable laws and regulations relating to the protection of the environment, regularly conduct monitoring and audits of environmental management systems and seek feasible, cost-effective opportunities to decrease GHG emissions and increase renewable energy sources.

Oversight of sustainability is integrated into each senior level of responsibility at Fortis. The Board is responsible for risk management oversight and ensuring that business is conducted to meet high standards of environmental and social responsibility. The Governance and Nominating Committee of the Board is responsible for overseeing governance structure and practices, including reviewing programs designed to promote corporate citizenship and environmental and social responsibility. The Executive Vice President, Sustainability and Chief Human Resource Officer is responsible for enterprise-wide sustainability and stewardship. Sustainability performance impacts how Fortis executives are compensated. Performance in the core areas of system reliability and safety is linked to incentive compensation for all Fortis executives. In addition, local management teams and boards of directors at each of the Corporation's utilities are responsible for operational aspects of sustainability.

Fortis is primarily an energy delivery company with 93% of its assets dedicated to energy delivery. This naturally limits its impact on the environment when compared with energy generation intensive businesses. The Corporation's GHG emissions come primarily from its generation assets, including fossil fuel-based generation representing 5% of the Corporation's total assets. TEP is the Corporation's primary producer of fossil fuel-based generation and is taking significant steps to reduce coal-fired generation and resulting carbon emissions. TEP is targeting to serve 30% of its retail load from renewable generation by 2030, doubling the State of Arizona's 2025 goal. To achieve this goal, TEP anticipates bringing 450 MW of renewable resources on line by 2021, including 100 MW of solar with a 30 MW battery and up to 350 MW of wind. TEP is also planning a 36% (508 MW) reduction in coal-fired generation by 2022 through plant retirements. Fortis is focused on decreasing its carbon intensity and its utilities achieved a 63% decrease during the period 2015 to 2017.

Fortis and its subsidiaries share a commitment to the environment, health and safety in their operations. The Fortis Sustainability Working Group, comprised of key leaders from across the Fortis group of utilities, is responsible for the Corporation's sustainability strategy and directing reporting practices and enables communication and sharing of information among the Corporation's utilities on sustainability performance, issues and opportunities. In addition, each operating subsidiary has extensive environmental compliance programs, most having adopted the ISO 14001 standard. Each operating subsidiary regularly reviews its environmental management systems and protocols, strives for continual performance improvement and regularly sets and reviews environmental objectives, targets and programs. The Fortis Operating Group consists of senior operational executives from all utilities and meets regularly to share best practices and identify opportunities for collaboration on a range of topics including environment, health and safety.

As part of the regulatory process, each operating subsidiary continually engages with stakeholders including community groups, regulators and customers, to discuss the environmental impact of investment opportunities to deliver safe, reliable, efficient energy to customers in their service territories. The Corporation and its subsidiaries are subject to various federal, provincial, state and municipal laws, regulations and guidelines relating to the protection of the environment. Compliance with environmental laws, regulations and guidelines involve significant operating and capital costs. At the Corporation's regulated utilities, prudently incurred operating and capital costs associated with environmental protection initiatives, compliance with environmental laws, regulations and guidelines, and environmental damage are generally eligible for recovery in customer rates. There is no assurance, however, that all such costs will be recovered or that continued recovery in customer rates will be permitted.



ANNUAL INFORMATION FORM	26	December 31, 2018

Environmental Contingencies

Mine Reclamation at Generation Facilities Not Operated by TEP. TEP pays ongoing reclamation costs related to three coal mines that supply generation facilities in which TEP has an ownership interest but does not operate. TEP's share of the reclamation costs is expected to be US$66 million upon expiry of the coal agreements, which expire between 2019 and 2031. The mine reclamation liability recognized as at December 31, 2018 was $49 million (US$36 million) and represents the present value of the estimated future liability.

Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements' terms. TEP does not believe that recognition of its final reclamation obligations will be material in any single year because recognition will occur over the remaining terms of its coal supply agreements. TEP is permitted to fully recover these costs from retail customers and, accordingly, these costs are deferred as a regulatory asset.

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, 2018, an obligation of $64 million (US$47 million) was recognized. Central Hudson has notified its insurers and intends to seek reimbursement where insurance coverage exists. Further, as authorized by the New York Public Service Commission, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for manufactured gas plant site investigation and remediation and the associated rate allowances.

CAPITAL STRUCTURE AND DIVIDENDS

Description of Capital Structure

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

As at February 14, 2019, the Corporation had issued and outstanding 428.6 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M.

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 paid quarterly.

In October 2018 Fortis increased its quarterly dividend per common share 5.9% to $0.45 per share, or $1.80 on an annualized basis. In November 2018 the Board declared a first quarter 2019 dividend on the common shares of $0.45 per share and on the First Preference Shares, Series F, G, H, I, J, K and M in accordance with the applicable prescribed rate. The first quarter dividends on the common shares and the First Preference Shares, Series F, G, H, I, J, K and M are to be paid on March 1, 2019 to holders of record as of February 15, 2019.



ANNUAL INFORMATION FORM	27	December 31, 2018

Fortis is targeting average annual dividend growth of 6% through 2023. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of its five-year capital expenditure program, and management's continued confidence in the strength of the Corporation's diversified portfolio of assets and record of operational excellence.

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



	2018	2017	2016
Common Shares	1.75	1.65	1.55
First Preference Shares, Series E⁽¹⁾	—	—	0.6126
First Preference Shares, Series F ⁽²⁾	1.2250	1.2250	1.2250
First Preference Shares, Series G⁽³⁾	1.0345	0.9708	0.9708
First Preference Shares, Series H⁽⁴⁾	0.6250	0.6250	0.6250
First Preference Shares, Series I ⁽⁵⁾	0.7116	0.5262	0.4874
First Preference Shares, Series J ⁽²⁾	1.1875	1.1875	1.1875
First Preference Shares, Series K⁽⁶⁾	1.0000	1.0000	1.0000
First Preference Shares, Series M⁽⁷⁾	1.0250	1.0250	1.0250


⁽¹⁾	In September 2016 the Corporation redeemed all of the issued and outstanding First Preference Shares, Series E.


⁽²⁾	The dividend rate on the First Preference Shares, Series F and First Preference Shares, Series J are fixed and do not reset.


⁽³⁾	The annual fixed dividend per share for the First Preference Shares, Series G was reset from $0.9708 to $1.0983 for the five-year period from September 1, 2018 up to but excluding September 1, 2023.


⁽⁴⁾	The annual fixed dividend per share for the First Preference Shares, Series H was reset from $1.0625 to $0.6250 for the five-year period from and including June 1, 2015 to but excluding June 1, 2020.


⁽⁵⁾	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%.


⁽⁶⁾	The Fixed Rate Reset First Preference Shares, Series K were issued in July 2013 at $25.00 per share and are entitled to receive cumulative dividends in the amount of $1.0000 per share per annum for the first six years.


⁽⁷⁾	The Fixed Rate Reset First Preference Shares, Series M were issued in September 2014 at $25.00 per share and are entitled to receive cumulative dividends in the amount of $1.0250 per share per annum for the first five years.

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 in July 2023, that is available for general corporate purposes. The credit facility contains a covenant which provides that Fortis shall not declare or pay any dividends or make any other restricted payments if, immediately thereafter, consolidated debt to consolidated capitalization ratio would exceed 65% at any time.

As at December 31, 2018 and 2017, the Corporation was in compliance with its debt covenant restrictions pertaining to dividend distributions, as described above.



ANNUAL INFORMATION FORM	28	December 31, 2018

Credit Ratings

Securities issued by Fortis and its utilities, that are currently rated, are rated by one or more credit rating agencies, namely DBRS, Fitch, S&P and/or Moody's. The ratings assigned to securities issued by Fortis and its utilities are reviewed by the agencies on an ongoing basis. Credit and stability ratings are intended to provide investors with an independent measure of credit quality of an issue of securities and are not recommendations to buy sell or hold securities. Ratings may be subject to revision or withdrawal at any time by the rating organization. The following table summarizes the Corporation's debt credit ratings as at February 14, 2019.



Company/Security	DBRS	S&P	Moody's
Fortis- Senior Unsecured Debt ⁽¹⁾	BBB (high), Stable	BBB+, Negative	Baa3, Stable
Caribbean Utilities-Senior Unsecured Debt ⁽¹⁾	A (low), Stable	A-, Negative	—
Central Hudson-Senior Unsecured Debt ^{(2) (3)}	—	A-, Stable	A2, Negative
FortisBC Energy
Senior Unsecured Debt	A, Stable	—	A3, Stable
Commercial Paper	R-1 (low), Stable	—	—
FortisAlberta - Senior Unsecured Debt ⁽¹⁾	A (low), Stable	A-, Negative	Baa1, Stable
FortisBC Electric
Senior Secured Debt	A (low), Stable	—	—
Senior Unsecured Debt	A (low), Stable	—	Baa1, Stable
ITC Holdings ⁽¹⁾
Senior Unsecured Debt	—	A-, Negative	Baa2, Stable
Commercial Paper	—	A-2, Negative	Prime-2, Stable
ITC Great Plains -First Mortgage Bonds ⁽¹⁾	—	A, Negative	A1, Stable
ITC Midwest - First Mortgage Bonds ⁽¹⁾	—	A, Negative	A1, Stable
ITCTransmission - First Mortgage Bonds ⁽¹⁾	—	A, Negative	A1, Stable
Maritime Electric - Senior Secured Debt	—	A, Stable	—
METC - Senior Secured Debt ⁽¹⁾	—	A, Negative	A1, Stable
Newfoundland Power - First Mortgage Bonds	A, Stable	—	A2, Stable
TEP ⁽¹⁾
Senior Unsecured Debt	—	A-, Negative	A3, Stable
Senior Unsecured Bank Credit Facility
UNS Electric
Senior Unsecured Debt	—	—	A3, Stable
Senior Unsecured Bank Credit Facility	—	—	A3, Stable
UNS Gas - Senior Unsecured Debt	—	—	A3, Stable
UNS Energy - Senior Unsecured Bank Credit Facility	—	—	Baa1, Stable

⁽¹⁾

In March 2018 S&P affirmed the Corporation's credit ratings and revised its outlook from stable to negative due to modest temporary weakening of financial measures as a result of U.S. tax reform, which reduces cash flow at the Corporation's U.S. regulated utilities. As a result of the Corporation's revised outlook, S&P also revised its outlook on Caribbean Utilities, FortisAlberta, ITC Holdings, ITC Great Plains, ITC Midwest, ITCTransmission, METC and TEP.


⁽²⁾	In July 2018 Moody's revised its outlook on Central Hudson from stable to negative due to the impacts of U.S. Tax Reform and higher capital expenditures.


⁽³⁾	Central Hudson's senior unsecured debt is also rated by Fitch at 'A-'.

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



ANNUAL INFORMATION FORM	29	December 31, 2018

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

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

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

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

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



ANNUAL INFORMATION FORM	30	December 31, 2018

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, except in exceptional circumstances determined by the Board, 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.

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



Name, Residence, Principal Occupation Within Five Preceding Years	Director Since	Committees ⁽¹⁾
	Director Since	AC	GN	HR
DOUGLAS J. HAUGHEY (Chair), Alberta, Canada Corporate Director	2009	l	l	l
TRACEY C. BALL, British Columbia, Canada Corporate Director. Executive Vice President and Chief Financial Officer of Canadian Western Bank Group from 2006 to 2014.	2014	C	l
PIERRE J. BLOUIN, Quebec, Canada Corporate Director. Chief Executive Officer of Manitoba Telecom Services, Inc. from 2005 to 2014.	2015		l	l
PAUL J. BONAVIA, Texas, USA Corporate Director. Executive Board Chair of UNS Energy from May 2014 to August 2014 and Chairman, President and Chief Executive Officer from 2009 to May 2014.	2018		l	l
LAWRENCE T. BORGARD, Florida, USA Corporate Director. President and Chief Operating Officer of Integrys Energy Group from 2007 to 2015.	2017	l		l
MAURA J. CLARK, New York, USA Corporate Director. President of Direct Energy Business at Direct Energy, a subsidiary of Centrica plc, from 2007 to 2014.	2015	l	l
MARGARITA K. DILLEY, District of Columbia, USA Corporate Director	2016	l		l
JULIE A. DOBSON, Maryland, USA Corporate Director	2018	l	l
IDA J. GOODREAU, British Columbia, Canada Corporate Director	2009		C	l
BARRY V. PERRY, Newfoundland and Labrador, Canada President and Chief Executive Officer of the Corporation. President of the Corporation from June 2014 to December 2014 and Vice President, Finance and Chief Financial Officer from 2004 to 2014.	2015	⁽²⁾
JOSEPH L. WELCH, Florida, USA Corporate Director. President and Chief Executive Officer of ITC Holdings from 2003 to 2016.	2017	⁽³⁾
JO MARK ZUREL, Newfoundland and Labrador, Canada President of Stonebridge Capital Inc., a private investment company since 2006.	2016	l		C


⁽¹⁾	Audit Committee, Governance and Nominating Committee and Human Resources Committee. "C" represents Chair.


⁽²⁾	Mr. Perry is not a member of any committees because he is the President and Chief Executive Officer of the Corporation.


⁽³⁾	Mr. Welch is not a member of any committees as he is not independent because he was President and Chief Executive Officer of ITC Holdings until October 2016. He will be considered independent in November 2019.



ANNUAL INFORMATION FORM	31	December 31, 2018

The following table sets out the name, province or state, and country of residence of each of the executive officers of Fortis and indicates the office held and principal occupations of the executive officers during the five preceding years.



Name, Residence, Principal Occupation During the Five Preceding Years	Office
BARRY V. PERRY, Newfoundland and Labrador, Canada President and Chief Executive Officer since January 2015. President from June 2014 to January 2015. Vice President, Finance and Chief Financial Officer from 2004 to June 2014.	President and Chief Executive Officer
JOCELYN H. PERRY, Newfoundland and Labrador, Canada Executive Vice President, Chief Financial Officer since June 2018. President and Chief Executive Officer of Newfoundland Power from 2017 to May 2018, Chief Financial Officer and Chief Operating Officer from 2016 to 2017 and Vice President, Finance & Chief Financial Officer from 2007 to 2016.	Executive Vice President, Chief Financial Officer
PHONSE J. DELANEY, Alberta, Canada Executive Vice President, Chief Information Officer since June 2017. President and Chief Executive Officer of FortisAlberta from 2014 to June 2017.	Executive Vice President, Chief Information Officer
NORA M. DUKE, Newfoundland and Labrador, Canada Executive Vice President, Sustainability and Chief Human Resource Officer since December 2017 and Executive Vice President, Corporate Services and Chief Human Resource Officer from August 2015 to December 2017. President and Chief Executive Officer of Fortis Properties from 2008 to August 2015.	Executive Vice President, Sustainability and Chief Human Resource Officer
DAVID G. HUTCHENS, Arizona, USA Executive Vice President, Western Utility Operations since January 2018 and President and Chief Executive Officer of UNS Energy since May 2014. President and Chief Operating Officer of UNS Energy from 2013 to May 2014.	Executive Vice President, Western Utility Operations
JAMES P. LAURITO, Florida, USA Executive Vice President, Business Development since April 2016. President and Chief Executive Officer of Central Hudson from 2010 to April 2016.	Executive Vice President, Business Development
JAMES R. REID, Ontario, Canada Executive Vice President, Chief Legal Officer and Corporate Secretary since March 2018. Partner with Davies Ward Phillips & Vineberg LLP from 2003 to March 2018.	Executive Vice President, Chief Legal Officer and Corporate Secretary
GARY J. SMITH, Newfoundland and Labrador, Canada Executive Vice President, Eastern Canadian and Caribbean Operations since June 2017. President and Chief Executive Officer of Newfoundland Power from 2014 to June 2017 and Vice President, Customer Operations and Engineering from 2008 to 2014.	Executive Vice President, Eastern Canadian and Caribbean Operations
STEPHANIE A. AMAIMO, Michigan, USA Vice President, Investor Relations since October 2017. Director, Investor Relations from 2016 to October 2017. Director, Investor Relations at ITC Holdings from 2015 to 2016 and Manager, Financial Planning and Analysis from 2013 to 2015.	Vice President, Investor Relations
KAREN J. GOSSE, Newfoundland and Labrador, Canada Vice President, Treasury and Planning since April 2018. Vice President, Planning and Forecasting from 2015 to April 2018. Vice President, Finance, and Chief Financial Officer of Fortis Properties from 2013 until 2015.	Vice President, Treasury and Planning
KAREN M. MCCARTHY, Newfoundland and Labrador, Canada Vice President, Communications and Corporate Affairs since May 2018. Director, Communications and Corporate Affairs from 2016 to May 2018. Director, Customer and Corporate Relations of Newfoundland Power from 2014 to 2016 and Manager, Corporate Affairs and Communications from 2013 to 2014.	Vice President, Communications and Corporate Affairs
REGAN P. O'DEA, Newfoundland and Labrador, Canada Vice President, General Counsel since May 2017 and Associate General Counsel from 2014 to May 2017.	Vice President, General Counsel
JAMIE D. ROBERTS, Newfoundland and Labrador, Canada Vice President, Controller since March 2013.	Vice President, Controller

As at December 31, 2018, the directors and executive officers of Fortis, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 2,416,788 common shares, representing 0.56% of the issued and outstanding common shares of Fortis. The common shares are the only voting securities of the Corporation.



ANNUAL INFORMATION FORM	32	December 31, 2018

AUDIT COMMITTEE

Members

The members of the Corporation's Audit Committee are Tracey C. Ball (Chair), Lawrence T. Borgard, Maura J. Clark, Margarita K. Dilley, Julie A. Dobson, Douglas J. Haughey and Jo Mark Zurel. All members of the Audit Committee are independent and financially literate as those terms are defined by Canadian and 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, 2019, is attached as Exhibit "C" to this AIF.

Education and Experience

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



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



ANNUAL INFORMATION FORM	33	December 31, 2018

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 ⁽¹⁾				Ernst & Young LLP ⁽²⁾
(thousands)	Description of Fee Category	2018		2017		2018		2017
Audit Fees	Represents the aggregate fees for core audit services.	$	9,121	$	7,207	$	—	$	978
Audit-Related Fees	Represents the aggregate fees for assurance and related services that are reasonably related to the audit or review of the Corporation's financial statements and are not included under Audit Fees.	1,462		1,241		—		718
Tax Fees	Represents the aggregate fees for services related to tax compliance, planning and advice.	636		497		—		7
Other	Represents the aggregate fees for services which are not Audit Services, Audit-Related Fees or Tax Fees.	27		177		—		—
Total		$	11,246	$	9,122	$	—	$	1,703


⁽¹⁾	The Corporation's external auditors effective as of May 4, 2017.


⁽²⁾	The Corporation's external auditors up to May 3, 2017.

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 United States for the common shares is Computershare Trust Company, N.A. in Canton, MA, Jersey City, NJ and Louisville, KY.

Computershare Trust Company of Canada

8^th Floor, 100 University Avenue

Toronto, ON M5J 2Y1

T: 514.982.7555 or 1.866.586.7638

F: 416.263.9394 or 1.888.453.0330

W: www.investorcentre.com/fortisinc

Computershare Trust Company, N.A.

Att: Stock Transfer Department

Overnight Mail Delivery: 250 Royall Street, Canton, Massachusetts 02021

Regular Mail Delivery: P.O. Box 43078, Providence, Rhode Island 02940-3070

T: 303.262.0600 or 1.800.962.4284



ANNUAL INFORMATION FORM	34	December 31, 2018

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 2018 Audited Consolidated Financial Statements, which are incorporated by reference in this AIF and can be found on the Corporation's website at www.fortisinc.com, on SEDAR and on EDGAR.

Further additional information, including officers' and directors' remuneration and indebtedness, principal holders of the securities of Fortis, options to purchase securities and interests of insiders in material transactions, where applicable, is contained in the Management Information Circular of Fortis dated March 16, 2018 for the May 3, 2018 annual meeting of shareholders.

Requests for additional copies of the above‑mentioned documents, as well as this 2018 Annual Information Form, should be directed to the Corporate Secretary, Fortis, P.O. Box 8837, St. John's, NL, A1B 3T2 (telephone: 709.737.2800).



ANNUAL INFORMATION FORM	35	December 31, 2018

EXHIBIT A: Summary of Terms and Conditions of Authorized Securities

Common Shares

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

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

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

Preference Shares

First Preference Shares

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

Issuance in Series

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

Priority

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

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

Voting

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



ANNUAL INFORMATION FORM	36	December 31, 2018

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 14, 2019.



	Authorized	Issued and Outstanding	Initial Yield (%)	Annual Dividend ($) ⁽¹⁾	Reset Dividend Yield (%)	Earliest Redemption and/or Conversion Option Date ⁽²⁾	Redemption Value ($)	Right to Convert on a One for One Basis
Perpetual Fixed Rate
Series F	5,000,000	5,000,000	4.90	1.2250	—	December 1, 2011	25.00	—
Series J ⁽³⁾	8,000,000	8,000,000	4.75	1.1875	—	December 1, 2017	25.75	—
Fixed Rate Reset ^{(4) (5)}
Series G ⁽⁶⁾	9,200,000	9,200,000	5.25	1.0983	2.13	September 1, 2013	25.00	—
Series H	10,000,000	7,024,846	4.25	0.6250	1.45	June 1, 2015	25.00	Series I
Series K	12,000,000	10,000,000	4.00	1.0000	2.05	March 1, 2019	25.00	Series L
Series M	24,000,000	24,000,000	4.10	1.0250	2.48	December 1, 2019	25.00	Series N
Floating Rate Reset ^{(5) (7)}
Series I ⁽³⁾	10,000,000	2,975,154	2.10	—	1.45	June 1, 2015	25.50	Series H
Series L	12,000,000	—	—	—	2.05	March 1, 2024	—	Series K
Series N	24,000,000	—	—	—	2.48	December 1, 2024	—	Series M


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


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


⁽³⁾	First Preference Shares, Series J were redeemable at $26.00 until December 1, 2018, decreasing by $0.25 each year until December 1, 2021 and redeemable at $25.00 per share thereafter. First Preference Shares, Series I are redeemable at $25.50 per share, up to but excluding June 1, 2020, and at $25.00 per share on June 1, 2020, and on every fifth anniversary date of June 1, 2020, thereafter.


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


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


⁽⁶⁾	The annual dividend per share for the First Preference Shares, Series G was reset from $0.9708 to $1.0983 for the five-year period from September 1, 2018 up to but excluding September 1, 2023.


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



ANNUAL INFORMATION FORM	37	December 31, 2018

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 14, 2019, there were no second preference shares issued and outstanding.



ANNUAL INFORMATION FORM	38	December 31, 2018

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, 2018, for the common shares on the TSX and NYSE in Canadian Dollars and US Dollars, respectively.



2018 Trading Prices and Volumes – Common Shares
	TSX			NYSE
Month	High ($)	Low ($)	Volume	High (US$)	Low (US$)	Volume
January	46.00	42.56	23,833,658	36.76	34.49	6,373,078
February	43.48	39.38	27,141,195	35.35	31.41	8,235,162
March	43.83	41.52	26,194,320	34.03	32.26	6,702,318
April	43.83	41.76	15,120,177	34.19	32.83	4,541,728
May	43.60	41.31	17,886,103	33.79	31.84	3,684,268
June	42.41	40.21	18,718,490	32.02	30.88	7,246,839
July	43.18	41.71	15,867,578	33.02	31.55	6,192,773
August	43.65	42.05	17,701,954	33.42	32.11	4,534,468
September	43.14	41.67	17,025,568	33.00	32.09	4,581,920
October	44.04	40.71	33,041,713	33.84	31.37	8,895,053
November	47.06	42.60	28,786,806	35.82	32.48	6,370,720
December	47.36	43.49	27,966,319	35.86	31.80	8,971,281

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, 2018.



2018 Trading Prices and Volumes – First Preference Shares
	First Preference Shares, Series F			First Preference Shares, Series G
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	24.56	23.90	52,581	23.46	21.80	314,574
February	24.01	23.14	116,545	23.49	22.65	481,057
March	23.40	23.04	26,613	22.89	21.69	164,323
April	23.37	22.88	49,779	21.86	21.35	360,277
May	23.35	22.62	22,564	22.75	21.41	263,086
June	23.00	22.56	44,988	22.00	21.69	131,944
July	23.05	22.74	91,350	22.46	21.59	99,568
August	23.09	22.67	117,689	22.45	21.81	71,417
September	22.90	22.68	38,973	22.21	21.55	108,121
October	22.78	21.53	78,511	21.94	19.76	347,351
November	22.42	21.21	76,509	20.96	18.01	93,717
December	22.38	20.66	54,125	19.34	16.85	384,885



ANNUAL INFORMATION FORM	39	December 31, 2018



	First Preference Shares, Series H			First Preference Shares, Series I
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	19.27	17.95	448,894	19.41	17.10	149,365
February	18.95	18.39	58,465	19.00	18.22	60,571
March	18.55	17.72	117,162	18.69	17.69	11,052
April	18.04	17.46	48,388	17.90	17.53	13,728
May	18.96	17.83	47,539	18.84	17.85	52,500
June	18.81	18.29	138,802	18.65	18.07	106,500
July	18.80	18.20	57,802	18.85	18.21	22,735
August	18.76	18.30	153,861	19.05	18.50	16,689
September	18.58	18.21	26,453	18.90	18.42	15,800
October	18.51	17.09	292,217	19.33	17.42	67,159
November	17.94	15.61	68,366	18.33	16.26	19,705
December	16.18	14.22	145,708	16.65	13.64	37,628
	First Preference Shares, Series J			First Preference Shares, Series K
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	23.48	22.77	88,753	22.98	21.61	157,367
February	23.20	22.10	73,891	23.00	22.35	60,197
March	22.66	22.23	64,898	22.60	21.52	232,405
April	22.80	22.12	71,416	21.72	21.28	75,323
May	22.60	21.89	126,261	22.70	21.58	108,200
June	22.28	21.90	153,957	21.99	21.50	52,196
July	22.45	22.10	80,266	21.88	21.37	65,424
August	22.45	21.92	182,692	22.06	21.58	346,042
September	22.08	21.87	108,890	21.87	21.47	112,970
October	22.03	20.77	153,462	21.94	20.05	237,944
November	21.71	20.45	93,375	21.11	18.05	163,491
December	21.88	20.26	138,827	18.41	16.17	180,451
	First Preference Shares, Series M
Month	High ($)	Low ($)	Volume
January	24.41	23.65	921,049
February	24.45	23.67	218,630
March	23.96	23.28	158,451
April	23.66	23.26	175,864
May	24.07	23.35	1,231,722
June	25.00	23.40	412,482
July	23.98	23.24	195,966
August	24.22	23.71	75,810
September	24.20	23.64	178,167
October	24.07	22.15	203,354
November	23.23	19.56	208,333
December	19.97	17.45	505,883



ANNUAL INFORMATION FORM	40	December 31, 2018

EXHIBIT C: AUDIT COMMITTEE MANDATE


1.0	PURPOSE AND AUTHORITY

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


(a)	the integrity of the Corporation's financial statements, financial disclosures and internal controls over financial reporting;


(b)	the Corporation's compliance with related legal and regulatory requirements;


(c)	the qualifications, independence and performance of the Independent Auditor and Internal Auditor;


(d)	the related policies of the Corporation set out herein; and


(e)	other matters set out herein or otherwise delegated to the Committee by the Board.

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

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

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

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


2.0	DEFINITIONS

2.1 In this Mandate:

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

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


(c)	"Committee" means the audit committee appointed by the Board pursuant to this Mandate;


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

(e) "Corporation" means Fortis Inc.;

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



ANNUAL INFORMATION FORM	41	December 31, 2018

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


(h)	"ERM Program" means the Corporation's Enterprise Risk Management Program that incorporates an effective risk management framework and applies a logical and systematic methodology to identify, evaluate, treat, monitor and communicate key corporate risks;


(i)	"Financial Expert" means an "audit committee financial expert" as defined in Item 407(d)(5) of SEC Regulation S‑K;


(j)	"Financially Literate" means having the ability to read and understand a set of financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breath and complexity of the issues that can reasonably be expected to be present in the Corporation's financial statements;


(k)	"Governance and Nominating Committee" means the governance and nominating committee of the Board;


(l)	"Independent" means, in the context of a Member and in accordance with applicable law and stock exchange requirements, free from any direct or indirect material relationship with the Corporation and its subsidiaries which, in the view of the Board, could reasonably be expected to interfere with the exercise of a Member's independent judgment;


(m)	"Independent Auditor" means the firm of chartered professional accountants, registered with the CPAB and the PCAOB, and appointed by the Shareholders to act as external auditor;


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

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

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


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

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

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


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

(u)

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

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

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



ANNUAL INFORMATION FORM	42	December 31, 2018

3.0 ESTABLISHMENT AND COMPOSITION OF COMMITTEE

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

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

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

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

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

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


4.0	COMMITTEE MEETINGS

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

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

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

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

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

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



ANNUAL INFORMATION FORM	43	December 31, 2018

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

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


5.0	SPECIFIC RESPONSIBILITIES AND DUTIES OF THE COMMITTEE

A. Independent Auditor

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

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

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

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

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

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


(a)	review and discuss with Management and separately with the Independent Auditor the results of the Corporation's annual Independent Auditor assessment process; and

(b)

at least annually, obtain and review a report from the Independent Auditor describing the firm's internal quality control process and procedures, including any material issues raised by the most recent internal quality-control review or peer review, or by any inquiry or investigation by governmental or professional authorities (including without limitation the PCAOB and the CPAB) within the preceding five years with respect to independent audits carried out by the Independent Auditor, and any steps taken to deal with such issues.



ANNUAL INFORMATION FORM	44	December 31, 2018

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

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

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


B.	Financial Reporting

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


(a)	reports regarding: (i) critical accounting estimates, policies and practices; (ii) goodwill impairment testing; (iii) derivatives and hedges; and (iv) the effect of regulatory and accounting initiatives, as well as off-balance sheet structures, on the Corporation's financial statements;

(b)

analyses by Management and the Independent Auditor regarding significant financial reporting issues and judgements made in connection with the preparation of the Corporation's consolidated financial statements including: (i) alternative treatments of financial information within generally accepted accounting principles related to material matters that have been discussed with Management, their ramifications and the treatment preferred by the Independent Auditor; (ii) major issues regarding accounting principles and presentations, including significant changes in the selection or application of accounting principles; and (iii) major issues regarding the adequacy of the Corporation's internal controls and any specific audit steps adopted in light of material weaknesses or significant deficiencies in internal controls; and


(c)	other material written communication between Management and the Independent Auditor.

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


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


(b)	Management's report and the Independent Auditor's audit report on internal controls over financial reporting;


(c)	significant reports or summaries thereof pertaining to the Corporation's processes for compliance with the requirements of the Sarbanes Oxley Act of 2002 with respect to internal controls over financial reporting;

(d)

the Independent Auditor's quarterly review reports and annual audit results report summarizing the scope, status, results and recommendations of the quarterly reviews of the Corporation's interim condensed consolidated financial statements and of the audit of the Corporation's annual consolidated financial statements and related audit of internal controls over financial reporting, and also containing at least: (i) the



ANNUAL INFORMATION FORM	45	December 31, 2018

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;


(e)	the Report to Shareholders contained in the Corporation's annual report; and


(f)	any other document that the Committee determines should be reviewed and discussed with Management and the Independent Auditor or for which a legal or regulatory requirement in that regard exists.

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

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

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

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


(b)	the Annual Information Form and Management Information Circular to be filed by the Corporation;


(c)	any prospectus or other offering documents and documents related thereto for the issuance of securities by the Corporation; and


(d)	other financial information and disclosure documents to be released publicly.

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

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

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

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



ANNUAL INFORMATION FORM	46	December 31, 2018

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

C. Internal Audit

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

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

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

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

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

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

D. Risk Management and Other

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

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

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

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


E.	Policies and Mandate

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


(a)	Policy on Reporting Allegations of Suspected Improper Conduct and Wrongdoing (including overseeing procedures for the receipt, retention, and treatment of complaints regarding accounting, internal controls, or auditing matters as well as procedures for confidential, anonymous submissions by employees regarding questionable accounting or auditing matters as required by applicable law);


(b)	Derivative Instruments and Hedging Policy;


(c)	Pre-Approval Policy for Independent Auditor Services;


(d)	Hiring from Independent Auditing Firms Policy;


(e)	Policy on the Role of the Internal Audit Function;



ANNUAL INFORMATION FORM	47	December 31, 2018


(f)	Disclosure Policy; and


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

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

6.0 REPORTING

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

7.0 REMUNERATION OF MEMBERS

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

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

8.0 GENERAL

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

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

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

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



ANNUAL INFORMATION FORM	48	December 31, 2018

EXHIBIT D: MATERIAL CONTRACTS

The following are the material contracts of Fortis filed on SEDAR and EDGAR during 2018 or which were entered into prior to 2018 and are still in effect. Requests for additional copies of these material contracts should be directed to the Corporate Secretary, Fortis, P.O. Box 8837, St. John's, NL, A1B 3T2 (telephone: 709.737.2800). All such contracts are also available under the Corporation's profile at www.sedar.com and www.sec.gov.

Revolving Credit Facility

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

Shareholders' Agreement

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

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

Indenture and First Supplemental Indenture

On October 4, 2016, Fortis entered into an Indenture and a First Supplement thereto with The Bank of New York Mellon, as 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 outstanding US$500 million aggregate principal amount of 2.100% Unsecured Notes due 2021 and US$1.5 billion aggregate principal amount of 3.055% Unsecured Notes due 2026. The Indenture contains customary covenants, events of default and rights for the benefit of security holders and the trustees. An unlimited amount of debt securities may be issued under the Indenture, which is governed by the laws of the State of New York.



ANNUAL INFORMATION FORM	49	December 31, 2018