Exhibit 99.1

FORTIS INC.

ANNUAL INFORMATION FORM

FOR THE YEAR ENDED DECEMBER 31, 2017

February 14, 2018

ANNUAL INFORMATION FORM

For the year ended December 31, 2017

Dated February 14, 2018

CONTENTS
Forward-Looking Information	2	Corporate Social Responsibility	25
Definitions	3	Social and Diversity Policies	25
Corporate Structure	6	Environmental, Sustainability and Regulatory
Name and Incorporation	6	Oversight	26
Inter-Corporate Relationships	6	Environmental Contingencies	26
General Development of the Business	7	Capital Structure and Dividends	27
Overview	7	Description of Capital Structure	27
Three-Year History	7	Dividends and Distributions	27
Outlook	8	Prior Sales	28
Description of the Business	8	Credit Ratings	29
Regulated Utilities – United States	9	Directors and Officers	31
ITC	9	Audit Committee	33
UNS Energy	12	Members	33
Central Hudson	14	Education and Experience	33
Regulated Utilities – Canada	15	Pre-Approval Policies and Procedures	34
FortisBC Energy	15	External Auditor Service Fees	34
FortisAlberta	17	Transfer Agent and Registrar	34
FortisBC Electric	18	Auditors	35
Eastern Canadian	20	Additional Information	35
Regulated Utilities – Caribbean	22
Non-Regulated	23	Exhibit A: Summary of Terms and
Energy Infrastructure	23	Conditions of Authorized Securities	36
Corporate and Other	23	Exhibit B: Market for Securities	39
Human Resources	24	Exhibit C: Audit Committee Mandate	41
Legal Proceedings and Regulatory Actions	25	Exhibit D: Material Contracts	48
Risk Factors	25

ANNUAL INFORMATION FORM 1 December 31, 2017

FORWARD-LOOKING INFORMATION

The following 2017 Annual Information Form has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. Financial information for 2017 and comparative periods contained in the 2017 Annual Information Form has been prepared in accordance with US GAAP and is presented in Canadian dollars unless otherwise specified. Capitalized terms used herein are defined under the heading "Definitions" on page 3.

Except as otherwise stated, the information in the 2017 Annual Information Form is given as of December 31, 2017.

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 Corporation's forecast gross consolidated capital expenditures for the period 2018 to 2022; the expectation that long-term sustainable growth in rate base will support continuing growth in earnings and dividends; target average annual dividend growth through 2022;the impact of U.S. Tax Reform on the Corporation's earnings per share, cash flows at the Corporation's U.S. regulated utilities and rate base growth;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; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the expected timing of the commissioning of the 8.75-MW engine at FortisTCI; 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; 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 continuation of regulator approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; no significant counterparty defaults; 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; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans, environmental laws and regulations that may materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; 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; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital program.

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, 2017 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 2018 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; the impact of the Tax Cuts and Jobs Act on the Corporation's future results of operations and cash flows; risk associated with the impacts of less favourable economic conditions on the Corporation's results of operations; risk associated with the Corporation's ability to continue to comply with Section 404(a) of the Sarbanes-Oxley Act of 2002 and the related rules of the U.S. Securities and Exchange Commission and the Public Company Accounting Oversight Board; 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.

ANNUAL INFORMATION FORM 2 December 31, 2017

DEFINITIONS

Certain terms used in this 2017 Annual Information Form are defined below:

"2017 Annual Information Form" or "AIF" means this annual information form of the Corporation in respect of the year ended December 31, 2017;

"$" means Canadian dollars;

"2017 Audited Consolidated Financial Statements" means the audited consolidated financial statements of the Corporation as at and for the years ended December 31, 2017 and 2016 and related notes thereto;

"AC" means alternating current;

"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.;

"CEC" means Consumers Energy Company;

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

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

"Common Shares" means the common shares of the

Corporation;

"COPE" means the Canadian Office and Professional

Employees Union;

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

"Corporation" means Fortis Inc.;

"CPA" means the Canal Plant Agreement;

"CPC/CBT" means Columbia Power Corporation and Columbia Basin Trust;

"CUPE" means the Canadian Union of Public Employees;

"DBRS" means DBRS Limited;

"DC" means direct current;

"DTE" means DTE Electric Company;

"Eastern Canadian Electric Utilities" means, collectively, the operations of Newfoundland Power, Maritime Electric and FortisOntario;

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

"Ethos" means EthosEnergy Power Plant Services, LLC;

"External Auditor" means the firm of Chartered Professional Accountants registered with the Canadian Public Accountability Board or its successor and appointed by the shareholders of the Corporation to act as external auditor of the Corporation;

"FAES" means FortisBC Alternative Energy Services Inc.;

"FERC" means the United States Federal Energy Regulatory Commission;

"FHI" means FortisBC Holdings Inc., the parent company of FortisBC Energy;

"Fitch" means Fitch Ratings Inc.;

"Fortis" means Fortis Inc.;

"FortisAlberta" means FortisAlberta Inc.;

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

ANNUAL INFORMATION FORM 3 December 31, 2017

"FortisBC Energy" means FortisBC Energy Inc.;

"FortisOntario" means FortisOntario Inc.;

"Fortis Properties" means Fortis Properties Corporation;

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

"FortisTCI" means FortisTCI 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;

"IBEW" means the International Brotherhood of Electrical Workers;

"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;

"Management" means, collectively, the senior officers of the Corporation;

"Maritime Electric" means Maritime Electric Company, Limited;

"MD&A" means the Corporation's Management Discussion and Analysis prepared in accordance with National Instrument 51-102 – Continuous Disclosure Obligations, in respect of the Corporation's annual consolidated financial statements for the year ended December 31, 2017;

"METC" means Michigan Electric Transmission Company;

"MGP" means manufactured gas plant;

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

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

"NB Power" means New Brunswick Power Corporation;

"Newfoundland Hydro" means Newfoundland and Labrador Hydro Corporation;

"Newfoundland Power" means Newfoundland Power Inc.;

"NYSE" means the New York Stock Exchange;

"OEB" means the Ontario Energy Board;

"PCAOB" means the Public Company Accounting Oversight Board;

"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;

ANNUAL INFORMATION FORM 4 December 31, 2017

"Teck" means Teck Resources Limited;

"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.;

"U.S." or "USA" means the United States of America;

"US$" means US dollars;

"US GAAP" means accounting principles generally accepted in the U.S.;

"U.S. Tax Reform" means the Tax Cuts and Jobs Act, signed into law by the President of the United States on December 22, 2017;

"UUWA" means the United Utility Workers' Association of Canada;

"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.

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) MW    Megawatt(s) MWh    Megawatt hour(s) TJ    Terajoule(s) PJ    Petajoule(s)

ANNUAL INFORMATION FORM 5 December 31, 2017

CORPORATE STRUCTURE

Name and Incorporation

Fortis 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 are 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, 2018. The principal subsidiaries together comprise approximately 87% of the Corporation's consolidated assets as at December 31, 2017 and approximately 84% of the Corporation's 2017 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, 2017.

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, an Arizona corporation, 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, 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 Inc., an Alberta corporation, owns all of the shares of FortisAlberta. FortisWest, a Canadian corporation, owns all of the shares of FortisAlberta Holdings Inc. Fortis owns all of the shares of FortisWest.

⁽⁶⁾  The Corporation 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, 2018, 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 6 December 31, 2017

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Fortis is a leader in the North American regulated electric and gas utility business, with total assets of approximately $48 billion as at December 31, 2017 and fiscal 2017 revenue of $8.3 billion. Approximately 8,500 employees of the Corporation serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries. In 2017 the Corporation's electricity systems met a combined peak demand of 32,134 MW and its gas distribution systems met a peak day demand of 1,585 TJ. As at December 31, 2017, approximately 65% of the Corporation's assets were located outside of Canada and approximately 59% of the Corporation's revenue was derived from foreign operations.

Three-Year History

Over the past three years, Fortis has experienced significant growth in its business operations. Total assets have almost doubled from $26.2 billion as at December 31, 2014 to $47.8 billion as at December 31, 2017. The Corporation's shareholders' equity has also grown significantly from $9.1 billion as at December 31, 2014 to $16.7 billion as at December 31, 2017. Net earnings attributable to common equity shareholders have increased from $317 million in 2014 to $963million in 2017.

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

In April 2015 the Corporation completed construction of the $900 million, 335-MW Waneta Expansion hydroelectric generating facility ahead of schedule and on budget. Fortis has a 51% controlling ownership interest in the Waneta Expansion and operates and maintains the non-regulated investment.

In June 2015 the Corporation completed the sale of the commercial real estate assets of Fortis Properties for gross proceeds of $430 million to a subsidiary of Slate Office REIT. As part of the transaction, Fortis subscribed to trust units of Slate Office REIT for total consideration of approximately $35 million. In November 2016, Fortis sold its Slate Office REIT trust units for aggregate gross proceeds of approximately $37 million.

In October 2015 the Corporation completed the sale of the hotel assets of Fortis Properties for gross proceeds of $365 million to a private investor group.

In June and July of 2015, the Corporation completed the sale of its non-regulated generation assets in Upstate New York and Ontario, respectively, for gross proceeds of approximately $93 million.

In August 2015 the Corporation reached a settlement with the Government of Belize regarding the expropriation of the Corporation's approximate 70% interest in Belize Electricity. The terms of the settlement included a one-time US$35 million cash payment to Fortis and an approximate 33% equity investment in Belize Electricity.

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 now 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 a SEC registrant in May 2016 and in October 2016 its 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.

ANNUAL INFORMATION FORM 7 December 31, 2017

The Corporation's gross consolidated capital expenditures for 2017 were approximately $3.0 billion. Over the past three years, including 2017, gross consolidated capital expenditures totalled $7.3 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 construction of the Waneta Expansion, which commenced production in April 2015, and the acquisition of Aitken Creek in April 2016.

Outlook

Fortis is focused on executing the five-year capital expenditure program of approximately $14.5 billion for 2018 through 2022 and securing further organic growth opportunities at its subsidiaries. Fortis expects the long-term sustainable growth in rate base to support continuing growth in earnings and dividends. 

Fortis has targeted average annual dividend growth of approximately 6% through 2022. 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 expenditure program, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence. 

Fortis expects its annual earnings per share will be reduced in the range of 3-4%, as a result of U.S. Tax Reform and near-term cash flows of the Corporation's U.S. regulated utilities will be reduced due to the lower corporate tax rate. Going forward, the impact of U.S. Tax Reform will increase rate base growth over the five-year period to 2022 by approximately 50 basis points. Consequently, the compound annual growth in rate base over the next five years is expected to increase to 5%.

DESCRIPTION OF THE BUSINESS

Fortis is principally a regulated electric and gas utility holding company. Fortis segments its business based on regulatory status and service territory, as well as information used by the chief operating decision maker in deciding on how to allocate resources and evaluate the performance of the segment. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long‑term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes responsibility for net earnings and its own resource allocation.

The majority of the Corporation's regulated utilities operate as the sole supplier of electricity and/or gas within their respective service territories. The Corporation's regulated utilities own and operate facilities that generate, transmit and distribute electricity and/or gas to their customers in their service territories. Competition in the regulated electric business is primarily from alternative energy sources and on-site generation by industrial customers. The Corporation faces competition in its transmission business which may restrict its ability to grow such 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. The growth in the North American natural gas supply, primarily from shale gas production, has resulted in a lower natural gas price environment, which has helped improve natural gas competitiveness on an operating basis. Nevertheless, upfront capital cost differences between electricity and natural gas equipment continue to present a challenge 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 the 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.

The following sections describe the operations included in each of the Corporation's reportable segments.

ANNUAL INFORMATION FORM 8 December 31, 2017

Regulated Utilities – United States

ITC

ITC's business consists primarily of the electric transmission operations of the ITC Regulated Operating Subsidiaries. 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 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 owns and operates more than 25,000 km of transmission lines.

As electric transmission utilities regulated by FERC, ITC's Regulated Operating Subsidiaries earn revenues for the use of their electric transmission systems by their respective customers, which include 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 by ITC's Regulated Operating Subsidiaries are established using cost-based formula rates.

ITC's principal transmission service customers are DTE, CEC 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.

Market and Sales

Revenues

ITC derives nearly all of its revenues from providing transmission, scheduling, control and dispatch services and other related services over ITC's Regulated Operating Subsidiaries' transmission systems to DTE, CEC, IPL and other entities, such as alternative electricity suppliers, power marketers and other wholesale customers that provide electricity to end-use consumers, 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 DTE, CEC, IPL and other 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 from ITC Great Plains include the annual revenue requirements specific to projects that are charged exclusively within one pricing zone within SPP or are classified as direct assigned network upgrades under the SPP tariff, and contain a true-up mechanism.

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.

Regional cost-sharing revenues are generated from transmission customers throughout Regional Transmission Organization regions 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 revenue also includes 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 treated as a revenue credit to regional or network customers and is a reduction to the gross revenue requirement when calculating the net revenue requirement under ITC's cost-based formula rates.

ANNUAL INFORMATION FORM 9 December 31, 2017

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

Other revenuesconsist of rental revenues, easement revenues, revenues relating to utilization 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 revenue credit and taken as a reduction to the gross revenue requirement when calculating the net revenue requirement under ITC's cost-based formula rates.

The following table compares the composition of ITC's 2017 and 2016 revenue by customer class.

	Revenue (%)
	2017	2016 (1)
Network revenues	67	72
Regional cost-sharing revenues	28	30
Point-to-point	2	2
Scheduling, control and dispatch	1	1
Other	2	2
Recognition of refund liabilities (2)	-	(7)
Total	100	100

⁽¹⁾  The information presented is for the year ended December 31, 2016. ITC was acquired by Fortis in October 2016, therefore, only financial results from the date of acquisition, October 14, 2016, are reflected in the Corporation's 2016 Audited Consolidated Financial Statements.

⁽²⁾  Mainly represents return on common shareholder's equity refund liabilities associated with third-party complaints filed with FERC challenging the base return on common shareholder's equity of the ITC MISO Regulated Operating Subsidiaries.

Material 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 the following:

Master Operating Agreement. The Master Operating Agreement governs the primary day-to-day operational responsibilities of ITCTransmission and DTE. This 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. The Generator Interconnection and Operation Agreement established, re-established and maintains the direct electricity interconnection of DTE's electricity generating assets with ITCTransmission's transmission system for the purposes of transmitting electric power from and to the electricity generating facilities.

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

METC

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

ANNUAL INFORMATION FORM 10 December 31, 2017

Amended and Restated Easement Agreement. Under the Amended and Restated Easement Agreement, CEC 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 CEC and others are located. METC pays CEC 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. CEC retained for itself the rights to, and the value of activities associated with, all other uses of the premises and the facilities covered by the Easement Agreement, such as for distribution of electricity, fiber optics, telecommunications, gas pipelines and agricultural uses.

Amended and Restated Operating Agreement. Under the Amended and Restated Operating Agreement, METC agrees to operate its transmission system to provide all transmission customers with safe, efficient, reliable and nondiscriminatory transmission service pursuant to its tariff. METC is also responsible for maintaining and operating its transmission system, providing CEC 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 CEC, building connection facilities necessary to permit interaction with new distribution facilities built by CEC.

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 CEC. Currently, under the Amended and Restated Purchase and Sale Agreement for Ancillary Services, METC pays CEC 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. CEC will offer all ancillary services as required by FERC Order No. 888 at FERC-approved rates. METC is not precluded from procuring these ancillary services from third-party suppliers and is free to purchase ancillary services from unaffiliated generators located within its control area or neighboring jurisdictions on a non-preferential, competitive basis.

Amended and Restated Distribution-Transmission Interconnection Agreement. The Amended and Restated Distribution-Transmission Interconnection Agreement provides for the interconnection of CEC'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. The Amended and Restated Generator Interconnection Agreement specifies the terms and conditions under which CEC and METC maintain the interconnection of CEC's generation resources and METC's transmission assets.

ITC Midwest

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

Distribution-Transmission Interconnection Agreement. The Distribution-Transmission Interconnection Agreement governs the rights, responsibilities and obligations of ITC Midwest and IPL, with respect to the use of certain of their own and the other 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 the Large Generator Interconnection Agreement in order to establish, re-establish and maintain the direct electricity interconnection of IPL's electricity generating assets with ITC Midwest's transmission system for the purpose of transmitting electric power from and to the electricity generating facilities.

ANNUAL INFORMATION FORM 11 December 31, 2017

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 674,000 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 422,000 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 96,000 retail customers in Arizona's Mohave and Santa Cruz counties, which have a combined population of approximately 251,000.

TEP and UNS Electric currently own generation resources with an aggregate capacity of 2,834 MW, including 64 MW of solar capacity. Several of the generating assets in which TEP and UNS Electric have an interest are jointly owned. TEP has sufficient generating 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, 2017, approximately 44% of the generating capacity was fuelled by coal.

UNS Gas is a regulated gas distribution utility that serves approximately 156,000 retail customers in Arizona's Mohave, Yavapai, Coconino, Navajo and Santa Cruz counties, which have a combined population of approximately 728,000.

Market and Sales

UNS Energy's electricity sales were 14,971 GWh for 2017, compared to 14,387 GWh for 2016. 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 for 2017 and 2016. Revenue was $2,080 million for 2017, compared to $2,002 million for 2016.

The following table provides the composition of UNS Energy's 2017 and 2016 revenue, electricity sales, and gas volumes by customer class.

	Revenue (%)		GWh Sales (%)		PJ Volumes (%)
	2017	2016	2017	2016	2017	2016
Residential	38.1	38.0	31.1	31.8	56.4	54.6
Commercial	23.1	23.4	19.2	19.3	24.7	23.8
Industrial	14.5	16.3	20.3	21.9	2.1	2.0
Other (1)	24.3	22.3	29.4	27.0	16.8	19.6
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 2,531 MW and its T&D system consisting of approximately 15,800 km of line. In 2017, TEP met a peak demand of 2,915 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.

ANNUAL INFORMATION FORM 12 December 31, 2017

TEP's generating capacity as of December 31, 2017, measured in DC, is set forth in the following table.

Generating Source	Unit No.	Location	Date in Service	Resource Type	Total Capacity (MW)	Operating Agent	TEP's Share (%)	TEP's Share (MW)
Springerville Station	1	Springerville, AZ	1985	Coal	387	TEP	100.0	387
Springerville Station	2	Springerville, AZ	1990	Coal	406	TEP	100.0	406
San Juan Station	1	Farmington, NM	1976	Coal	340	PNM	50.0	170
Navajo Station	1	Page, AZ	1974	Coal	750	SRP	7.5	56
Navajo Station	2	Page, AZ	1975	Coal	750	SRP	7.5	56
Navajo Station	3	Page, AZ	1976	Coal	750	SRP	7.5	56
Four Corners Station	4	Farmington, NM	1969	Coal	785	APS	7.0	55
Four Corners Station	5	Farmington, NM	1970	Coal	785	APS	7.0	55
Gila River Power Station	3	Gila Bend, AZ	2003	Gas	550	Ethos	75.0	413
Luna Generating Station	1	Deming, NM	2006	Gas	555	PNM	33.3	185
Sundt Station	1	Tucson, AZ	1958	Gas/Oil	81	TEP	100.0	81
Sundt Station	2	Tucson, AZ	1960	Gas/Oil	81	TEP	100.0	81
Sundt Station	3	Tucson, AZ	1962	Gas	104	TEP	100.0	104
Sundt Station	4	Tucson, AZ	1967	Gas	156	TEP	100.0	156
Sundt Internal Combustion Turbines		Tucson, AZ	1972-1973	Gas/Oil	50	TEP	100.0	50
DeMoss Petrie		Tucson, AZ	2001	Gas	75	TEP	100.0	75
North Loop		Tucson, AZ	2001	Gas	94	TEP	100.0	94
Springerville Solar Station		Springerville, AZ	2002-2014	Solar	16	TEP	100.0	16
Tucson Solar Projects		Tucson, AZ	2010-2014	Solar	13	TEP	100.0	13
Ft. Huachuca Project (1)		Ft. Huachuca, AZ	2014-2017	Solar	22	TEP	100.0	22
Total Capacity								2,531

⁽¹⁾  In January 2017, a second phase of the Ft. Huachuca Project was commissioned adding 5 MW of solar to TEP's total generating capacity.

On December 20, 2017, San Juan Unit 2 was removed from service. TEP's 50% share of San Juan Unit 2's nominal capacity was 170 MW.

UNS Electric meets the electricity supply requirements of its retail customers through a mix of its own generation and power purchase contracts. UNS Electric owns and operates several gas and diesel‑fuelled generating plants, with a collective electrical generating capacity of 303MW. In 2017, UNS Electric met a peak demand of 463 MW by utilizing its generating capacity and purchasing power on the wholesale market.

UNS Electric's generating capacity as of December 31, 2017, measured in DC, is set forth in the following table.

Generating 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	Purchased 2003	Gas/Oil	14	UNSE	100.0	14
Valencia	2	Nogales, AZ	Purchased 2003	Gas/Oil	14	UNSE	100.0	14
Valencia	3	Nogales, AZ	Purchased 2003	Gas/Oil	14	UNSE	100.0	14
Valencia	4	Nogales, AZ	Purchased 2003	Gas/Oil	21	UNSE	100.0	21
Gila River Power Station	3	Gila Bend, AZ	2003	Gas	550	Ethos	25.0	137
La Senita		Kingman, AZ	2011	Solar	1	UNSE	100.0	1
Rio Rico		Rio Rico, AZ	2014	Solar	7	UNSE	100.0	7
Jacobson		Kingman, AZ	2017	Solar	5	UNSE	100.0	5
Total Capacity								303

ANNUAL INFORMATION FORM 13 December 31, 2017

Each of TEP and UNS Electric are subject to government-mandated renewable energy requirements. TEP satisfies these requirements through its 51 MW, measured in DC, of owned photovoltaic solar generating capacity and PPAs for capacity from solar resources (198 MW measured in DC), wind resources (80 MW measured in AC) and a landfill gas generation plant (4 MW measured in AC). UNS Electric satisfies its renewable energy requirements through its 13 MW, measured in DC, of owned photovoltaic solar generating capacity and PPAs for capacity from solar resources (48 MW measured in DC) and wind resources (10 MW measured in AC).

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.

TEP and UNS Gas purchase the majority of their gas supply from the San Juan and Permian Basins. The gas is delivered on the El Paso Natural Gas, L.L.C. and Transwestern Pipeline Company interstate pipeline systems under firm transportation agreements with combined capacity sufficient to meet TEP's gas-fired generation needs and the demands of UNS Gas' customers.

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 6,734 square km in the Hudson Valley. Electric service is available throughout the territory, and natural gas service is provided in and about the cities of Poughkeepsie, Beacon, Newburgh, and Kingston, New York, and in certain outlying and intervening territories.

Central Hudson's electric transmission system consists of approximately 1,000 km of line. The Central Hudson electric distribution system consists of approximately 11,600 km of overhead lines and 2,600 trench km of underground lines, as well as customer service lines and meters. Central Hudson's electricity system met a peak demand of 1,034 MW in 2017.

Central Hudson's natural gas system consists of approximately 300 km of transmission pipelines and 2,000 km of distribution pipelines, as well as customer service lines and meters. In 2017 Central Hudson's natural gas system met a peak day demand of 144 TJ.

Market and Sales

Central Hudson's electricity sales were 4,891 GWh for 2017, compared to 5,112 GWh for 2016. Natural gas sales volumes for 2017 were 22 PJ, compared to 24 PJ for 2016. Revenue was $872 million for 2017, compared to $849 million in 2016.

The following table compares the composition of Central Hudson's 2017 and 2016 revenue, electricity sales and gas volumes by customer class.

	Revenue (%)		GWh Sales (%)		PJ Volumes (%)
	2017	2016	2017	2016	2017	2016
Residential	61.5	61.3	40.5	41.4	25.1	24.6
Commercial	27.6	26.7	39.0	37.5	34.5	33.0
Industrial	3.8	4.4	19.0	19.5	20.5	21.8
Other	5.6	5.5	0.6	0.6	7.6	7.4
Sales for Resale	1.5	2.1	0.9	1.0	12.3	13.2
Total	100.0	100.0	100.0	100.0	100.0	100.0

ANNUAL INFORMATION FORM 14 December 31, 2017

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.

During 2016, Central Hudson entered into an agreement with Entergy Nuclear Power Marketing, LLC to purchase electricity, on a unit contingent basis at defined prices, from December 1, 2016 through March 31, 2017. The maximum commitment under this agreement was approximately US$3.3 million, of which US$2.7 million related to the first quarter of 2017. This contract expired on March 31, 2017 and was not renewed.

Central Hudson's PPA to purchase capacity from the Roseton Generating Facility expired in April 2017 and was not renewed. Central Hudson is a party to a PPA to purchase capacity from the Danskammer Generating Facility, expiring August 2018, with approximately US$18.9 million in purchase commitments remaining as at December 31, 2017.

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.

Regulated Utilities – Canada

FortisBC Energy

FortisBC Energy is the largest distributor of natural gas in British Columbia, serving approximately 1,008,000 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 49,000 km of natural gas pipelines and met a peak day demand of 1,336 TJ in 2017.

Market and Sales

FortisBC Energy's natural gas sales volumes were 221 PJ in 2017, compared to 197 PJ in 2016. Revenue was $1,198 million in 2017 compared to $1,151 million in 2016.

ANNUAL INFORMATION FORM 15 December 31, 2017

The following table compares the composition of FortisBC Energy's 2017 and 2016 revenue and natural gas volumes by customer class.

	Revenue (%)		PJ Volumes (%)
	2017	2016	2017	2016
Residential	58.4	57.0	37.1	36.0
Commercial	28.6	27.5	23.5	21.8
Industrial	2.1	1.7	1.8	2.0
Transportation	9.0	9.3	32.1	34.5
Other (1)	1.9	4.5	5.5	5.7
Total	100.0	100.0	100.0	100.0

⁽¹⁾  Includes amounts under fixed-revenue contracts, revenue from sources other than from the sale of natural gas and other regulatory adjustments, such as deferral mechanisms, that are recorded for rate-setting purposes.

Gas Purchase Agreements

In order to ensure supply of adequate resources to provide 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 146 PJ of baseload and seasonal supply, of which the majority is sourced in northeast British Columbia and transported on Enbridge Inc.'s Westcoast 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 only 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 Westcoast 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 in order 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 a 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 over the course of the winter months.

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 north east 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 during the December through February period.

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.

ANNUAL INFORMATION FORM 16 December 31, 2017

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 $2.4 million for the gas contract for the year ended October 31, 2017.

The current GSMIP program was approved by the BCUC following a comprehensive review in 2011. In 2013, the BCUC approved an extension of the program until October 31, 2016. In August 2016, FortisBC Energy received approval from the BCUC for a renewal of the GSMIP program effective November 1, 2016 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 reviewed and 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 2017, 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. This application is under review by the BCUC.

Unbundling

A Customer Choice program at FortisBC Energy allows eligible commercial and residential customers a choice to buy their natural gas commodity supply from FortisBC Energy or directly 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, 2017, approximately 3% of eligible commercial customers and 3% of eligible residential customers participated in the program by purchasing their commodity supply from alternate providers.

FortisAlberta

FortisAlberta is a regulated electricity distribution utility operating in Alberta. Its business is the ownership and operation of 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 sale of electricity. FortisAlberta operates the electricity distribution system in a substantial portion of southern and central Alberta, totalling approximately 123,000 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 556,000 customers, comprised of residential, commercial, farm, oil and gas and industrial consumers, and met a peak demand of 2,725 MW in 2017.

Market and Sales

FortisAlberta's annual energy deliveries were 17,018 GWh in 2017 compared to 16,788 GWh in 2016. Revenue was $600 million in 2017 compared to $572 million in 2016.

ANNUAL INFORMATION FORM 17 December 31, 2017

The following table compares the composition of FortisAlberta's 2017 and 2016 revenue and energy deliveries by customer class.

	Revenue (%)		GWh Deliveries (%) (1)
	2017	2016	2017	2016
Residential	30.7	31.0	18.1	18.1
Large commercial, industrial and oil field	20.8	20.7	59.6	60.1
Farms	13.0	13.2	8.5	7.9
Small commercial	12.2	12.0	8.1	8.1
Small oil field	8.7	8.8	5.3	5.4
Other (2)	14.6	14.3	0.4	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 6,691 GWh in 2017 and 6,524 GWh in 2016, based on an interim settlement that is expected to be finalized in May 2018, 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 residing within various municipalities throughout its service areas. From time to time, municipal governments in Alberta give consideration to 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 pay compensation to 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 158 municipalities within its service area. The franchise agreements include 10‑year terms with an option that will permit the agreement to automatically 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.

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 172,000 customers and met a peak demand of 731 MW in 2017. FortisBC Electric's T&D assets include approximately 7,300 km of T&D lines and 65 substations.

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

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 3,305 GWh in 2017, compared to 3,119 GWh in 2016. Revenue increased to $398 million in 2017 from $377 million in 2016.

ANNUAL INFORMATION FORM 18 December 31, 2017

The following table compares the composition of FortisBC Electric's 2017 and 2016 revenue and electricity sales by customer class.

	Revenue (%)		GWh Sales (%)
	2017	2016	2017	2016
Residential	46.7	44.6	41.5	40.4
Commercial	24.6	24.3	29.4	29.7
Wholesale	12.6	11.8	17.9	17.7
Industrial	7.8	8.2	11.2	12.2
Other (1)	8.3	11.1	-	-
Total	100.0	100.0	100.0	100.0

⁽¹⁾  Includes revenue from sources other than from the sale of electricity, including revenue of FortisBC Pacific Holdings Inc. associated with non‑regulated operating, maintenance and management services.

Generation and Power Supply

FortisBC Electric meets the electricity supply requirements of its customers through a mix of its own generation and power purchase contracts. The company owns four regulated hydroelectric generating plants on the Kootenay River with an aggregate capacity of 225 MW, which provide approximately 45% of the company's 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 six 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	256	BC Hydro
Waneta Dam	237	Teck Metals Ltd.
Waneta Expansion	335	Waneta Partnership
Kootenay River System	225	FortisBC Electric
Brilliant Dam	149	BPC
Brilliant Expansion	120	BEPC
Total	1,902

BPC, BEPC, 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. 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.

ANNUAL INFORMATION FORM 19 December 31, 2017

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 CPC/CBT. During 2017, FortisBC Electric purchased capacity and energy from the market to meet its peak energy requirements and optimize its overall power supply portfolio. Spot market and contracted purchases provided approximately 12% of FortisBC Electric's energy supply requirements in 2017. 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.

Eastern Canadian

Eastern Canadian is comprised of the operations of Newfoundland Power, Maritime Electric, FortisOntario and the Corporation's 49% equity investment in the Wataynikaneyap Partnership.

Newfoundland Power is an integrated regulated electric utility and the principal distributor of electricity on the island portion of Newfoundland and Labrador, serving approximately 266,000 customers in approximately 600 communities. Newfoundland Power has installed generating capacity of 139 MW and met a peak demand of 1,423 MW in 2017. Newfoundland Power owns and operates approximately 12,200 km of T&D lines.

Maritime Electric is an integrated regulated electric utility and the principal distributor of electricity on PEI, serving approximately 80,000 customers, constituting approximately 92% of electricity consumers on PEI. Maritime Electric purchases most of the energy it distributes to its customers from NB Power, a New Brunswick Crown corporation, through various energy purchase agreements. Maritime Electric owns and operates generating plants with a combined capacity of 145 MW and met a peak demand of 282 MW in 2017. Maritime Electric owns and operates approximately 6,000 km of T&D lines.

FortisOntario provides integrated electric utility service through its three regulated operating utilities to approximately 66,000 customers in Fort Erie, Cornwall, Gananoque, Port Colborne and the District of Algoma in Ontario. FortisOntario also owns a 10% interest in certain regional electric distribution companies serving approximately 40,000 customers. FortisOntario met a combined peak demand of 240 MW in 2017. FortisOntario owns and operates approximately 3,500 km of T&D lines.

Wataynikaneyap Partnership is a partnership between 22 First Nation communities and Fortis with a mandate of connecting remote First Nation communities to the electricity grid in Ontario through the development of new transmission lines. The Wataynikaneyap Partnership's power project is in the development stage.

Market and Sales

Electricity sales attributable to the Eastern Canadian were 8,355 GWh in 2017 compared to 8,374 GWh in 2016. Revenue was $1,062 million in 2017 compared to $1,063 million in 2016.

The following table compares the composition of revenue and electricity sales by customer class at Eastern Canadian in 2017 and 2016.

	Revenue (%)		GWh Sales (%)
	2017	2016	2017	2016
Residential	57.1	56.8	56.8	56.9
Commercial and Industrial	39.4	39.5	43.0	43.0
Other (1)	3.5	3.7	0.2	0.1
Total	100.0	100.0	100.0	100.0

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

Power Supply

Newfoundland Power

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

ANNUAL INFORMATION FORM 20 December 31, 2017

Newfoundland 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 Newfoundland Hydro's marginal cost of generating electricity.

Newfoundland Hydro filed a general rate application with the PUB in July 2017. The application originally proposed an increase to the wholesale electricity rate charged to Newfoundland Power of 9.7% on January 1, 2018 and 9.4% on January 1, 2019. In the fourth quarter of 2017, Newfoundland Hydro indicated that it would not be feasible for it to implement the originally proposed rate increase for January 1, 2018. The application is currently under review by the PUB, and the timing and amount of any rate change associated with the application is uncertain.

Future changes in supply costs, including costs associated with the 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. In addition, Nalcor Energy indicated it was investigating the options available to moderate the impact of higher project costs on electricity prices. The government of Newfoundland and Labrador announced that it will be proceeding with a public inquiry into the Muskrat Falls project, which is scheduled to begin in early 2018.

Newfoundland Power experienced losses of electricity supply from Newfoundland Hydro in January 2013 and January 2014, which prevented Newfoundland Power from meeting all of its customers' requirements. The PUB is conducting an inquiry and hearing into these system supply issues and power interruptions. In September 2016 the PUB issued its report on the first phase of the inquiry regarding the supply issues and power interruptions. The report indicated that Newfoundland Power did not cause or contribute to the power outages. It also indicated significant concerns remain in relation to the adequacy and reliability of supply from Newfoundland Hydro. The second phase of the inquiry and hearing process is ongoing, which considers longer-term issues associated with adequacy and reliability on the Island Interconnected system after interconnection with the Muskrat Falls hydroelectric generation facility.

Newfoundland Power operates 28 small generating facilities, which generate approximately 7% of the electricity sold by the company. Newfoundland Power's hydroelectric generating plants have a total capacity of 97 MW and its diesel plants and gas turbines have a total capacity of approximately 5 MW and 37 MW, respectively.

Maritime Electric

Maritime Electric purchased 77% of the electricity required to meet its customers' needs from NB Power in 2017. The balance was 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. Maritime Electric's on‑Island generation facilities are used primarily for peaking, submarine-cable loading issues and emergency purposes.

Maritime Electric has two take-or-pay contracts for the purchase of either energy or capacity: (i) a fixed-pricing contract with NB Power expiring February 2019; and (ii) a transmission capacity contract with NB Power 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 areas are provided from various sources. Canadian Niagara Power purchases its power requirements for Fort Erie and Port Colborne from IESO. Canadian Niagara Power purchases approximately 70% of energy requirements for Gananoque through monthly energy purchases from Hydro One Networks Inc. and the remaining 30% is purchased 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 OEB, 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.

ANNUAL INFORMATION FORM 21 December 31, 2017

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.

Regulated Utilities – Caribbean

The Corporation's Regulated Utilities – Caribbean segment includes Caribbean Utilities, Fortis Turks and Caicos and the Corporation's 33% equity investment in Belize Electricity. Caribbean Utilities is an integrated regulated electric utility and the sole provider of electricity on Grand Cayman, Cayman Islands. Fortis holds an approximate 60% controlling ownership interest in Caribbean Utilities as at December 31, 2017. Fortis Turks and Caicos is an integrated regulated generation, transmission and distribution utility serving the Turks and Caicos Islands. Belize Electricity isan 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.

The Regulated Utilities – Caribbean segment serves approximately 44,000 customers on Grand Cayman, Cayman Islands and certain islands in Turks and Caicos and met a peak demand of 142 MW in 2017. The utilities own and operate almost 1,400 km of T&D lines, including 24 km of submarine cable.

Market and Sales

Electricity sales of Regulated Utilities – Caribbean were 841 GWh in 2017, compared to 837 GWh in 2016. Revenue was $301 million in 2017 compared with $301 million in 2016.

In September 2017 the Turks and Caicos Islands were struck by Hurricane Irma, resulting in significant damage to Fortis Turks and Caicos' T&D systems. Post-hurricane recovery on the Turks and Caicos Islands continues in 2018 as reconstruction activities advance and businesses resume operations, which may offset some losses in economic output resulting from the storm.

The following table compares the composition of revenue and electricity sales by customer class at the Regulated Utilities – Caribbean for 2017 and 2016.

	Revenue (%)		GWh Sales (%)
	2017	2016	2017	2016
Residential	46.2	44.6	46.1	44.5
Commercial and Industrial	52.8	54.3	53.9	55.5
Other (1)	1.0	1.1	-	-
Total	100.0	100.0	100.0	100.0

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

Power Supply

Caribbean Utilities and Fortis Turks and Caicos rely upon in-house diesel-powered generation to produce electricity for their customers, with an installed generating capacity of 161 MW and 84 MW, respectively.

Caribbean Utilities is party to primary and secondary fuel supply contracts with two different suppliers and is committed to purchasing approximately 60% and 40%, respectively, of Caribbean Utilities' diesel fuel requirements for the operation of its diesel-powered generating plant. The fuel contracts expired August 31, 2017 and are currently under negotiations.

In 2017 FortisTCI installed and commissioned its first two photovoltaic systems under its Utility Owned Renewable Energy Program, with a total aggregate size of 178 KW. In addition, the official contract signing for the acquisition of a Wartsila 20V32 engine with 8.75 MW capacity occurred in 2017. The engine is expected to be commissioned in 2019.

Hurricane Irma affected approximately 50% of Fortis Turks and Caicos' T&D infrastructure. System hardening and repairs following the storms have allowed FortisTCI to design and rebuild its electrical infrastructure to further withstand category five storms in order to continue to provide reliable service to its customers.

ANNUAL INFORMATION FORM 22 December 31, 2017

Fortis Turks and Caicos 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.

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). Generating assets in British Columbia include the Corporation's 51% controlling ownership interest in the 335-MW Waneta Expansion, conducted through the Waneta Partnership, with CPC/CBT holding the remaining 49% interest. All of the output of the Waneta Expansion is sold to BC Hydro and FortisBC Electric under 40-year contracts. As described earlier, FortisBC Electric operates and maintains the Waneta Expansion.

Generating assets in Belize are comprised of three hydroelectric generating facilities with a combined capacity of 51 MW held through the Corporation's indirectly wholly owned 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.

Generating assets in Ontario are comprised of the operation of a 5‑MW gas‑powered cogeneration plant in Cornwall that is owned by FortisOntario and operated by Cornwall Electric. All thermal energy output of this plant is sold to external third parties, while the electricity output is sold to Cornwall Electric.

In February 2016 the Corporation sold its 16-MW run-of-river Walden hydroelectric generating facility in British Columbia.

Market and Sales

Energy sales from Energy Infrastructure assets were 918 GWh in 2017 compared to 901 GWh in 2016. Revenue was $226 million in 2017 compared to $193 million in 2016. The increase in revenue was driven by Aitken Creek, attributable to increased contribution in the first quarter of 2017 due to its acquisition occurring in April 2016.

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, 2017

HUMAN RESOURCES

As of December 31, 2017, Fortis and its subsidiaries had approximately 8,500 employees, with 52% in Canada, 43% in the U.S. and 5% in other countries. The following table provides the breakdown of full-time equivalent employees among the Corporation's subsidiaries and corporate office.

	Employees	Participation in a Collective Agreement	Union(s)	Current Collective Agreement(s) Expiry Date(s)
Regulated Utilities – United States
ITC	669	None	-	-
UNS Energy	2,024	53%	IBEW	June 2018 – February 2020
Central Hudson	1,004	59%	IBEW	March 2018 - April 2022
Regulated utilities – Canada
FortisBC Energy	1,719	65%	IBEW, COPE	March 2018 – March 2022
FortisAlberta	1,116	80%	UUWA	December 2020
FortisBC Electric	510	70%	IBEW, COPE	December 2018 – March 2022
Eastern Canadian	989	58%	IBEW, CUPE, Power Workers' Union	September 2017 (1) – December 2019
Regulated Utilities - Caribbean (2)
	380	None	-	-
Non-Regulated
Energy Infrastructure (3)	66	None	-	-
Corporate and Other (4)	57	None	-	-
Total	8,534	54%

⁽¹⁾  The two collective agreements between Newfoundland Power and IBEW Local 1620 expired on September 30, 2017. Collective agreement negotiations began in the fourth quarter of 2017.

⁽²⁾  Excludes Belize Electricity

⁽³⁾  Includes employees at BECOL, ACGS and FAES. Energy Infrastructure operations in British Columbia and Ontario are staffed by employees of FortisBC Inc. and FortisOntario, respectively

⁽⁴⁾  Employees at Fortis Inc.

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, 2017

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, 2017, 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 2017 Audited Consolidated Financial Statements, which are incorporated by reference in this AIF.

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, 2017; (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, 2017.

For information with respect to the nature of regulation and material regulatory decisions and applications associated with each of the Corporation's electric and gas utilities, refer to the "Regulatory Highlights" section of the MD&A and to Notes 2 and 8 of the 2017 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. 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 each Fortis subsidiary.

Social and Diversity Policies

In 2015 Fortis adopted a Diversity Policy that describes the principles and objectives for diversity among the Board and the Corporation's executive leadership. In 2017 the Corporation amended its Diversity Policy and committed to maintaining a Board where at least one-third of the Board's independent directors are represented by each gender - a level that Fortis currently meets. For further information on the Corporation's Diversity Policy, refer to the Corporation's Management Information Circular dated March 17, 2017, which is available on SEDAR.

Each of the operating subsidiaries are stand-alone entities responsible for implementing policies, programs and practices that adhere to the standards set forth in the Corporation's policies, while taking into account the jurisdiction and unique operating environment of the subsidiary. Social and environmental policies in place at the Corporation's utilities include, among others: a Code of Business Conduct and Ethics; Health, Safety, and Environmental Policies; Diversity Policies; Equal Opportunity Policies; Respectful Workplace, Workplace Harassment and Violence Policies; Disability Non-Discrimination Policies; and Accommodation Policies.

ANNUAL INFORMATION FORM 25 December 31, 2017

Environmental, Sustainability and Regulatory Oversight

Fortis believes that responsible environmental and sustainability management is good for its business and customers. The Corporation is focused on operating its energy networks in a sustainable manner, helping its customers reduce their consumption and become more energy efficient, and achieving its goal of delivering safe, reliable, cleaner and affordable 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. 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 Corporation's environmental footprint is relatively low compared to its peers as its regulated utilities consist primarily of T&D assets, which have minimal direct GHG emissions. 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 primary producer of fossil fuel-based generation, and is taking significant steps to reduce coal-fired generation and resulting carbon emissions. TEP is planning a 36% (508 MW) reduction in coal-fired generation over the next five years through plant retirements.

Fortis and its subsidiaries share a commitment to the environment in their operations. Each operating subsidiary has a comprehensive environmental management system with the majority having environmental management systems that are ISO 14001 compliant. 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.

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.

Environmental Contingencies

TEP

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$61 million upon expiry of the coal agreements, which expire between 2019 and 2031. The mine reclamation liability recognized as at December 31, 2017 was $43 million (US$34 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 to TEP 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.

Central Hudson

Former MGP Facilities. Central Hudson has been notified by the New York State Department of Environmental Conservation to investigate MGPs at sites that the Company or its predecessors once owned and/or operated 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, 2017, an obligation of $69 million (US$55 million) was recognized. Central Hudson has notified its insurers and intends to seek reimbursement, where coverage exists. Further, as authorized by the PSC, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for MGP site investigation and remediation and the associated rate allowances.

ANNUAL INFORMATION FORM 26 December 31, 2017

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, 2018, the Corporation had issued and outstanding 421.1 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 2017 Annual Information Form.

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 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 paid quarterly.

In October 2017 Fortis increased its dividend per common share 6.25% to $0.425 per share, or $1.70 on an annualized basis. In December 2017 the Board declared a first quarter 2018 dividend on the Common Shares of $0.425 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, 2018 to holders of record as of February 15, 2018.

Fortis has targeted average annual dividend growth of 6% through 2022. 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.

ANNUAL INFORMATION FORM 27 December 31, 2017

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

	2017		2016		2015
Common Shares		$1.6500		$1.5500		$1.4300
First Preference Shares, Series E (1)	-			$0.6126		$1.2250
First Preference Shares, Series F (2)		$1.2250		$1.2250		$1.2250
First Preference Shares, Series G (3)		$0.9708		$0.9708		$0.9708
First Preference Shares, Series H (4)		$0.6250		$0.6250		$0.7344
First Preference Shares, Series I (5)		$0.5262		$0.4874		$0.3637
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 $1.3125 to $0.9708 for the five-year period from and including September 1, 2013 to but excluding September 1, 2018.

⁽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 Preferred 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 Senior 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 2022, 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, 2017 and 2016, the Corporation was in compliance with its debt covenant restrictions pertaining to dividend distributions, as described above.

Prior Sales

In July 2017 Fortis exchanged its US$2.0 billion ($2.6 billion) unregistered senior unsecured notes for US$2.0 billion ($2.6 billion) registered senior unsecured notes under its 25-month life base shelf prospectus, under which Fortis may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $5 billion. The notes are not listed on a stock exchange or publicly traded. As at December 31, 2017 a principal amount of approximately $1.5 billion remains under the base shelf prospectus.

ANNUAL INFORMATION FORM 28 December 31, 2017

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 ratings 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 Corporation's credit ratings outlook have been affirmed as stable by DBRS, Fitch, S&P and Moody's. The following table summarizes the Corporation's debt credit ratings as at February 14, 2018.

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

⁽¹⁾  Central Hudson's senior unsecured debt is also rated by Fitch at 'A-' .

⁽²⁾  In September 2017 S&P upgraded ITC Holdings' senior unsecured debt rating to 'A-' from 'BBB+'.

⁽³⁾  In April 2017 S&P upgraded TEP's senior unsecured debt rating to 'A-' from 'BBB+'.

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, 2017

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. Fortis has also paid fees to S&P and Moody's in the last two years in respect of certain advisory services provided in connection with the acquisition of ITC.

ANNUAL INFORMATION FORM 30 December 31, 2017

DIRECTORS AND OFFICERS

The Board has governance guidelines which 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, be eligible for re‑election until the annual meeting of shareholders following the date they turn 72 or 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 as of February 14, 2018, and indicates their principal occupations within the five preceding years. Each Director's current term expires at the close of the May 3, 2018 annual meeting of shareholders.

Name, Residence, Principal Occupation Within Five Preceding Years	Director Since	Committees (1)
		AC	GN	HR
DOUGLAS J. HAUGHEY (Chair), Alberta, Canada Mr. Haughey, 61, a Corporate Director, was Chief Executive Officer of The Churchill Corporation from August 2012 through May 2013. Mr. Haughey was appointed Chair of the Board in September 2016.	May 2009	l	l	l
TRACEY C. BALL, British Columbia, Canada Ms. Ball, 60, a Corporate Director, was Executive Vice President and Chief Financial Officer of Canadian Western Bank Group from 2006 until her retirement in September 2014.	May 2014	C	l
PIERRE J. BLOUIN, Quebec, Canada Mr. Blouin, 59, a Corporate Director, was Chief Executive Officer of Manitoba Telecom Services, Inc. from 2005 until his retirement in December 2014.	May 2015		l	l
LAWRENCE T. BORGARD, Florida, USA Mr. Borgard, 56, a Corporate Director, was President and Chief Operating Officer of Integrys Energy Group and the Chief Executive Officer of each of Integrys' six regulated electric and natural gas utilities until his retirement in 2015.	May 2017	l
MAURA J. CLARK, New York, USA Ms. Clark, 59, a Corporate Director, retired from Direct Energy, a subsidiary of Centrica plc, in March 2014 where she was President of Direct Energy Business from 2007.	May 2015	l	l
MARGARITA K. DILLEY, Virginia, USA Ms. Dilley, 60, a Corporate Director, has served as a director of CH Energy Group since 2004 and serves as Chair of that board.	May 2016	l		l
IDA J. GOODREAU, British Columbia, Canada Ms. Goodreau, 66, a Corporate Director, was President and Chief Executive Officer of LifeLabs until her retirement in 2009.	May 2009		l	C
R. HARRY McWATTERS, British Columbia, Canada Mr. McWatters, 72, is the President of Vintage Consulting Group Inc., Harry McWatters Inc., and TIME Estate Winery, all of which are engaged in various aspects of the British Columbia wine industry.	May 2007		l
RONALD D. MUNKLEY, Ontario, Canada Mr. Munkley, 71, a Corporate Director, retired in 2009 as Vice Chairman and Head of the Power and Utility Business of CIBC World Markets.	May 2009		C	l
BARRY V. PERRY, Newfoundland and Labrador, Canada Mr. Perry, 53, is President and Chief Executive Officer of the Corporation. He served as President of the Corporation from June 2014 to December 2014 and prior to that served as Vice President, Finance and Chief Financial Officer.	January 2015	(2)
JOSEPH L. WELCH, Florida, USA Mr. Welch, 69, a Corporate Director, was President and Chief Executive Officer of ITC Holdings until his retirement in October 2016.	May 2017	(3)
JO MARK ZUREL, Newfoundland and Labrador, Canada Mr. Zurel, 53, is President of Stonebridge Capital Inc., a private investment company.	May 2016	l		l

⁽¹⁾  Audit Committee, Governance and Nominating Committee and Human Resources Committee

⁽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, 2017

The following table sets out the name, province or state, and country of residence of each of the executive officers of Fortis as of December 31, 2017, 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 Mr. Perry was appointed President and Chief Executive Officer in January 2015. Mr. Perry was President of Fortis from June 2014 to January 2015. From 2004 to June 2014 Mr. Perry served as Vice President, Finance and Chief Financial Officer of Fortis.	President and Chief Executive Officer
KARL W. SMITH, Newfoundland and Labrador, Canada Mr. Smith was appointed Executive Vice President, Chief Financial Officer in June 2014. From 2007 to June 2014 Mr. Smith served as President and Chief Executive Officer of FortisAlberta.	Executive Vice President, Chief Financial Officer
NORA M. DUKE, Newfoundland and Labrador, Canada Ms. Duke was appointed Executive Vice President, Corporate Services and Chief Human Resource Officer in August 2015 and Executive Vice President, Sustainability and Chief Human Resource Officer in December 2017. From 2008 to August 2015 Ms. Duke served as President and Chief Executive Officer of Fortis Properties.	Executive Vice President, Sustainability and Chief Human Resource Officer
JAMES P. LAURITO, Florida, USA Mr. Laurito was appointed Executive Vice President, Business Development in April 2016. From 2010 to April 2016 Mr. Laurito served as President and Chief Executive Officer of Central Hudson.	Executive Vice President, Business Development
GARY J. SMITH, Newfoundland and Labrador, Canada Mr. Smith was appointed Executive Vice President, Eastern Canadian and Caribbean Operations in June 2017. Mr. Smith served as President and Chief Executive Officer at Newfoundland Power from 2014 to June 2017 and Vice President, Customer Operations and Engineering at Newfoundland Power from 2008 to 2014.	Executive Vice President, Eastern Canadian and Caribbean Operations
DAVID C. BENNETT, Newfoundland and Labrador, Canada Mr. Bennett was appointed Executive Vice President, Chief Legal Officer and Corporate Secretary in May 2016 and, prior thereto, served as Vice President, Chief Legal Officer and Corporate Secretary from September 2014. Mr. Bennett served as Vice President, Operations Support, General Counsel and Corporate Secretary of FortisBC from 2013 to September 2014.	Executive Vice President, Chief Legal Officer and Corporate Secretary
PHONSE J. DELANEY, Newfoundland and Labrador, Canada Mr. Delaney was appointed Executive Vice President, Chief Information Officer in June 2017. Mr. Delaney served as President and Chief Executive Officer of FortisAlberta from 2014 to June 2017 and Executive Vice President, Operations, Engineering and Information Technology of FortisAlberta from 2008 to 2014.	Executive Vice President, Chief Information Officer
EARL A. LUDLOW, Newfoundland and Labrador, Canada Mr. Ludlow was appointed Operational Advisor to the President and Chief Executive Officer in June 2017 and served as Executive Vice President, Eastern Canadian and Caribbean Operations from August 2014 to May 2017. Mr. Ludlow served as President and Chief Executive Officer of Newfoundland Power from 2007 to August 2014.	Operational Advisor to the President and Chief Executive Officer
STEPHANIE A. AMAIMO, Michigan, USA Ms. Amaimo was appointed Vice President, Investor Relations, in October 2017. Ms. Amaimo served as Director, Investor Relations from October 2016 to October 2017. Ms. Amaimo served as Director, Investor Relations and Manager, Financial Planning and Analysis at ITC Holdings from 2015 to 2016 and 2013 to 2015, respectively.	Vice President, Investor Relations
KAREN J. GOSSE, Newfoundland and Labrador, Canada Ms. Gosse was appointed Vice President, Planning and Forecasting in November 2015. Ms. Gosse served as Vice President, Finance, and Chief Financial Officer of Fortis Properties from 2013 until November 2015.	Vice President, Planning and Forecasting
REGAN P. O'DEA, Newfoundland and Labrador, Canada Mr. O'Dea was appointed Vice President, General Counsel - Corporate in May 2017 and served as Associate General Counsel from 2014 to May 2017. Prior to joining Fortis, Mr. O'Dea served as Director, Legal and Corporate Services at a national insurance company.	Vice President, General Counsel - Corporate
JAMES D. SPINNEY, Newfoundland and Labrador, Canada Mr. Spinney was appointed Vice President, Treasurer in March 2013.	Vice President, Treasurer
JAMIE D. ROBERTS, Newfoundland and Labrador, Canada Mr. Roberts was appointed Vice President, Controller in March 2013.	Vice President, Controller

As at December 31, 2017, the directors and executive officers of Fortis, as a group, beneficially owned, directly or indirectly, or exercised control or direction over 2,570,902 Common Shares, representing 0.61% 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, 2017

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, 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 Tracey C. Ball and Maura J. Clark as "audit committee financial experts" under U.S. securities laws.

The Corporation's Audit Committee Mandate, effective as of January 1, 2018, is attached as Exhibit "C" to this 2017 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. As at February 14, 2018, the Audit Committee was composed of the following persons.

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.
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 also 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 has served on several private and public sector boards, including Major Drilling Group International Inc., the Canada Pension Plan Investment Board and Fronteer Gold Inc. 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, 2017

Pre-Approval Policies and Procedures

The Audit Committee has established a policy which 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 which may be contracted from the External Auditor and the limitations and authorization procedures related thereto. 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

Fees incurred by the Corporation for work performed by Deloitte LLP, the Corporation's External Auditors effective as of May 4, 2017, and Ernst & Young LLP, the Corporation's External Auditors up to May 3, 2017, during each of the last two fiscal years for audit, audit-related, tax, and non‑audit services were as follows.

	Deloitte LLP	Ernst & Young LLP
($ thousands)	2017	2017	2016
Audit Fees	7,207	978	5,884
Audit-Related Fees	1,241	718	1,727
Tax Fees	497	7	332
Other	177	-	-
Total	9,122	1,703	7,943

The total audit fees were higher in 2017, mainly due to the requirement to obtain an audit opinion on the Corporation's internal control over financial reporting, which was a result of the Corporation becoming a SEC registrant in 2016.

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, 2017

AUDITORS

Effective as of May 4, 2017, the Corporation's auditors are Deloitte LLP, Chartered Professional Accountants, Fortis Place, Suite 1000, 5 Springdale Street, St. John's, NL, A1E 0E4. The Corporation's auditors up to May 3, 2017 were Ernst & Young LLP, Chartered Professional Accountants. The consolidated financial statements of the Corporation for the fiscal year ended December 31, 2017 have been audited by Deloitte LLP. Deloitte LLP is a public accounting firm registered with the PCAOB and is required to be independent with respect to the Corporation in accordance with the U.S. federal securities laws and the applicable rules and regulations of the SEC and the PCAOB. Further, Deloitte LLP is required to be independent of the Corporation in accordance with the ethical requirements that are relevant to the audit of financial statements in Canada and to fulfill its other ethical responsibilities in accordance with these requirements.

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 2017 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 17, 2017 for the May 4, 2017 annual meeting of shareholders.

Requests for additional copies of the above‑mentioned documents, as well as this 2017 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, 2017

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 ratabasis 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, 2017

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, 2018.

	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	26.00	-
Fixed Rate Reset (4) (5)
Series G	9,200,000	9,200,000	5.25	0.9708	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) (6)
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 quarterly installments on the first day of each quarter.

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

⁽³⁾  First Preference Shares, Series J are redeemable at $26.00 until December 1, 2018, such redemption price 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 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, 2017

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, 2018, there were no second preference shares issued and outstanding.

ANNUAL INFORMATION FORM 38 December 31, 2017

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, 2017, for the Common Shares on the TSX and NYSE in Canadian Dollars and US Dollars, respectively.

2017 Trading Prices and Volumes – Common Shares
	TSX			NYSE
Month	High ($)	Low ($)	Volume	High (US$)	Low (US$)	Volume
January	41.91	40.59	15,832,581	32.18	30.53	3,779,640
February	43.50	41.35	20,223,622	33.07	31.59	3,664,838
March	44.44	41.95	23,887,789	33.37	31.27	5,304,323
April	45.13	43.70	12,649,620	33.99	32.28	3,267,632
May	45.04	43.12	22,773,180	33.04	31.72	3,285,816
June	47.06	44.42	20,317,098	35.73	32.91	3,923,855
July	45.66	43.98	13,049,471	36.60	34.25	3,242,909
August	46.43	45.06	15,095,563	36.96	35.01	3,472,129
September	45.80	44.01	18,615,874	37.67	35.33	3,736,732
October	47.78	44.45	13,132,871	37.56	35.62	4,256,790
November	48.73	46.53	14,498,699	38.24	36.13	4,874,360
December	47.96	45.69	15,184,454	37.64	35.77	4,533,433

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, 2017.

2017 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	24.16	22.98	65,536	19.97	18.51	204,337
February	24.19	23.59	125,679	20.70	19.92	134,272
March	24.00	23.53	64,190	21.31	19.87	183,589
April	24.80	23.89	60,624	22.00	20.63	108,728
May	24.90	23.93	77,599	21.01	19.75	90,765
June	24.59	23.70	104,392	21.27	19.22	274,308
July	24.00	23.18	46,277	21.26	20.65	103,151
August	23.71	23.21	49,215	21.20	20.60	155,825
September	23.61	22.81	50,968	21.20	20.67	137,468
October	24.35	23.08	52,762	21.57	20.90	192,985
November	24.70	24.01	52,990	21.75	21.35	125,343
December	24.34	23.66	49,842	21.85	21.25	144,539

ANNUAL INFORMATION FORM 39 December 31, 2017

	First Preference Shares, Series H			First Preference Shares, Series I
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	15.43	14.11	305,645	14.00	12.74	43,350
February	16.10	15.14	109,874	14.80	13.90	54,635
March	16.52	15.66	374,504	15.12	14.15	37,410
April	17.57	16.11	251,883	16.00	14.77	128,707
May	16.58	15.76	157,784	15.41	14.52	53,455
June	17.06	15.39	175,425	16.25	14.45	141,354
July	17.12	16.65	39,978	16.70	16.24	19,300
August	17.43	16.79	46,194	16.75	15.95	82,120
September	17.30	16.83	52,494	16.55	16.19	239,567
October	17.43	16.91	231,984	16.71	16.28	64,829
November	17.28	17.00	319,303	16.98	16.50	21,350
December	18.17	17.01	340,006	17.19	16.46	39,581
	First Preference Shares, Series J			First Preference Shares, Series K
Month	High ($)	Low ($)	Volume	High ($)	Low ($)	Volume
January	23.51	22.56	140,816	19.76	18.20	181,395
February	23.64	22.90	116,562	20.54	19.62	164,209
March	23.28	22.74	409,151	21.29	19.75	307,694
April	24.18	23.05	501,452	21.68	20.42	362,158
May	24.50	23.34	72,991	20.90	19.61	185,016
June	24.00	23.15	178,428	20.86	19.10	385,843
July	23.63	22.76	61,152	20.96	20.35	211,375
August	23.15	22.72	52,702	21.00	20.41	90,346
September	22.96	22.11	83,770	21.14	20.53	132,375
October	23.70	22.33	152,457	21.58	20.92	122,645
November	24.00	23.27	83,380	21.82	21.30	131,077
December	23.60	22.75	131,274	21.80	21.08	171,761
	First Preference Shares, Series M
Month	High ($)	Low ($)	Volume
January	22.19	20.19	434,532
February	22.94	21.80	262,293
March	23.85	22.09	318,048
April	23.88	22.44	563,139
May	23.33	22.25	171,572
June	23.68	21.54	329,740
July	23.51	23.00	184,938
August	23.49	22.68	94,964
September	23.66	23.00	125,742
October	23.74	23.30	527,643
November	23.95	23.51	381,751
December	23.82	23.18	186,468

ANNUAL INFORMATION FORM 40 December 31, 2017

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

"Board" means the board of directors of the Corporation;

"Chair" means the Chair of the Committee;

"Committee" means the audit committee appointed by the Board pursuant to this mandate;

"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;

"Corporation" means Fortis Inc.;

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

"Director" means a member of the Board;

"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;

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

ANNUAL INFORMATION FORM 41 December 31, 2017

"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;

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

"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;

"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;

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

"Management" means the senior officers of the Corporation;

"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;

"Member" means a Director appointed to the Committee;

"NYSE" means the New York Stock Exchange;

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

"Related Party Transactions" means those transactions required to bedisclosed 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;

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

"Shareholders" means the shareholders of the Corporation.

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.

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.

ANNUAL INFORMATION FORM 42 December 31, 2017

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 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.

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

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.

ANNUAL INFORMATION FORM 43 December 31, 2017

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.

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.

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;

ANNUAL INFORMATION FORM 44 December 31, 2017

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

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

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

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

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

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

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

ANNUAL INFORMATION FORM 45 December 31, 2017

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 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.

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.

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.

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.

ANNUAL INFORMATION FORM 46 December 31, 2017

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;

(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    REMUNERATION OF MEMBERS

6.1    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.

6.2    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.

7.0    GENERAL

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

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

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

7.4    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.

7.5    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 47 December 31, 2017

EXHIBIT D: MATERIAL CONTRACTS

The following are the material contracts of Fortis filed on SEDAR and EDGAR during 2017 or which were entered into prior to 2017 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. The Fortis 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 securityholders 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 48 December 31, 2017