Exhibit 99.3

Interim Management Discussion and Analysis

For the three months ended March 31, 2018

Dated April 30, 2018

TABLE OF CONTENTS
Forward-Looking Information	1	Contractual Obligations	13
Corporate Overview	3	Capital Structure	13
Financial Highlights	3	Credit Ratings	14
Segmented Results of Operations	5	Capital Expenditure Plan	14
Regulated Utilities	5	Additional Investment Opportunities	15
ITC	5	Cash Flow Requirements	16
UNS Energy	6	Credit Facilities	17
Central Hudson	6	Off-Balance Sheet Arrangements	17
FortisBC Energy	7	Business Risk Management	17
FortisAlberta	7	Changes in Accounting Policies	18
FortisBC Electric	8	Future Accounting Pronouncements	19
Other Electric	8	Financial Instruments	20
Non-Regulated	9	Critical Accounting Estimates	21
Energy Infrastructure	9	Related-Party and Inter-Company Transactions	22
Corporate and Other	9	Summary of Quarterly Results	22
Regulatory Highlights	10	Outlook	24
Consolidated Financial Position	11	Outstanding Share Data	24
Liquidity and Capital Resources	12	Condensed Consolidated Interim Financial Statements (Unaudited)	F-1
Summary of Consolidated Cash Flows	12

FORWARD-LOOKING INFORMATION

The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. The MD&A should be read in conjunction with the unaudited condensed consolidated interim financial statements and notes thereto for the three months ended March 31, 2018 ("Interim Financial Statements") and the MD&A and audited consolidated financial statements for the year ended December 31, 2017 included in the Corporation's 2017 Annual Report. Financial information contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") and is presented in Canadian dollars unless otherwise specified.

Fortis includes forward-looking information in the MD&A within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, collectively referred to as "forward-looking information". Forward-looking information included in the MD&A reflect expectations of Fortis management regarding future growth, results of operations, performance and 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 include, without limitation: the expectation that Fortis Turks and Caicos will recover lost revenue under its business interruption insurance; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the Corporation's forecast capital expenditures for 2018 and for the period from 2018 through 2022; the nature, timing, benefits and expected costs of certain capital projects including, without limitation, the Wataynikaneyap Power Project, the FortisBC Energy Lower Mainland System Upgrade and additional opportunities beyond the base capital expenditure plan including the Lake Erie Connector Project and additional liquefied natural gas infrastructure investment opportunities in British Columbia; the expectation that subsidiary operating expenses and interest costs will be paid out of subsidiary operating cash flows; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis; the expectation that maintaining the targeted capital structure of the Corporation's regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; the expectation that cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions will be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt, as well as proceeds from the dividend reinvestment plan and at-the-market common equity program; expected

MANAGEMENT DISCUSSION AND ANALYSIS 1 March 31, 2018

consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2018; the intent of management to refinance certain borrowings under Corporation's and subsidiaries' long-term committed credit facilities with long-term permanent financing; the expected timing and impact, if any, of the adoption of future accounting pronouncements; the expectation that long-term debt will not be settled prior to maturity; the expectation that any liability from current legal proceedings and claims will not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows; the Corporation's forecast rate base for 2022; the expectation that the Corporation's significant capital expenditure plan will support continuing growth in earnings and dividends, and targeted average annual dividend growth through 2022.

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 realization of additional opportunities; 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 changes in tax laws; 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 have a material negative affect on 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 expenditure plan.

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. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risk Management" in this MD&A and in continuous disclosure materials filed from time to time 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 plan, 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 the MD&A is given as of the date of the MD&A and Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.

MANAGEMENT DISCUSSION AND ANALYSIS 2 March 31, 2018

CORPORATE OVERVIEW

Fortis is a leader in the North American regulated electric and gas utility industry, with 2017 revenue of $8.3 billion and total assets of $49 billion as at March 31, 2018. The Corporation's 8,500 employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.

Year-to-date March 31, 2018, the Corporation's electricity systems met a combined peak demand of 24,794 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,599 terajoules. For additional information on the Corporation's operations and reportable segments, refer to Note 1 to the Corporation's Interim Financial Statements for the three months ended March 31, 2018 and to the "Corporate Overview" section of the 2017 Annual MD&A.

FINANCIAL HIGHLIGHTS

Fortis has adopted a strategy of long-term profitable growth with the primary measures of financial performance being earnings per common share and total shareholder return. Key financial highlights for the first quarters ended March 31, 2018 and 2017 are provided in the following table.

Consolidated Financial Highlights	Quarter Ended March 31
($ millions, except for common share data)	2018	2017	Variance
Revenue	2,197	2,274	(77	)
Energy Supply Costs	729	754	(25	)
Operating Expenses	553	579	(26	)
Depreciation and Amortization	302	297	5
Other Income, Net	9	28	(19	)
Finance Charges	236	229	7
Income Tax Expense	22	106	(84	)
Net Earnings	364	337	27
Net Earnings Attributable to:
Non-Controlling Interests	25	27	(2	)
Preference Equity Shareholders	16	16	—
Common Equity Shareholders	323	294	29
Net Earnings	364	337	27
Earnings per Common Share
Basic ($)	0.77	0.72	0.05
Diluted ($)	0.76	0.72	0.04
Weighted Average Number of Common Shares Outstanding (# millions)	422.0	406.2	15.8
Cash Flow from Operating Activities	589	541	48

Revenue

The decrease in revenue was primarily due to unfavourable foreign exchange associated with the translation of US dollar-denominated revenue, the recognition of a provision reflecting income tax savings due to a reduction in the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018 ("U.S. Tax Reform") and the flow through in customer rates of lower overall energy supply costs. The decrease was partially offset by the impacts of growth in rate base and a full quarter of new rates with the rate case settlement at UNS Energy being effective February 27, 2017.

Energy Supply Costs

The decrease in energy supply costs was primarily due to favourable foreign exchange associated with the translation of US dollar-denominated energy supply costs and lower overall commodity costs.

Operating Expenses

The decrease in operating expenses was primarily due to favourable foreign exchange associated with the translation of US dollar-denominated operating expenses.

MANAGEMENT DISCUSSION AND ANALYSIS 3 March 31, 2018

Depreciation and Amortization

The increase in depreciation and amortization was primarily due to continued investment in energy infrastructure at the Corporation's utilities, partially offset by favourable foreign exchange associated with the translation of US dollar-denominated depreciation and amortization.

Other Income, Net

The decrease in other income, net of expenses, was primarily due to the favourable settlement of matters at UNS Energy pertaining to the Federal Energy Regulatory Commission ("FERC") ordered transmission refunds of $11 million ($7 million after tax) in 2017, mark-to-market net losses on foreign exchange contracts and total return swaps in 2018, and unfavourable foreign exchange associated with the translation of US dollar-denominated other income.

Finance Charges

The increase in finance charges was primarily due to overall higher debt levels at the Corporation's utilities to support capital expenditure programs, partially offset by favourable foreign exchange associated with the translation of US dollar-denominated finance charges.

Income Tax Expense

The decrease in income tax expense was primarily due to U.S. Tax Reform, a one-time $30 million remeasurement of the Corporation's deferred income tax liabilities that resulted from an election to file a consolidated state income tax return, and favourable foreign exchange associated with the translation of US dollar-denominated income tax expense.

Net Earnings Attributable to Common Equity Shareholders and Basic Earnings per Common Share

The increase in net earnings attributable to common equity shareholders was primarily due to: (i) the one-time remeasurement of the Corporation's deferred income tax liabilities as a result of an election to file a consolidated state income tax return; (ii) the impact of a full quarter of new rates compared to last year at UNS Energy; and (iii) growth in rate base. The increase was partially offset by: (i) unfavourable foreign exchange associated with the translation of US dollar-denominated earnings; (ii) lower earnings from Aitken Creek related to unrealized net losses on the mark-to-market of natural gas derivatives quarter over quarter; (iii) timing differences at Newfoundland Power; and (iv) the favourable settlement of matters at UNS Energy pertaining to FERC-ordered transmission refunds of $7 million in 2017.

Basic earnings per common share were $0.05 higher compared to the same period in 2017. The impact of the above-noted items on net earnings attributable to common equity shareholders was partially offset by an increase in the weighted average number of common shares outstanding associated with the issuance of $500 million common equity in March 2017 and Corporation's dividend reinvestment and share plans.

Adjusted Net Earnings Attributable to Common Equity Shareholders and Adjusted Basic Earnings per Common Share

Fortis uses financial measures, being adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share, that do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar adjustments presented by other companies. The most directly comparable US GAAP measures to adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share are net earnings attributable to common equity shareholders and basic earnings per common share, respectively.

The Corporation calculates adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes are not reflective of the normal, ongoing operations of the business. Year-to-date March 31, 2018 and 2017, the Corporation adjusted net earnings attributable to common equity shareholders for: (i) a one-time remeasurement of the Corporation's deferred income tax liabilities as a result of an election to file a consolidated state income tax return; and (ii) the favourable settlement of matters pertaining to FERC-ordered transmission refunds in 2017.

The Corporation calculates adjusted basic earnings per common share by dividing adjusted net earnings attributable to common equity shareholders by the weighted average number of common shares outstanding.

MANAGEMENT DISCUSSION AND ANALYSIS 4 March 31, 2018

The following table provides a reconciliation of the non-US GAAP measures. Each of the adjusting items are discussed in the segmented results of operations for the respective reporting segments.

Non-US GAAP Reconciliation	Quarter Ended March 31
($ millions, except for common share data)	2018		2017		Variance
Net Earnings Attributable to Common Equity Shareholders	323		294		29
Adjusting Items:
UNS Energy - Settlement of FERC-ordered transmission refunds	—		(7	)	7
Corporate and Other -
Remeasurement of deferred income tax liabilities - consolidated state income tax election	(30	)	—		(30	)
Adjusted Net Earnings Attributable to Common Equity Shareholders	293		287		6
Adjusted Basic Earnings Per Common Share ($)	0.69		0.71		(0.02	)
Weighted Average Number of Common Shares Outstanding (# millions)	422.0		406.2		15.8

SEGMENTED RESULTS OF OPERATIONS

Segmented Net Earnings Attributable to Common Equity Shareholders
	Quarter Ended March 31
($ millions)	2018		2017		Variance
Regulated Utilities
ITC	86		91		(5	)
UNS Energy	50		41		9
Central Hudson	21		23		(2	)
FortisBC Energy	98		97		1
FortisAlberta	27		25		2
FortisBC Electric	16		15		1
Other Electric	18		26		(8	)
Non-Regulated
Energy Infrastructure	18		23		(5	)
Corporate and Other	(11	)	(47	)	36
Net Earnings Attributable to Common Equity Shareholders	323		294		29

The following is a discussion of the financial results of the Corporation's reporting segments. A discussion of the significant regulatory decisions and applications pertaining to the Corporation's regulated utilities is provided in the "Regulatory Highlights" section of this MD&A.

REGULATED UTILITIES

ITC

Financial Highlights (1)	Quarter Ended March 31
($ millions)	2018	2017	Variance
Average US:CAD Exchange Rate (2)	1.26	1.32	(0.06	)
Revenue	354	395	(41	)
Earnings	86	91	(5	)

⁽¹⁾  Revenue represents 100% of ITC, while earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflects consolidated purchase price accounting adjustments.

⁽²⁾  The reporting currency of ITC is the US dollar.

MANAGEMENT DISCUSSION AND ANALYSIS 5 March 31, 2018

Revenue

The decrease in revenue was primarily due to the recognition of a provision reflecting income tax savings as a result of U.S. Tax Reform and approximately $17 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue. The decrease was partially offset by the impact of growth in rate base.

Earnings

The decrease in earnings was primarily due to approximately $4 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings, the deduction of interest at a lower corporate income tax rate of 21%, as a result of U.S. Tax Reform, and higher business development costs. The decrease in earnings before considering the impact of foreign exchange was largely offset by the impact of growth in rate base.

UNS ENERGY ⁽¹⁾ 

Financial Highlights	Quarter Ended March 31
	2018	2017	Variance
Average US:CAD Exchange Rate (2)	1.26	1.32	(0.06	)
Electricity Sales (gigawatt hours ("GWh"))	3,325	3,384	(59	)
Gas Volumes (petajoules ("PJ"))	5	5	—
Revenue ($ millions)	444	458	(14	)
Earnings ($ millions)	50	41	9

⁽¹⁾  Includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. and UNS Gas, Inc.

⁽²⁾  The reporting currency of UNS Energy is the US dollar.

Electricity Sales & Gas Volumes

The decrease in electricity sales was primarily due to lower average consumption as a result of warmer temperatures. Gas volumes were comparable with the same period in 2017.

Revenue

The decrease in revenue was mainly due to approximately $20 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue and the recognition of a provision reflecting income tax savings as a result of U.S. Tax Reform. The decrease was partially offset by the impact of a full quarter of new rates with the rate case settlement being effective February 27, 2017.

Earnings

The increase in earnings was primarily due to the impact of a full quarter of new rates, as discussed above. The increase was partially offset by the $7 million favourable settlement of matters pertaining to FERC-ordered transmission refunds in the first quarter of 2017 and approximately $2 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings.

CENTRAL HUDSON

Financial Highlights	Quarter Ended March 31
	2018	2017	Variance
Average US:CAD Exchange Rate (1)	1.26	1.32	(0.06	)
Electricity Sales (GWh)	1,295	1,244	51
Gas Volumes (PJ)	9	9	—
Revenue ($ millions)	275	258	17
Earnings ($ millions)	21	23	(2	)

⁽¹⁾  The reporting currency of Central Hudson is the US dollar.

Electricity Sales & Gas Volumes

The increase in electricity sales was primarily due to higher average consumption as a result of colder temperatures. Gas volumes were comparable with the same period in 2017.

MANAGEMENT DISCUSSION AND ANALYSIS 6 March 31, 2018

Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result, do not have a material impact on earnings.

Revenue

The increase in revenue was mainly due to the recovery from customers of higher commodity costs and higher delivery revenue from increases in base electricity rates effective July 1, 2017. The increase was partially offset by approximately $12 million of unfavourable foreign exchange associated with the translation of U.S. dollar-denominated revenue and the recognition of a provision reflecting income tax savings as a result of U.S. Tax Reform.

Earnings

The decrease in earnings was primarily due to higher operating costs, particularly due to higher storm restoration costs, and approximately $1 million of unfavourable foreign exchange associated with the translation of U.S. dollar-denominated earnings. The decrease was partially offset by increased delivery revenue, as discussed above.

FORTISBC ENERGY

Financial Highlights	Quarter Ended March 31
	2018	2017	Variance
Gas Volumes (PJ)	80	83	(3	)
Revenue ($ millions)	429	449	(20	)
Earnings ($ millions)	98	97	1

Gas Volumes

The decrease in gas volumes was primarily due to lower average consumption by residential and commercial customers as a result of warmer temperatures, partially offset by growth in the number of customers.

Revenue

The decrease in revenue was primarily due to a lower commodity cost of natural gas charged to customers.

Earnings

The increase in earnings was primarily due to the impact of increased investment in regulated assets, partially offset by higher operating expenses.

FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery of natural gas. As a result of the operation of regulatory deferral mechanisms, changes in consumption levels and the cost of natural gas do not have a material impact on earnings.

FORTISALBERTA

Financial Highlights	Quarter Ended March 31
	2018	2017	Variance
Energy Deliveries (GWh)	4,603	4,551	52
Revenue ($ millions)	141	147	(6	)
Earnings ($ millions)	27	25	2

Energy Deliveries

The increase in energy deliveries was primarily due to higher average consumption by residential and irrigation customers, mainly due to colder temperatures.

MANAGEMENT DISCUSSION AND ANALYSIS 7 March 31, 2018

Revenue

The decrease in revenue was primarily due to an election to record municipal franchise fee revenue on a net basis upon implementation of ASC Topic 606, Revenue from Contracts with Customers, effective January 1, 2018, using the modified retrospective approach under which comparative periods are not restated. The $11 million decrease due to the change in presentation of municipal franchise fees was partially offset by higher distribution rates effective January 1, 2018 and revenue associated with incremental return due to efficiencies achieved in the first PBR term through the ROE efficiency carry-over mechanism.

For further details on the implementation of the new revenue recognition standard refer to Note 6 to the Corporation's Interim Financial Statements for the three months ended March 31, 2018.

Earnings

The increase in earnings was primarily due to higher distribution rates and the ROE efficiency carry-over mechanism, both discussed above, partially offset by higher operating costs, mainly due to timing.

FORTISBC ELECTRIC ⁽¹⁾ 

Financial Highlights	Quarter Ended March 31
	2018	2017	Variance
Electricity Sales (GWh)	920	945	(25	)
Revenue ($ millions)	112	113	(1	)
Earnings ($ millions)	16	15	1

⁽¹⁾  Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants.

Electricity Sales

The decrease in electricity sales was primarily due to lower average consumption as a result of warmer temperatures.

Revenue and Earnings

Revenue and earnings were comparable with the same period in 2017.

Variances from regulated forecasts used to set rates for electricity revenue and energy supply costs are flowed back to customers in future rates through approved regulatory deferral mechanisms and, therefore, these variances do not have an impact on earnings.

OTHER ELECTRIC ⁽¹⁾ 

Financial Highlights	Quarter Ended March 31
	2018	2017	Variance
Average US:CAD Exchange Rate (2)	1.26	1.32	(0.06	)
Electricity Sales (GWh)	2,920	2,928	(8	)
Revenue ($ millions)	397	402	(5	)
Earnings ($ millions)	18	26	(8	)

⁽¹⁾  Comprised of utilities in Eastern Canada and the Caribbean as follows: Newfoundland Power Inc.; Maritime Electric Company, Limited; FortisOntario Inc.; the Corporation's 49% equity investment in Wataynikaneyap Power Limited Partnership; Caribbean Utilities Company, Ltd. ("Caribbean Utilities"), in which Fortis holds an approximate 60% controlling interest; two wholly-owned utilities on the Turks and Caicos Islands, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "Fortis Turks and Caicos"); and a 33% equity investment in Belize Electricity Limited ("Belize Electricity").

⁽²⁾  The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00.

MANAGEMENT DISCUSSION AND ANALYSIS 8 March 31, 2018

Electricity Sales

The decrease in electricity sales was primarily due to overall lower average consumption, particularly in Newfoundland, due to the completion of a large project by a commercial customer, and on the Turks and Caicos Islands, due to the impact of Hurricane Irma.

Revenue

The decrease in revenue was primarily due to approximately $3 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue in the Caribbean, lower electricity sales, as discussed above, and the flow through of lower energy supply costs in customer rates.

Earnings

The decrease in earnings was primarily due to the timing of energy supply costs at Newfoundland Power, lower revenue as a result of the impact of Hurricane Irma and lower equity income from Belize Electricity.

Fortis Turks and Caicos expects to recover lost revenue estimated at US$3 million, as a result of the cumulative impact of Hurricane Irma up to March 31, 2018, under its business interruption insurance. Such revenue will be recognized when the insurance claim is settled, which is expected to occur in 2018.

NON-REGULATED

ENERGY INFRASTRUCTURE ⁽¹⁾ 

Financial Highlights	Quarter Ended March 31
	2018	2017	Variance
Energy Sales (GWh)	89	82	7
Revenue ($ millions)	48	56	(8	)
Earnings ($ millions)	18	23	(5	)

⁽¹⁾  Primarily comprised of long-term contracted generation assets in British Columbia and Belize, with a combined generating capacity of 391 MW, and the Aitken Creek natural gas storage facility in British Columbia, with a total working gas capacity of 77 billion cubic feet.

Energy Sales

The increase in energy sales was primarily due to increased production at Belize, as a result of higher rainfall.

Revenue and Earnings

The decrease in revenue and earnings was primarily due to the unfavourable impact of the mark-to-market accounting of natural gas derivatives at Aitken Creek with $4 million of unrealized losses during the first quarter of 2018 compared to unrealized gains of $6 million during the same period last year. The decrease was partially offset by higher contribution due to increased gas volumes at Aitken Creek and increased energy production at Belize.

CORPORATE AND OTHER ⁽¹⁾ 

Financial Highlights	Quarter Ended March 31
($ millions)	2018		2017		Variance
Net loss	(11	)	(47	)	36

⁽¹⁾  Includes Fortis net Corporate expenses and non-regulated holding company expenses

The decrease in net expenses at Corporate and Other was primarily driven by higher income tax recovery, due to a one-time $30 million remeasurement of the Corporation's deferred income tax liabilities, which resulted from an election to file a consolidated state income tax return, and mark-to-market net losses on foreign exchange contracts and total return swaps, partially offset by lower finance charges. The effect of U.S. Tax Reform was negligible during the first quarter as the impact of holding company interest being deductible at a lower corporate tax rate of 21% was offset by a favourable timing difference associated with the application of a lower annual effective tax rate to consolidated earnings.

MANAGEMENT DISCUSSION AND ANALYSIS 9 March 31, 2018

REGULATORY HIGHLIGHTS

The nature of regulation associated with the Corporation's utilities is generally consistent with that disclosed in the 2017 Annual MD&A. The following summarizes any developments or changes in significant ongoing regulatory proceedings and significant decisions and applications for the Corporation's utilities in the first quarter of 2018.

U.S. Tax Reform

The Corporation's regulated utilities in the United States are currently working with their respective regulators to return the net income tax savings to customers from the reduction in the federal corporate income tax rate, due to U.S. Tax Reform.

ITC: In April 2018 ITC reposted 2018 formula rates charged to customers in the Midcontinent Independent System Operator ("MISO") retroactive to January 1, 2018 for ITC's MISO-regulated operating subsidiaries, as approved by FERC. A regulatory liability of $21 million (US$16 million) as at March 31, 2018 was recognized for estimated amounts to be returned to customers through the resettlement process.

UNS Energy: In April 2018 the Arizona Corporation Commission ("ACC") approved TEP's application to return ongoing savings through a combination of customer bill credits and regulatory liability. The customer bill credits become effective in May 2018. As at March 31, 2018, a regulatory liability of $12 million (US$9 million) was recognized for estimated amounts to be returned to customers in 2018. In 2019 and beyond, the Company will continue to return savings to customers through a combination of bill credits and a regulatory liability. The associated regulatory liability will be returned to customers as part of TEP's next rate case.

In March 2018 FERC issued orders directing TEP to either: (i) submit proposed revisions to its transmission rates or transmission revenue requirement to reflect the reduction in the federal corporate income tax rate; or (ii) show why a rate adjustment is not required. This regulatory filing is due in May 2018 and TEP is evaluating the impact on its FERC-approved rates.

Central Hudson: In March 2018 the New York Public Service Commission ("PSC") issued a proposal recommending the treatment of the effects of U.S. Tax Reform, including rate-making mechanisms that can be applied to return ongoing and deferred benefits to customers. In April 2018 Central Hudson provided its recommendation for applying the effects of U.S. Tax Reform in customer rates as part of a Joint Proposal, discussed below. In the interim, a regulatory liability of $8 million (US$6 million) was recognized for estimated amounts to be returned to customers.

ITC

In April 2018 a third-party complaint was filed with FERC challenging ITC's independence incentive adders that are included in transmission rates charged by ITC's operating subsidiaries in the MISO region. The independence incentive adder was established to encourage investment in transmission infrastructure and recognizes that ITC's operating subsidiaries are independent, dedicated transmission-only operations, with no affiliations with market participants in the regions in which they operate. The adder allows 0.50% to 1.00% to be added to ITC's authorized ROE, subject to any ROE cap established by FERC. While ITC believes it has a strong defense against this complaint, the outcome of this matter cannot be predicted at this time.

Central Hudson

General Rate Application

In July 2017 Central Hudson filed a rate case with the PSC requesting an increase in its allowed ROE to 9.5% from 9.0% and the equity component of its capital structure to 50% from 48%.

In April 2018 Central Hudson filed a Joint Proposal with multiple stakeholders and intervenors proposing a three-year rate plan for electric and gas delivery service commencing July 1, 2018 through June 30, 2021. Major components of the Joint Proposal include an allowed ROE of 8.8% and a common equity ratio of 48% in rate year one, 49% in rate year two and 50% in rate year three. The Joint Proposal includes an earnings sharing mechanism, whereby the Company and customers share equally earnings in excess of 50 basis points above the allowed ROE up to an achieved ROE that is 100 basis points above the allowed ROE. Earnings in excess of 100 basis points above the allowed ROE are shared primarily with customers.

MANAGEMENT DISCUSSION AND ANALYSIS 10 March 31, 2018

A proposed schedule for processing the Joint Proposal is awaiting consideration by the Administrative Law Judges. Assuming the Joint Proposal is approved, an order from the PSC is expected in June 2018 with the new rates effective as of July 1, 2018.

FortisAlberta

Generic Cost of Capital

In July 2017 the AUC established a proceeding to determine the ROE and capital structure for 2018, 2019 and 2020. The proceeding commenced in October 2017 and the oral hearing was completed in March 2018. The ROE and capital structure approved for 2017 will remain in effect on an interim basis pending the finalization of this proceeding. A decision is expected in the third quarter of 2018.

Next Generation PBR Proceeding

In March 2018 the AUC issued a decision approving the Company's 2018 distribution rates, on an interim basis, until required true-up amounts are finalized. The 2018 distribution rates will be effective January 1, 2018 with collection from customers effective April 1, 2018. The key provisions of the decision included an increase of approximately 5.5% in the distribution component of customer rates which reflected: (i) a combined inflation and productivity factor (I-X) of negative 0.2%; (ii) a K-bar placeholder of $24 million to reflect incremental capital funding requirements; and (iii) a net collection of flow-through costs of approximately $6 million, mainly reflecting the ROE efficiency carry-over mechanism associated with the first-term PBR.

FortisAlberta is pursuing options to appeal certain elements of the rate-setting design for the second PBR term.

Significant Regulatory Proceedings

The following table summarizes significant ongoing regulatory proceedings, including filing dates and expected timing of decisions for the Corporation's utilities.

Regulated Utility	Application/Proceeding	Filing Date	Expected Decision
ITC	MISO Base ROE Complaints	Not applicable	To be determined
Central Hudson	General Rate Application - Joint Proposal	July 2017	June 2018

CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheets between March 31,2018 and December 31, 2017.

Significant Changes in the Consolidated Balance Sheets between March 31, 2018 and December 31, 2017
Balance Sheet Account	Increase (1) ($ millions)	Explanation
Property, plant and equipment, net	838	The increase was mainly due to capital expenditures and the impact of foreign exchange associated with the translation of US dollar-denominated property, plant and equipment, partially offset by depreciation.
Goodwill	283	The increase was due to the impact of foreign exchange associated with the translation of US dollar-denominated goodwill.
Regulatory liabilities - current and long-term	111	The increase was primarily due to the impact of foreign exchange associated with the translation of US dollar-denominated regulatory liabilities.
Long-term debt (including current portion and short-term borrowings)	657	The increase was mainly due to the impact of foreign exchange associated with the translation of US dollar-denominated debt. The increase was also due to the issuance of first mortgage bonds by ITC, partially offset by regularly scheduled debt repayments.

MANAGEMENT DISCUSSION AND ANALYSIS 11 March 31, 2018

Significant Changes in the Consolidated Balance Sheets between March 31, 2018 and December 31, 2017
Balance Sheet Account	Increase (1) ($ millions)	Explanation
Shareholders' equity	486	The increase was due to: (i) the increase in accumulated other comprehensive income associated with the translation of the Corporation's US dollar-denominated investments in subsidiaries, net of hedging activities and tax; (ii) net earnings attributable to common shareholders for the three months ended March 31, 2018, less dividends declared on common shares; and (iii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans.

⁽¹⁾  Includes the impact of foreign exchange based upon the closing foreign exchange rate at March 31, 2018 of US$1.00=CAD$1.29 compared to the closing foreign exchange rate at December 31, 2017 of US$1.00=CAD$1.25.

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CONSOLIDATED CASH FLOWS

The table below outlines the Corporation's sources and uses of cash for the quarter ended March 31, 2018 compared to the same period in 2017, followed by a discussion of the nature of the variances in cash flows.

Summary of Consolidated Cash Flows	Quarter Ended March 31
($ millions)	2018		2017		Variance
Cash, Beginning of Period	327		269		58
Cash Provided by (Used in):
Operating Activities	589		541		48
Investing Activities	(678	)	(719	)	41
Financing Activities	89		208		(119	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	6		(1	)	7
Cash, End of Period	333		298		35

Operating Activities: Cash flow provided by operating activities was $48 million higher quarter over quarter. The increase was primarily due to favourable changes in working capital, mainly due to a payment of US$121 million in 2017 related to the ROE complaint at ITC, partially offset by the timing of transmission cost payments at FortisAlberta.

Investing Activities: Cash used in investing activities was $41 million lower quarter over quarter. The decrease was mainly due to the timing of capital expenditures and higher contributions in aid of construction.

Financing Activities: Cash provided by financing activities was $119 million lower quarter over quarter. The decrease was primarily due to higher net repayments of long-term debt and lower proceeds from the issuance of long-term debt, partially offset by lower net repayments on credit facility borrowings.

In March 2017 approximately 12.2 million common shares of Fortis were issued to an institutional investor for proceeds of $500 million. The proceeds were used to repay short-term borrowings.

MANAGEMENT DISCUSSION AND ANALYSIS 12 March 31, 2018

Proceeds from long-term debt, net of issue costs, for the quarter compared to the same period last year are summarized in the following table.

Proceeds from Long-Term Debt, Net of Issue Costs	Quarter Ended March 31
($ millions)	2018	2017	Variance
ITC (1)	290	334	(44	)
Caribbean Electric (2)	30	54	(24	)
Total	320	388	(68	)

⁽¹⁾  In March 2018 ITC issued 35-year US$225 million first mortgage bonds at 4.00%. The net proceeds from the issuance were used to repay maturing long-term debt, repay credit facility borrowings, finance capital expenditures and for general corporate purposes.

⁽²⁾  In January 2018 Fortis Turks and Caicos issued 5-year US$25 million unsecured notes at a floating interest rate of a one-month LIBOR plus a spread of 1.75%. The net proceeds from the issuance were used to repay a hurricane-related emergency standby loan.

Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay borrowings under the Corporation's committed credit facility.

Common share dividends paid in the first quarter of 2018 totalled $116 million, net of $63 million of dividends reinvested, compared to $98 million, net of $62 million of dividends reinvested, paid in the first quarter of 2017. The dividend paid per common share was $0.425 in the first quarter of 2018 compared to $0.40 in the first quarter of 2017. The weighted average number of common shares outstanding for the first quarter of 2018 was 422.0 million compared to 406.2 million for the first quarter of 2017.

CONTRACTUAL OBLIGATIONS

There were no material changes in the nature and amount of the Corporation's contractual obligations during the three months ended March 31, 2018 from those disclosed in the 2017 Annual MD&A, except as follows.

In March 2018 Maritime Electric extended its power purchase agreement with New Brunswick Power from March 2019 to February 2024, increasing the total commitment under this agreement by approximately $262 million as at March 31, 2018.

CAPITAL STRUCTURE

The Corporation's principal business of regulated electric and gas utilities requires ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in their customer rates.

MANAGEMENT DISCUSSION AND ANALYSIS 13 March 31, 2018

The consolidated capital structure of Fortis is presented in the following table.

Capital Structure	As at
	March 31, 2018		December 31, 2017
	($ millions)	(%)	($ millions)	(%)
Total debt and capital lease and finance obligations (net of cash) (1)	22,382	59.1	21,739	59.2
Preference shares	1,623	4.3	1,623	4.4
Common shareholders' equity	13,866	36.6	13,380	36.4
Total	37,871	100.0	36,742	100.0

⁽¹⁾  Includes long-term debt and capital lease and finance obligations, including current portion, and short-term borrowings, net of cash

Including amounts related to non-controlling interests, the Corporation's capital structure as at March 31, 2018 was 56.4% total debt and capital lease and finance obligations (net of cash), 4.1% preference shares, 35% common shareholders' equity and 4.5% non-controlling interests (December 31, 2017 - 56.5% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 34.8% common shareholders' equity and 4.5% non-controlling interests).

CREDIT RATINGS

As at March 31, 2018, the Corporation's credit ratings were as follows.

Rating Agency	Credit Rating	Type of Rating	Outlook
Standard & Poor's ("S&P")	A-	Corporate	Negative
	BBB+	Unsecured debt
DBRS	BBB (high)	Corporate	Stable
	BBB (high)	Unsecured debt
Moody's Investor Service	Baa3	Issuer	Stable
	Baa3	Unsecured debt

The above-noted credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company. In March 2018 S&P affirmed the Corporation's credit ratings and revised its outlook from stable to negative due to modest temporary weakening of financial measures as a result of U.S. Tax Reform, which reduces cash flow at the Corporation's U.S. regulated utilities.

CAPITAL EXPENDITURE PLAN

A breakdown of the $685 million in consolidated capital expenditures by reporting segment year-to-date 2018 is provided in the following table.

Consolidated Capital Expenditures (1)
Year-to-date March 31, 2018
($ millions)
	Regulated
								Total
		UNS	Central	FortisBC	Fortis	FortisBC	Other	Regulated	Non-
	ITC	Energy	Hudson	Energy	Alberta	Electric	Electric	Utilities	Regulated (2)	Total
Total	223	125	48	86	119	29	53	683	2	685

⁽¹⁾  Represents cash payments to construct property, plant and equipment and intangible assets, as reflected on the condensed consolidated interim statement of cash flows. Excludes the non-cash equity component of allowance for funds used during construction.

⁽²⁾  Includes Energy Infrastructure and Corporate and Other segments.

MANAGEMENT DISCUSSION AND ANALYSIS 14 March 31, 2018

Planned capital expenditures are based on detailed forecasts of energy demand, cost of labour and materials, as well as other factors, including economic conditions and foreign exchange rates, which could change and cause actual expenditures to differ from those forecast.

Consolidated capital expenditures for 2018 are forecast to be approximately $3.2 billion. The Corporation continues to advance its significant capital projects and there have been no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those that were disclosed in the 2017 Annual MD&A with the exception of the Lower Mainland System Upgrade project at FortisBC Energy.

The Lower Mainland System Upgrade project is in place to address system capacity and pipeline condition issues for the gas supply system in the Lower Mainland area of British Columbia. The British Columbia Utilities Commission ("BCUC") approved the application for this project in October 2015. The project will be completed in two phases: (i) the Coastal Transmission System ("CTS") phase, which is intended to increase security of supply; and (ii) the Lower Mainland Intermediate Pressure System Upgrade ("LMIPSU") project phase, which is focused on addressing pipeline condition issues. Construction activities for the CTS project are complete, and the new pipelines have been commissioned and are in-service. FortisBC Energy conducted further detailed engineering work and evaluated construction bids and other costs resulting in a revised cost estimate for the LMIPSU was provided to the BCUC in the first quarter of 2018. The construction of the LMIPSU is expected to occur primarily during 2018 and 2019. The total capital cost of both phases of the Lower Mainland System Upgrade is now estimated to be approximately $680 million.

Over the five-year period 2018 through 2022, consolidated capital expenditures ("Five-Year Capital Program") are expected to be approximately $15.1 billion. The increase in the Corporation's Five-Year Capital Program from the $14.5 billion disclosed in the 2017 Annual MD&A is the result of the inclusion of Fortis' effective 49% investment in the Wataynikaneyap Power Project.

The Wataynikaneyap Power Project will connect 17 remote First Nations communities in Northwestern Ontario to the main electricity grid through construction of 1,800 kilometres of transmission lines. Wataynikaneyap Power is a licensed transmission company, regulated by the Ontario Energy Board ("OEB"), equally owned by 22 First Nations communities (51%), in partnership with Fortis (49%). In 2016 the Government of Ontario designated Wataynikaneyap Power as the licensed transmission company to complete this project. In 2017 the OEB approved a deferral account to recover development costs incurred between November 2010 and the commencement of construction. In March 2018 the project reached a significant milestone with the formal announcement of a funding framework among Wataynikaneyap Power, the Government of Canada and the Government of Ontario. FortisOntario will be responsible for construction management and operation of the transmission line. The total estimated capital cost for the project is approximately $1.6 billion. The initial phase of the project to connect the Pikangikum First Nation to Ontario’s power grid is fully funded by the Canadian government and is expected to be completed by the end of 2018. The next two phases are subject to receipt of all necessary regulatory approvals, including the leave-to-construct approval from the OEB, anticipated in early 2019. These phases are targeted to be completed by the end of 2020 and 2023, respectively. In addition to providing participating First Nations communities ownership in the transmission line, the project provides socio-economic benefits, reduces environmental risk and lessens greenhouse gas emissions associated with diesel-fired generation currently used in remote locations.

ADDITIONAL INVESTMENT OPPORTUNITIES

Management is pursuing additional investment opportunities within existing service territories. These additional investment opportunities, as discussed below, are not included in the Corporation's Five-Year Capital Program.

ITC - Lake Erie Connector

The Lake Erie Connector is a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line that would provide the first direct link between the markets of the Ontario Independent Electricity System Operator and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets.

MANAGEMENT DISCUSSION AND ANALYSIS 15 March 31, 2018

In 2017 the project's major application process in the United States and Canada was completed upon receipt of permits from the U.S. Army Corps of Engineers. The project continues to advance through regulatory, operational, and economic milestones. Ongoing activities include completing project cost refinement and securing favourable transmission service agreements with prospective counterparties. Pending achievement of key milestones, completion of the project would take approximately three years from the commencement of construction.

FortisBC - Liquefied Natural Gas

The Corporation continues to pursue additional liquefied natural gas ("LNG") infrastructure investment opportunities in British Columbia, including further expansion of the Tilbury LNG facility which is uniquely positioned to meet customer demand for clean-burning natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment, and is relatively close to international shipping lanes. Fortis continues to have discussions with a number of potential export customers.

Other Opportunities

Other capital investment opportunities, above the Five-Year Capital Program, include, but are not limited to: incremental regulated transmission investment opportunities and energy storage and contracted transmission projects at ITC; renewable energy investments, energy storage projects, grid modernization, infrastructure resiliency, and transmission investments at UNS Energy; and further gas infrastructure opportunities at FortisBC Energy.

CASH FLOW REQUIREMENTS

At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of subsidiary operating cash flows, with varying levels of residual cash flows available for subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities may be required from time to time to support seasonal working capital requirements. Cash required to complete subsidiary capital expenditure programs is also expected to be financed from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis.

The Corporation's ability to service its debt obligations and pay dividends on its common and preference shares is dependent on the financial results of the subsidiaries and the related cash payments from these subsidiaries. Certain regulated subsidiaries may be subject to restrictions that may limit their ability to distribute cash to Fortis. These include restrictions by certain regulators limiting the amount of annual dividends and restrictions by certain lenders limiting the amount of debt to total capitalization at the subsidiaries. In addition, there are practical limitations on using the net assets of each of the Corporation's regulated subsidiaries to pay dividends based on management's intent to maintain the regulator-approved capital structures for each of its regulated subsidiaries. The Corporation does not expect that maintaining the targeted capital structures of its regulated subsidiaries will have an impact on its ability to pay dividends in the foreseeable future.

Cash required of Fortis to support subsidiary capital expenditure programs is expected to be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt as well as proceeds from the dividend reinvestment plan and at-the-market common equity program. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends.

In November 2016 Fortis filed a short-form base shelf prospectus, under which the Corporation may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $5 billion during the 25-month life of the base shelf prospectus. In March 2018 the Corporation established an at-the-market common equity program that allows the Corporation to issue up to $500 million of common shares from treasury to the public at the Corporation's discretion, effective until December 2018. 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 the base shelf prospectus. In March 2017 Fortis issued $500 million common equity and in December 2016 issued $500 million unsecured notes at 2.85%, both under the base shelf prospectus. A principal amount of approximately $1.0 billion remains under the base shelf prospectus.

MANAGEMENT DISCUSSION AND ANALYSIS 16 March 31, 2018

As at March 31, 2018, the average annual consolidated fixed-term debt maturities and repayments over the next five years have not materially changed from that disclosed in the 2017 Annual MD&A. The combination of available credit facilities and manageable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.

Fortis and its subsidiaries were in compliance with debt covenants as at March 31, 2018 and are expected to remain compliant throughout 2018.

CREDIT FACILITIES

As at March 31, 2018, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.0 billion, of which approximately $3.9 billion was unused, including $1.1 billion unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $4.8 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2022.

The following summary outlines the credit facilities of the Corporation and its subsidiaries.

Credit Facilities					As at
	Regulated Utilities		Corporate and Other		March 31, 2018		December 31, 2017
($ millions)
Total credit facilities (1)	3,640		1,385		5,025		4,952
Credit facilities utilized:
Short-term borrowings (1)	(39	)	—		(39	)	(209	)
Long-term debt (including current portion) (2)	(711	)	(206	)	(917	)	(671	)
Letters of credit outstanding	(73	)	(56	)	(129	)	(129	)
Credit facilities unused	2,817		1,123		3,940		3,943

⁽¹⁾  As at March 31, 2018 and December 31, 2017, there was no commercial paper outstanding. Outstanding commercial paper does not reduce available capacity under the Corporation's consolidated credit facilities.

⁽²⁾  As at March 31, 2018, credit facility borrowings classified as long-term debt included $572 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2017 - $312 million).

As at March 31, 2018 and December 31, 2017, borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods. There were no material changes in credit facilities from that disclosed in the Corporation's 2017 Annual MD&A.

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $129 million as at March 31, 2018 (December 31, 2017 - $129 million), the Corporation had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.

BUSINESS RISK MANAGEMENT

Year-to-date 2018, the business risks of the Corporation were generally consistent with those disclosed in the Corporation's 2017 Annual MD&A, including certain risks, as disclosed below, and an update to those risks, where applicable.

Regulatory Risk: For further information, refer to the "Regulatory Highlights" section of this MD&A.

Capital Resources and Liquidity Risk - Credit Ratings: Year-to-date 2018 the following changes occurred to the debt credit ratings of the Corporations' utilities: In March 2018 S&P revised its outlook on ITC, UNS Energy, FortisAlberta and Caribbean Utilities from stable to negative due to modest temporary weakening of the Corporation's financial measures as a result of U.S. Tax Reform, which reduces cash flow at the Corporation's U.S. regulated utilities. For a discussion on the Corporation's credit ratings refer to the "Liquidity and Capital Resources" section of this MD&A.

MANAGEMENT DISCUSSION AND ANALYSIS 17 March 31, 2018

CHANGES IN ACCOUNTING POLICIES

The Interim Financial Statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation's 2017 annual audited consolidated financial statements, except as described below.

Revenue from Contracts with Customers

Effective January 1, 2018, Fortis adopted Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers, which supersedes the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and enables users of financial statements to better understand and consistently analyze an entity's revenues across industries and transactions. The Corporation adopted the new revenue recognition guidance using the modified retrospective approach, under which comparative periods are not restated and the cumulative impact of applying the standard is recognized at the date of initial adoption supplemented by additional disclosures. Upon adoption, there were no adjustments to the opening balance of the Corporation's retained earnings.

The Corporation's revenue recognition policy, effective January 1, 2018, is as follows.

The majority of the Corporation's revenue is derived from energy sales and the provision of transmission services to customers based on regulator-approved tariff rates. Most of the Corporation's contracts have a single performance obligation, being the delivery of energy or the provision of transmission services. Substantially all of the Corporation's performance obligations are satisfied over time as energy is delivered and the continuous transfer of control to the customer occurs, generally using an output measure of progress performance of kilowatt hours, gigajoules, or transmission load delivered. The billing of energy sales is based on the reading of customer meters, which occurs on a systematic basis throughout the month. The billing of transmission services at ITC is based on peak load for the month.

FortisAlberta is a distribution company and, as stipulated by the regulator, is required to arrange and pay for transmission services with the Alberta Electric System Operator. These services include the collection of transmission revenue from its customers, which is achieved through invoicing the customers' retailers through FortisAlberta's transmission component of its regulator-approved rates. FortisAlberta reports revenue and expenses related to transmission services on a net basis.

Electricity, gas and transmission service revenue includes an estimate for unbilled revenue for energy consumed or services provided that have not been billed at the end of the accounting period, as approved by the regulator. The unbilled revenue accrual for the period is based on estimated electricity and gas sales and transmission services provided to customers since the last meter reading at the rates approved by the respective regulatory authority. The development of the sales estimates generally requires analysis of consumption on a historical basis in relation to key inputs, such as the current price of electricity and gas, population growth, economic activity, weather conditions and system losses. The estimation process for accrued unbilled electricity and gas consumption will result in adjustments to revenue in the periods they become known.

The Corporation's non-regulated generation operations revenue is recognized on delivery of output at rates fixed under contract or based on observed market prices as stipulated in contractual arrangements.

The Corporation estimates variable consideration at the most likely amount to which it expects to be entitled and reassesses its estimate at each reporting date until the uncertainty is resolved. Variable consideration is recognized as a refund liability until the Corporation is certain that it will be entitled to the consideration. Variable consideration includes revenue that is subject to refund until such time that a regulatory decision is received in respect of such consideration.

In the course of its operations, the Corporation's subsidiaries collect sales and municipal taxes from their customers. When customers are billed, a current liability is recognized for the sales taxes included on the customers' bill. The liability is settled when the taxes are remitted to the appropriate government authority. The Corporation's revenue excludes sales and municipal taxes. Prior to the adoption of ASC Topic 606, Central Hudson recognized sales tax and FortisAlberta recognized municipal tax on a gross basis, in both revenue and expense. Effective January 1, 2018, the exclusion of sales and municipal taxes from revenue at Central Hudson and FortisAlberta, respectively, resulted in a decrease in revenue of $14 million for the three months ended March 31, 2018.

MANAGEMENT DISCUSSION AND ANALYSIS 18 March 31, 2018

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

The Corporation disaggregates revenue by geography, regulatory status, and substantially autonomous utility operations, as disclosed in Note 5 to the Corporation's Interim Financial Statements. This represents the level of disaggregation used by the Corporation's President and Chief Executive Officer in allocating resources and evaluating performance.

Recognition and Measurement of Financial Assets and Financial Liabilities

Effective January 1, 2018, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. The amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities may elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial instrument. The adoption of this ASU did not impact the Corporation's Interim Financial Statements for the quarter ended March 31, 2018.

Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost

Effective January 1, 2018, the Corporation adopted ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost. The amendments in this update require that an employer disaggregate the current service cost component of net benefit cost and present it in the same statement of earnings line item(s) as other employee compensation costs arising from services rendered. The other components of net benefit cost are required to be presented separately from the service cost component and outside of operating income. Additionally, the amendments allow only the service cost component to be eligible for capitalization when applicable. On adoption, the Corporation applied retrospectively the presentation of the net periodic benefit costs, and prospectively the capitalization in assets of only the service cost component of net periodic benefit costs. The adoption of this ASU resulted in a retrospective $3 million reclassification from Operating Expenses to Other Income, Net on the Corporation's condensed consolidated interim statement of earnings for the quarter ended March 31, 2017.

FUTURE ACCOUNTING PRONOUNCEMENTS

The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board ("FASB"). The following updates have been issued by FASB, but have not yet been adopted by Fortis. Any ASUs not included below were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements.

Leases

ASU No. 2016-02 was issued in February 2016 and the amendments in this update, along with an additional ASU issued in 2018 to provide additional optional practical expedients, create ASC Topic 842, Leases, and supersede lease requirements in ASC Topic 840, Leases. The main provision of ASC Topic 842 is the recognition of lease assets and lease liabilities on the balance sheet by lessees for those leases that were previously classified as operating leases. For operating leases, a lessee is required to do the following: (i) recognize a right-of-use asset and a lease liability, initially measured at the present value of the lease payments, on the balance sheet; (ii) recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and (iii) classify all cash payments within operating activities in the statement of cash flows. These amendments also require qualitative disclosures along with specific quantitative disclosures. This update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted.

Fortis expects to elect a package of practical expedients that will allow the Corporation to not reassess whether any expired or existing contract is a lease or contains a lease, the lease classification of any expired or existing leases, and the initial direct costs for any existing leases. Any significant developments

MANAGEMENT DISCUSSION AND ANALYSIS 19 March 31, 2018

in its implementation efforts could change the Corporation's expected election of transition practical expedients.

Fortis continues to assess the impact that the adoption of this ASU will have on its consolidated financial statements and monitor standard-setting activities that may affect the transition requirements of the new lease standard.

Measurement of Credit Losses on Financial Instruments

ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements.

Targeted Improvements to Accounting for Hedging Activities

ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, was issued in August 2017 and the amendments in this update better align risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and presentation of hedge results. This update is effective for annual and interim periods beginning after December 15, 2018. Early adoption is permitted. The amendments in this update should be reflected as of the beginning of the fiscal year of adoption. For cash flow and net investment hedges existing at the date of adoption, the amendments should be applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to the opening balance of retained earnings. Amended presentation and disclosure guidance is required only prospectively. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements.

FINANCIAL INSTRUMENTS

The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short‑term maturity, normal trade credit terms and/or nature of these instruments, except as follows.

Financial Instruments	As at
	March 31, 2018		December 31, 2017
	Carrying	Estimated	Carrying	Estimated
($ millions)	Value	Fair Value	Value	Fair Value
Long-term debt, including current portion	22,361	23,795	21,535	23,481
Waneta Partnership promissory note	64	65	63	64

The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.

Derivative Instruments

The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments is the estimate of the amounts that the Corporation would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates. The Corporation's derivatives primarily include energy contracts that are subject to regulatory deferral, as permitted by the regulators, as well as certain limited energy contracts that are not subject to regulatory deferral and cash flow hedges.

MANAGEMENT DISCUSSION AND ANALYSIS 20 March 31, 2018

For further details of the Corporation's derivative instruments as at March 31, 2018 refer to Note 14 to the Corporation's Interim Financial Statements. There were no material changes in the nature and amount of the Corporations' derivative instruments from those disclosed in the 2017 Annual MD&A.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Corporation's Interim Financial Statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Actual results could differ from estimates.

Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates from those disclosed in the 2017 Annual MD&A.

Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows. For complete details of legal proceedings affecting the Corporation, refer to Note 15 to the Corporation's Interim Financial Statements. There were no material changes in the Corporation's contingencies from those disclosed in the 2017 Annual MD&A.

Comparative Figures in the Consolidated Statement of Cash Flows

During the year ended December 31, 2017, the Corporation discovered an immaterial error with respect to the presentation of credit facility borrowings within the financing section of its statement of cash flows. The Corporation evaluated the error and determined that there was no impact to its results of operations or financial position in previously issued financial statements and that the impact was not material to its cash flows in previously issued financial statements. For the quarter ended March 31, 2017, the correction resulted in $62 million, which was previously reported within Net Repayments and Borrowings under Committed Credit Facilities, being reported on a gross basis, with $483 million reported as Borrowings under Committed Credit Facilities and $545 million being reported as Repayments under Committed Credit Facilities. The correction did not change the total cash from financing activities.

The following table details the correction of the error for the periods ended March 31, 2017, June 30, 2017 and September 30, 2017.

	Quarter Ended						Year to Date
($ millions)	March 2017		June 2017		September 2017		September 2017
As reported
Net repayments and borrowings under committed credit facilities	65		(241	)	(221	)	(397	)
As corrected
Borrowings under committed credit facilities	483		324		659		1,466
Repayments under committed credit facilities	(545	)	(507	)	(648	)	(1,700	)
Net borrowings and repayments under committed credit facilities	127		(58	)	(232	)	(163	)

MANAGEMENT DISCUSSION AND ANALYSIS 21 March 31, 2018

Effective January 1, 2018, the Corporation elected to present, on the statement of cash flows, all borrowings and repayments under committed credit facilities on a gross basis and continue to present borrowings and repayments under uncommitted or demand credit facilities on a net basis as Net Change in Short-Term Borrowings. In addition to the above noted correction, comparative figures have been reclassified to comply with the current period presentation.

RELATED-PARTY AND INTER-COMPANY TRANSACTIONS

Related-party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. There were no material related-party transactions for the quarters ended March 31, 2018 and 2017.

Inter-company balances and inter-company transactions, including any related inter-company profit, are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The significant inter-company transactions are summarized in the following table.

Related-party and inter-company transactions	Quarter Ended March 31
($ millions)	2018	2017
Sale of capacity from Waneta Expansion to FortisBC Electric	15	16
Sale of energy from Belize Electric Company Limited to Belize Electricity	9	7
Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy	7	8

As at March 31, 2018, accounts receivable on the Corporation's condensed consolidated interim balance sheet included approximately $9 million due from Belize Electricity (December 31, 2017 - $20 million).

From time to time, the Corporation provides short-term financing to certain subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements. There were no inter-segment loans outstanding as atMarch 31, 2018 and December 31, 2017.

SUMMARY OF QUARTERLY RESULTS

The following table sets forth certain quarterly information for the Corporation. The quarterly information has been obtained from the Corporation's Interim Financial Statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.

Summary of Quarterly Results		Net Earnings
		Attributable to
		Common Equity
	Revenue	Shareholders	Earnings per Common Share
Quarter Ended	($ millions)	($ millions)	Basic ($)	Diluted ($)
March 31, 2018	2,197	323	0.77	0.76
December 31, 2017	2,111	134	0.32	0.31
September 30, 2017	1,901	278	0.66	0.66
June 30, 2017	2,015	257	0.62	0.62
March 31, 2017	2,274	294	0.72	0.72
December 31, 2016	2,053	189	0.49	0.49
September 30, 2016	1,528	127	0.45	0.45
June 30, 2016	1,485	107	0.38	0.38

MANAGEMENT DISCUSSION AND ANALYSIS 22 March 31, 2018

The summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions net of the associated acquisition-related transaction costs, and seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of electricity and gas demand, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel, purchased power and natural gas, which are flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric distribution utilities in the United States are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.

March 2018/March 2017: Net earnings attributable to common equity shareholders were $323 million, or $0.77 per common share, for the first quarter of 2018 compared to earnings of $294 million or $0.72 per common share, for the first quarter of 2017. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.

December 2017/December 2016: Net earnings attributable to common equity shareholders were $134 million, or $0.32 per common share, for the fourth quarter of 2017 compared to earnings of $189 million, or $0.49 per common share, for the fourth quarter of 2016. The decrease in earnings was driven by lower earnings at ITC, due to the one-time remeasurement of deferred income tax assets and liabilities as a result of U.S. Tax Reform, partially offset by higher earnings at Aitken Creek associated with unrealized gains on the mark-to-market of natural gas derivatives.

September 2017/September 2016: Net earnings attributable to common equity shareholders were $278 million, or $0.66 per common share, for the third quarter of 2017 compared to earnings of $127 million, or $0.45 per common share, for the third quarter of 2016. The increase was driven by earnings of $89 million at ITC, which was acquired in October 2016. The increase for the quarter was also due to: (i) lower Corporate and Other expenses, primarily due to the receipt of a break fee, net of related transaction costs, of $24 million associated with the termination of the Waneta Dam purchase agreement recognized in the third quarter of 2017, and $19 million in acquisition-related transactions costs associated with ITC recognized in the third quarter of 2016; (ii) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of natural gas derivatives quarter over quarter; (iii) strong performance at UNS Energy, largely due to the impact of the rate case settlement in 2017 and FERC-ordered refunds of $7 million in the third quarter of 2016; (iv) higher earnings at FortisAlberta due to an increase in capital tracker revenue; and (v) a lower loss at FortisBC Energy due to higher allowance for funds used during construction and lower operating expenses. The increase was partially offset by: (i) higher finance charges associated with the acquisition of ITC; (ii) the favourable settlement of Springerville Unit 1 matters at UNS Energy in the third quarter of 2016; (iii) unfavourable foreign exchange associated with the translation of US dollar-denominated earnings; (iv) lower contribution from the Caribbean, mainly due to the impact of Hurricane Irma and lower equity income from Belize Electricity; and (v) business development costs related to the Wataynikaneyap Power Project.

June 2017/June 2016: Net earnings attributable to common equity shareholders were $257 million, or $0.62 per common share, for the second quarter of 2017 compared to earnings of $107 million, or $0.38 per common share, for the second quarter of 2016. The increase was driven by earnings of $93 million at ITC, acquired in October 2016. The increase for the quarter was also due to: (i) strong performance at UNS Energy, largely due to the impact of the rate case settlement and higher electricity sales; (ii) lower Corporate and Other expenses, primarily due to $22 million in acquisition-related transaction costs associated with ITC recognized in the second quarter of 2016; (iii) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of natural gas derivatives quarter over quarter; and (iv) favourable foreign exchange associated with the translation of US dollar-denominated earnings. The increase was partially offset by higher finance charges associated with the acquisition of ITC.

MANAGEMENT DISCUSSION AND ANALYSIS 23 March 31, 2018

OUTLOOK

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

The Corporation's $15.1 billion five-year capital expenditure plan is expected to increase rate base to $33 billion by 2022, resulting in a five-year compound annual growth rate of 5.4%. The five-year capital expenditure plan is driven by investments that improve and automate the electricity grid, address natural gas system capacity and gas line network integrity, increase cyber protection and allow the grid to deliver cleaner energy.

Fortis is focused on securing further organic growth opportunities at its subsidiaries, which include the ITC Lake Erie Connector Project, gas infrastructure opportunities at FortisBC and renewable energy investments, including storage at UNS Energy. These additional investment opportunities may be funded through debt raised at the utilities, cash from operations, common equity contributions from the dividend reinvestment plan and at-the-market common equity program.

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 to 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 plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence.

OUTSTANDING SHARE DATA

As at April 30, 2018, the Corporation had issued and outstanding 423.0 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. Only the common shares of the Corporation have voting rights. The Corporation's First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether such dividends have been declared.

The number of common shares of Fortis that would be issued if all outstanding stock options were converted as at April 30, 2018 is approximately 4.2 million.

Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov. The information contained on, or accessible through, any of these websites is not incorporated by reference into this document.

MANAGEMENT DISCUSSION AND ANALYSIS 24 March 31, 2018