Exhibit 99.3

Interim Management Discussion and Analysis

For the three and six months ended June 30, 2018

Dated July 30, 2018

TABLE OF CONTENTS
Forward-Looking Information	1	Contractual Obligations	14
Corporate Overview	2	Capital Structure	14
Financial Highlights	3	Credit Ratings	15
Segmented Results of Operations	5	Capital Expenditure Plan	15
Regulated Utilities	6	Additional Investment Opportunities	16
ITC	6	Cash Flow Requirements	17
UNS Energy	6	Credit Facilities	18
Central Hudson	7	Off-Balance Sheet Arrangements	18
FortisBC Energy	8	Business Risk Management	18
FortisAlberta	8	Changes in Accounting Policies	19
FortisBC Electric	9	Future Accounting Pronouncements	20
Other Electric	9	Financial Instruments	21
Non-Regulated	10	Critical Accounting Estimates	21
Energy Infrastructure	10	Related-Party and Inter-Company Transactions	22
Corporate and Other	10	Summary of Quarterly Results	23
Regulatory Highlights	11	Outlook	24
Consolidated Financial Position	12	Outstanding Share Data	24
Liquidity and Capital Resources	13	Condensed Consolidated Interim Financial Statements (Unaudited)	F-1
Summary of Consolidated Cash Flows	13

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 and six months ended June 30, 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 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, expected costs and potential financing sources of certain capital projects including, without limitation, Tilbury liquefied natural gas expansion, the FortisBC Energy Lower Mainland System Upgrade and the Wataynikaneyap Transmission Power Project and additional opportunities beyond the base capital expenditure plan including the Lake Erie Connector Project, liquefied natural gas infrastructure investment opportunities in British Columbia and renewable energy investments including storage at UNS Energy; 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 cash required of Fortis to support subsidiary capital expenditure programs 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; the expectation that maintaining the targeted capital structure of the

MANAGEMENT DISCUSSION AND ANALYSIS 1 June 30, 2018

Corporation's regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2018; the intent of management to refinance certain borrowings under the 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 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.

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 $50 billion as at June 30, 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 June 30, 2018, the Corporation's electricity systems met a combined peak demand of 32,427 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 and to the "Corporate Overview" section of the 2017 Annual MD&A.

MANAGEMENT DISCUSSION AND ANALYSIS 2 June 30, 2018

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 are provided below.

Consolidated Financial Highlights
Periods Ended June 30	Quarter				Year-to-Date
($ millions, except for common share data)	2018	2017	Variance		2018	2017	Variance
Revenue	1,947	2,015	(68	)	4,144	4,289	(145	)
Energy Supply Costs	507	524	(17	)	1,236	1,278	(42	)
Operating Expenses	553	567	(14	)	1,106	1,146	(40	)
Depreciation and Amortization	309	298	11		611	595	16
Other Income, Net	18	20	(2	)	27	48	(21	)
Finance Charges	243	232	11		479	461	18
Income Tax Expense	61	102	(41	)	83	208	(125	)
Net Earnings	292	312	(20	)	656	649	7
Net Earnings Attributable to:
Non-Controlling Interests	35	38	(3	)	60	65	(5	)
Preference Equity Shareholders	17	17	—		33	33	—
Common Equity Shareholders	240	257	(17	)	563	551	12
Net Earnings	292	312	(20	)	656	649	7
Earnings per Common Share
Basic ($)	0.57	0.62	(0.05	)	1.33	1.34	(0.01	)
Diluted ($)	0.57	0.62	(0.05	)	1.33	1.34	(0.01	)
Weighted Average Number of Common Shares Outstanding (# millions)	423.8	416.8	7.0		422.9	411.5	11.4
Cash Flow from Operating Activities	682	649	33		1,271	1,190	81

Revenue

The decrease in revenue for the quarter was primarily due to unfavourable foreign exchange, the recovery of lower income tax expense 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 impact of growth in rate base.

The decrease in revenue year to date was driven by the same factors discussed above for the quarter, partially offset by the impact of the rate case settlement at UNS Energy being effective February 27, 2017.

Energy Supply Costs

The decrease in energy supply costs for the quarter and year to date was primarily due to favourable foreign exchange and lower overall commodity costs.

Operating Expenses

The decrease in operating expenses for the quarter and year to date was primarily due to favourable foreign exchange. The decrease was partially offset by increased maintenance expense due to planned generation outages at UNS Energy during the second quarter of 2018.

Depreciation and Amortization

The increase in depreciation and amortization for the quarter and year to date was primarily due to continued investment in energy infrastructure at the Corporation's utilities, partially offset by favourable foreign exchange.

MANAGEMENT DISCUSSION AND ANALYSIS 3 June 30, 2018

Other Income, Net

The decrease in other income, net of expenses, for the quarter and year to date was primarily due to the favourable settlement of matters at UNS Energy pertaining to the Federal Energy Regulatory Commission ("FERC") ordered transmission refunds in 2017, mark-to-market net losses on foreign exchange contracts and total return swaps in 2018, and unfavourable foreign exchange.

Finance Charges

The increase in finance charges for the quarter and year to date was primarily due to overall higher debt levels at the Corporation's utilities to support capital expenditure programs, partially offset by favourable foreign exchange.

Income Tax Expense

The decrease in income tax expense for the quarter and year to date was primarily due to U.S. tax reform and favourable foreign exchange. The decrease year to date was also due to 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.

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

The decrease in net earnings attributable to common equity shareholders for the quarter was primarily due to: (i) lower earnings from the Aitken Creek natural gas storage facility ("Aitken Creek") related to unrealized net losses on the mark-to-market of natural gas derivatives quarter over quarter; (ii) the impact of U.S. tax reform; (iii) unfavourable foreign exchange; and (iv) the favourable settlement of matters at UNS Energy pertaining to FERC-ordered transmission refunds in 2017. The decrease was partially offset by the settlement of Fortis Turks and Caicos' business interruption insurance claim, related to the impact of Hurricane Irma, and growth in rate base.

The increase in net earnings attributable to common equity shareholders year to date 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 year of new rates compared to last year at UNS Energy; and (iii) growth in rate base. The increase was partially offset by the same factors discussed above for the quarter.

Basic earnings per common share for the quarter and year to date were lower by $0.05 and $0.01, respectively, compared to the same periods in 2017. The decrease was due to the impact of the above-noted items on net earnings attributable to common equity shareholders and an increase in the weighted average number of common shares outstanding associated with the Corporation's dividend reinvestment and share plans, and on a year-to-date basis by the issuance of $500 million common equity in March 2017.

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.

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 June 30, 2018

A reconciliation of the non-US GAAP measures is provided below.

Non-US GAAP Reconciliation
Periods Ended June 30	Quarter					Year-to-Date
($ millions, except for common share data)	2018	2017		Variance		2018		2017		Variance
Net Earnings Attributable to Common Equity Shareholders	240	257		(17	)	563		551		12
Adjusting Items:
UNS Energy - Settlement of FERC-ordered transmission refunds	—	(4	)	4		—		(11	)	11
Corporate and Other -
Remeasurement of deferred income tax liabilities - consolidated state income tax election	—	—		—		(30	)	—		(30	)
Adjusted Net Earnings Attributable to Common Equity Shareholders	240	253		(13	)	533		540		(7	)
Adjusted Basic Earnings Per Common Share ($)	0.57	0.61		(0.04	)	1.26		1.31		(0.05	)
Weighted Average Number of Common Shares Outstanding (# millions)	423.8	416.8		7.0		422.9		411.5		11.4

SEGMENTED RESULTS OF OPERATIONS

Segmented Net Earnings Attributable to Common Equity Shareholders
Periods Ended June 30	Quarter						Year-to-Date
($ millions)	2018		2017		Variance		2018		2017		Variance
Regulated Utilities
ITC	86		93		(7	)	172		184		(12	)
UNS Energy	81		89		(8	)	131		130		1
Central Hudson	12		10		2		33		33		—
FortisBC Energy	7		6		1		105		103		2
FortisAlberta	32		31		1		59		56		3
FortisBC Electric	15		16		(1	)	31		31		—
Other Electric	35		27		8		53		53		—
Non-Regulated
Energy Infrastructure	20		25		(5	)	38		48		(10	)
Corporate and Other	(48	)	(40	)	(8	)	(59	)	(87	)	28
Net Earnings Attributable to Common Equity Shareholders	240		257		(17	)	563		551		12

A discussion of the financial results of the Corporation's reporting segments follows. A summary of any developments or changes in significant ongoing regulatory decisions and applications pertaining to the Corporation's utilities is provided in the "Regulatory Highlights" section of this MD&A.

MANAGEMENT DISCUSSION AND ANALYSIS 5 June 30, 2018

REGULATED UTILITIES

ITC

Financial Highlights (1)
Periods Ended June 30	Quarter				Year-to-Date
($ millions)	2018	2017	Variance		2018	2017	Variance
Average US:CAD Exchange Rate (2)	1.29	1.34	(0.05	)	1.28	1.33	(0.05	)
Revenue	374	408	(34	)	728	803	(75	)
Earnings	86	93	(7	)	172	184	(12	)

⁽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.

Revenue

The decrease in revenue for the quarter and year to date was primarily due to approximately $16 million and $33 million, respectively, of unfavourable foreign exchange and the recovery of lower federal corporate income tax in customer rates associated with U.S. tax reform, partially offset by the impact of growth in rate base.

Earnings

The decrease in earnings for the quarter and year to date was primarily due to: (i) the unfavourable net impact of U.S. tax reform; (ii) approximately $4 million and $8 million, respectively, of unfavourable foreign exchange; and (iii) higher business development costs on a year-to-date basis. The decrease was partially offset by the impact of growth in rate base.

UNS ENERGY ⁽¹⁾ 

Financial Highlights	Quarter				Year-to-Date
Periods Ended June 30	2018	2017	Variance		2018	2017	Variance
Average US:CAD Exchange Rate (2)	1.29	1.34	(0.05	)	1.28	1.33	(0.05	)
Electricity Sales (gigawatt hours ("GWh"))	3,974	3,618	356		7,299	7,002	297
Gas Volumes (petajoules ("PJ"))	2	3	(1	)	7	8	(1	)
Revenue ($ millions)	530	552	(22	)	974	1,010	(36	)
Earnings ($ millions)	81	89	(8	)	131	130	1

⁽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 increase in electricity sales for the quarter and year to date was primarily a result of an increase in short-term wholesale sales due to an increase in system capacity related to Gila River generating station Unit 2, partially offset by lower average consumption, as a result of warmer winter temperatures affecting heating load. Gas volumes were comparable with the same periods in 2017.

Revenue

The decrease in revenue for the quarter was primarily due to approximately $22 million of unfavourable foreign exchange, the recovery of lower corporate income tax in customer rates associated with U.S. tax reform, and the favourable settlement of matters pertaining to FERC-ordered transmission refunds in 2017, partially offset by the flow through of higher energy supply costs and an increase in short-term wholesale sales.

The decrease in revenue year to date was primarily due to approximately $42 million of unfavourable foreign exchange, along with the same factors discussed above for the quarter. The decrease was partially offset by the impact of the rate case settlement effective February 27, 2017.

MANAGEMENT DISCUSSION AND ANALYSIS 6 June 30, 2018

Earnings

The decrease in earnings for the quarter was primarily due to higher operating costs resulting from planned generation outages, the favourable settlement of matters pertaining to FERC-ordered transmission refunds in 2017, and approximately $3 million of unfavourable foreign exchange. The decrease was partially offset by the favourable net impact of U.S. tax reform.

The increase in earnings year to date was primarily due to the impact of the rate case settlement, as discussed above. The same factors discussed above for the quarter also impacted year-to-date earnings, including approximately $5 million of unfavourable foreign exchange.

CENTRAL HUDSON

Financial Highlights	Quarter				Year-to-Date
Periods Ended June 30	2018	2017	Variance		2018	2017	Variance
Average US:CAD Exchange Rate (1)	1.29	1.34	(0.05	)	1.28	1.33	(0.05	)
Electricity Sales (GWh)	1,157	1,134	23		2,452	2,378	74
Gas Volumes (PJ)	4	4	—		13	13	—
Revenue ($ millions)	201	206	(5	)	476	464	12
Earnings ($ millions)	12	10	2		33	33	—

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

Electricity Sales & Gas Volumes

The increase in electricity sales for the quarter and year to date was primarily due to higher average consumption as a result of colder temperatures increasing heating load. Gas volumes were comparable with the same periods in 2017.

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 decrease in revenue for the quarter was primarily due to approximately $9 million of unfavourable foreign exchange and the recovery of lower corporate income tax in customer rates associated with U.S. tax reform. The decrease was partially offset by an increase in base electricity rates effective July 1, 2017.

The increase in revenue year to date was mainly due to the recovery from customers of higher commodity costs and an increase in base electricity rates effective July 1, 2017. The increase was partially offset by approximately $20 million of unfavourable foreign exchange and the impact of U.S. tax reform, as discussed above.

Earnings

The increase in earnings for the quarter was primarily due to the rate increase effective July 1, 2017 reflecting a return on increased rate base assets. Year-to-date earnings were comparable with the same period in 2017 as the impact of the rate increase was offset by approximately $2 million of unfavourable foreign exchange and higher operating costs, particularly due to higher storm restoration costs.

MANAGEMENT DISCUSSION AND ANALYSIS 7 June 30, 2018

FORTISBC ENERGY

Financial Highlights	Quarter				Year-to-Date
Periods Ended June 30	2018	2017	Variance		2018	2017	Variance
Gas Volumes (PJ)	39	42	(3	)	119	125	(6	)
Revenue ($ millions)	226	227	(1	)	655	676	(21	)
Earnings ($ millions)	7	6	1		105	103	2

Gas Volumes

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

Revenue

The decrease in revenue for the quarter and year to date was primarily due to a lower commodity cost of natural gas charged to customers.

Earnings

The increase in earnings for the quarter and year to date 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				Year-to-Date
Periods Ended June 30	2018	2017	Variance		2018	2017	Variance
Energy Deliveries (GWh)	3,968	3,983	(15	)	8,571	8,534	37
Revenue ($ millions)	143	148	(5	)	284	295	(11	)
Earnings ($ millions)	32	31	1		59	56	3

Energy Deliveries

The decrease in energy deliveries for the quarter was primarily due to lower average consumption by oil and gas customers, related to sites exiting service since 2017, and residential customers, as a result of lower heating load. The decrease was partially offset by an increase in the number of commercial customers and lower precipitation resulting in increased average consumption by irrigation customers.

The increase in energy deliveries year to date was primarily due to higher average consumption by commercial and irrigation customers, as discussed above, and residential customers, mainly due to increased heating load in the first quarter of 2018 compared to the same period last year. The increase was partially offset by lower average consumption by oil and gas customers, as discussed above.

Revenue

The decrease in revenue for the quarter and year to date was primarily due to an election to record municipal franchise fee revenue on a net basis upon implementation of Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers, effective January 1, 2018, using modified retrospective approach under which comparative periods are not restated. The $11 million decrease for the quarter and $22 million decrease year to date 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 performance-based rate setting ("PBR") term through the return on equity ("ROE") efficiency carryover mechanism.

MANAGEMENT DISCUSSION AND ANALYSIS 8 June 30, 2018

Earnings

The increase in earnings for the quarter and year to date was primarily due to higher distribution rates and the ROE efficiency carryover mechanism, both discussed above, partially offset by higher operating costs related to vegetation management and higher interest expense related to a long-term debt issuance in 2017.

FORTISBC ELECTRIC

Financial Highlights	Quarter				Year-to-Date
Periods Ended June 30	2018	2017	Variance		2018	2017	Variance
Electricity Sales (GWh)	722	712	10		1,642	1,657	(15	)
Revenue ($ millions)	89	85	4		201	198	3
Earnings ($ millions)	15	16	(1	)	31	31	—

Electricity Sales

The increase in electricity sales for the quarter was primarily due to favourable economic conditions that lead to higher average consumption by commercial customers.

The decrease in electricity sales year to date was due to lower average consumption as a result of warmer temperatures reducing heating load in the first quarter of 2018 compared to 2017, partially offset by higher average consumption by commercial customers, as discussed above.

Revenue

The increase in revenue for the quarter and year to date was primarily due to higher third-party contract work and the impact of electricity sales, as discussed above.

Earnings

Earnings for the quarter and year to date were comparable with the same periods 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				Year-to-Date
Periods Ended June 30	2018	2017	Variance		2018	2017	Variance
Average US:CAD Exchange Rate (2)	1.29	1.34	(0.05	)	1.28	1.33	(0.05	)
Electricity Sales (GWh)	2,134	2,154	(20	)	5,054	5,082	(28	)
Revenue ($ millions)	336	331	5		733	733	—
Earnings ($ millions)	35	27	8		53	53	—

⁽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; FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "FortisTCI"); and a 33% equity investment in Belize Electricity Limited ("BEL").

⁽²⁾  The reporting currency of Caribbean Utilities and FortisTCI is the US dollar. The reporting currency of BEL is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00.

Electricity Sales

The decrease in electricity sales for the quarter and year to date was due to overall lower average consumption, including the completion of a large project by a commercial customer in Newfoundland, partially offset by weather variances that increased residential consumption in certain areas.

MANAGEMENT DISCUSSION AND ANALYSIS 9 June 30, 2018

Revenue

The increase in revenue for the quarter was primarily due to FortisTCI's business interruption insurance proceeds related to Hurricane Irma and the flow through of an overall increase in energy supply costs. The increase was partially offset by approximately $3 million of unfavourable foreign exchange and lower electricity sales, as discussed above.

On a year-to-date basis, revenue was favourably impacted by the same factors discussed above for the quarter as well as the flow through of an overall increase in energy supply costs. However, the favourable impact was offset by approximately $6 million of unfavourable foreign exchange and lower electricity sales.

Earnings

The increase in earnings for the quarter was primarily due to insurance proceeds, as discussed above, the seasonality of energy supply costs at Newfoundland Power, and the timing of operating costs.

Earnings year to date were comparable with the same period in 2017 as the increase due to insurance proceeds, discussed above, was offset by the seasonality of energy supply costs at Newfoundland Power and the timing of operating costs.

NON-REGULATED

ENERGY INFRASTRUCTURE ⁽¹⁾ 

Financial Highlights	Quarter				Year-to-Date
Periods Ended June 30	2018	2017	Variance		2018	2017	Variance
Energy Sales (GWh)	528	519	9		617	601	16
Revenue ($ millions)	49	59	(10	)	97	115	(18	)
Earnings ($ millions)	20	25	(5	)	38	48	(10	)

⁽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 for the quarter and year to date was primarily due to increased hydro-electric production in Belize, as a result of higher rainfall.

Revenue and Earnings

The decrease in revenue and earnings for the quarter and year to date was primarily due to the unfavourable impact of the mark-to-market accounting of natural gas derivatives at Aitken Creek with unrealized losses of $11 million and $15 million, respectively, compared to unrealized gains of $3 million and $9 million, respectively, for the same periods in 2017. The decrease was partially offset by higher contribution due to increased gas volumes and favourable pricing at Aitken Creek and increased hydro-electric production in Belize.

CORPORATE AND OTHER ⁽¹⁾ 

Financial Highlights
Periods Ended June 30	Quarter						Year-to-Date
($ millions)	2018		2017		Variance		2018		2017		Variance
Net loss	(48	)	(40	)	(8	)	(59	)	(87	)	28

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

The increase in net expenses for the quarter was primarily driven by a lower income tax recovery due to U.S. tax reform, which resulted in the application of a lower annual effective tax rate to consolidated earnings and holding company interest being deductible at a lower corporate tax rate of 21%. The increase was partially offset by lower stock-based compensation.

MANAGEMENT DISCUSSION AND ANALYSIS 10 June 30, 2018

The decrease in net expenses year to date 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. The remaining increase in net expenses was due to mark-to-market net losses on foreign exchange contracts and total return swaps, which was substantially offset by lower stock-based compensation and lower finance charges.

REGULATORY HIGHLIGHTS

Regulation of the Corporation's utilities is generally consistent with that disclosed in its 2017 Annual MD&A. A summary of significant regulatory developments in the first six months of 2018 follows.

U.S. Tax Reform

The Corporation's U.S. utilities are working with their respective regulators to return to customers the net income tax savings resulting from U.S. tax reform.

ITC: In April 2018 ITC reposted formula rates charged to customers of its Midcontinent Independent System Operator ("MISO") regulated subsidiaries retroactive to January 1, 2018, as approved by FERC. As at June 30, 2018, the amounts owing had been substantially returned to customers.

UNS Energy: In April 2018 the Arizona Corporation Commission approved TEP's application to return ongoing income tax savings through a combination of customer bill credits and regulatory liabilities. Customer bill credits became effective in May 2018. As at June 30, 2018, a regulatory liability of $10 million (US$8 million) was recognized for amounts to be returned to customers in the remainder of 2018. In 2019 and beyond, TEP will continue to return savings to customers using the same approach. Regulatory liabilities will be returned to customers as part of TEP's next rate case.

In March 2018 FERC issued an order 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. In May 2018 TEP proposed an overall customer rate reduction, to be effective March 2018, reflecting the lower federal corporate income tax rate. The proposal is currently being reviewed by FERC.

Central Hudson: In June 2018, as part of its approval of a joint proposal, discussed below, the New York Public Service Commission ("PSC") approved Central Hudson's recommendation to reflect the recovery of lower federal corporate income tax in customer rates effective July 1, 2018. As at June 30, 2018, a regulatory liability of $14 million (US$10 million) was recognized related to the income tax savings realized in the first six months of 2018. As approved by the PSC, the refund of this regulatory liability to customers will be determined as part of a future regulatory proceeding.

ITC

In April 2018 a third-party complaint was filed with FERC challenging independence incentive adders that are included in transmission rates charged by ITC's MISO-regulated operating subsidiaries. Independence incentive adders were established to encourage transmission investment and recognize that ITC's operating subsidiaries are independent, dedicated transmission-only operations, with no affiliation to market participants in their regions. The adder allows 0.50% or 1.00% to be added to the authorized ROE, subject to any ROE cap established by FERC. The outcome of this matter cannot be predicted at this time; however, ITC believes it has a strong position in respect of this complaint.

Central Hudson

In June 2018 the PSC issued an order approving a three-year rate plan, or joint proposal, that had been filed by Central Hudson along with multiple stakeholders and intervenors, pursuant to the July 2017 general rate application. The order included an allowed ROE of 8.8% and common equity ratios of 48%, 49% and 50% in rate years one, two and three, respectively, and is effective July 1, 2018 through June 30, 2021. Also included is an earnings sharing mechanism whereby the Company and customers share equally earnings between 50 and 100 basis points above the allowed ROE. Earnings beyond this are primarily returned to customers.

MANAGEMENT DISCUSSION AND ANALYSIS 11 June 30, 2018

FortisAlberta

Generic Cost of Capital Proceeding: Oral hearings to determine the ROE and capital structure for 2018, 2019 and 2020 were completed in March 2018. The ROE and capital structure approved for 2017 will remain in effect on an interim basis pending a final decision by the Alberta Utilities Commission ("AUC"), which is expected in the third quarter of 2018.

Next Generation Performance-Based Rate Setting Proceeding: In March 2018 the AUC approved the Company’s 2018 distribution rates, on an interim basis, until true-up amounts are finalized. New rates were effective January 1, 2018 with collection from customers effective April 1, 2018. Key provisions included an increase of approximately 5.5% in the distribution component of rates.

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

CONSOLIDATED FINANCIAL POSITION

The significant changes in the consolidated balance sheets between June 30,2018 and December 31, 2017 is provided below.

Significant Changes in the Consolidated Balance Sheets between June 30, 2018 and December 31, 2017
Balance Sheet Account	Increase/ (Decrease) (1) ($ millions)	Explanation
Cash and cash equivalents	(130)	The decrease was mainly due to the timing of transmission cost payments at FortisAlberta and a debt issuance at ITC in November 2017.
Property, plant and equipment, net	1,891	The increase was mainly due to capital expenditures, foreign exchange, and the recognition of a capital lease for Gila River generating station Unit 2 at UNS Energy, partially offset by depreciation.
Goodwill	506	The increase was due to foreign exchange.
Accounts payable and other current liabilities	(284)	The decrease was primarily due to the timing of the declaration of common share dividends, timing of transmission cost payments at FortisAlberta, and lower amounts owing for energy supply costs associated with the seasonality of operations. The decrease was partially offset by foreign exchange.
Regulatory liabilities - current and long-term	131	The increase was mainly due to foreign exchange.
Deferred income tax liabilities	167	The increase was mainly due to timing differences related to capital expenditures at the regulated utilities and foreign exchange.
Long-term debt (including current portion and short-term borrowings)	1,073	The increase was mainly due to foreign exchange. The increase also reflects higher net borrowings under committed credit facilities and the issuance of first mortgage bonds by ITC, partially offset by regularly scheduled debt repayments.
Capital lease and finance obligations (including current portion)	201	The increase was mainly due to UNS Energy's recognition of a capital lease for Gila River generating station Unit 2.
Shareholders' equity	1,011	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 six months ended June 30, 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.
Non-controlling interests	104	The increase was mainly due to foreign exchange.

⁽¹⁾  Includes the impact of foreign exchange based upon the closing foreign exchange rate at June 30,2018 of US$1.00=CAD$1.32 compared to the closing foreign exchange rate at December 31, 2017 of US$1.00=CAD$1.25.

MANAGEMENT DISCUSSION AND ANALYSIS 12 June 30, 2018

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CONSOLIDATED CASH FLOWS

The Corporation's sources and uses of cash is provided below, followed by a discussion of the nature of the variances in cash flows.

Summary of Consolidated Cash Flows
Periods Ended June 30	Quarter						Year-to-Date
($ millions)	2018		2017		Variance		2018		2017		Variance
Cash, Beginning of Period	333		298		35		327		269		58
Cash Provided by (Used in):
Operating Activities	682		649		33		1,271		1,190		81
Investing Activities	(792	)	(741	)	(51	)	(1,470	)	(1,460	)	(10	)
Financing Activities	(31	)	27		(58	)	58		235		(177	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	5		(2	)	7		11		(3	)	14
Cash, End of Period	197		231		(34	)	197		231		(34	)

Operating Activities

The increase in cash provided by operating activities for the quarter and year to date was primarily due to favourable changes in working capital, mainly due to the payment of an ROE complaint refund in the first quarter of 2017 at ITC, partially offset by the timing of transmission cost payments at FortisAlberta.

Investing Activities

The increase in cash used in investing activities for the quarter was driven by the timing of capital expenditures. Cash used in investing activities was comparable year to date.

Financing Activities

The decrease in cash provided by financing activities for the quarter and year to date was primarily due to lower proceeds from the issuance of long-term debt and higher repayments of long-term debt, partially offset by lower net repayments under committed credit facility borrowings.

In the first quarter of 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.

Proceeds from long-term debt, net of issue costs are summarized below.

Proceeds from Long-Term Debt, Net of Issue Costs
Periods ended June 30	Quarter				Year-to-Date
($ millions)	2018	2017	Variance		2018	2017	Variance
ITC (1)	—	267	(267	)	290	601	(311	)
Central Hudson (2)	32	—	32		32	—	32
FortisTCI (3)	—	—	—		30	—	30
Newfoundland Power	—	75	(75	)	—	75	(75	)
Caribbean Utilities	—	26	(26	)	—	80	(80	)
Total	32	368	(336	)	352	756	(404	)

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

⁽²⁾  In June 2018 Central Hudson issued 30-year US$25 million unsecured notes at 4.27%. The net proceeds were used for general corporate purposes.

⁽³⁾  In February 2018 FortisTCI 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 were used to repay a hurricane-related emergency standby loan.

MANAGEMENT DISCUSSION AND ANALYSIS 13 June 30, 2018

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 second quarter of 2018 totalled $114 million, net of $66 million of dividends reinvested, compared to $104 million, net of $63 million of dividends reinvested, paid in the second quarter of 2017. Common share dividends paid year-to-date 2018 were $230 million, net of $129 million of dividends reinvested, compared to $202 million, net of $125 million of dividends reinvested, paid year-to-date 2017. The dividend paid per common share for each of the first and second quarters of 2018 was $0.425 compared to $0.40 for the same periods in 2017. The weighted average number of common shares outstanding for the second quarter and year-to-date of 2018 was 423.8 million and 422.9 million, respectively, compared to 416.8 million and 411.5 million for the same periods in 2017.

On July 25, 2018, the board of directors of Fortis declared dividends of $0.425 per common share.

CONTRACTUAL OBLIGATIONS

There were no material changes in contractual obligations from that disclosed in the Corporation's 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 June 30, 2018.

In May 2018, following the acquisition of Gila River generating station Units 1 and 2 by a third party with whom UNS Energy has a power purchase agreement, UNS Energy recorded an increase of US$165 millionto capital lease obligations to reflect the anticipated exercising of UNS Energy's option to purchase Unit 2 in December 2019.

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. 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.

The consolidated capital structure of Fortis is presented below.

Capital Structure	As at
	June 30, 2018		December 31, 2017
	($ millions)	(%)	($ millions)	(%)
Total debt and capital lease and finance obligations (net of cash) (1)	23,143	59.1	21,739	59.2
Preference shares	1,623	4.1	1,623	4.4
Common shareholders' equity	14,391	36.8	13,380	36.4
Total	39,157	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 June 30, 2018 was 56.4% total debt and capital lease and finance obligations (net of cash), 4.0% preference shares, 35.1% 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).

MANAGEMENT DISCUSSION AND ANALYSIS 14 June 30, 2018

CREDIT RATINGS

As at June 30, 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 consolidated capital expenditures by reporting segment is provided below.

Consolidated Capital Expenditures (1)
Year-to-date June 30, 2018
($ millions)
	Regulated
								Total
		UNS	Central	FortisBC	Fortis	FortisBC	Other	Regulated	Non-
	ITC	Energy	Hudson	Energy	Alberta	Electric	Electric	Utilities	Regulated (2)	Total
Total	468	269	107	200	223	54	125	1,446	31	1,477

⁽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.

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 those noted below for FortisBC Energy.

Approximately $450 million, including allowance for funds used during construction ("AFUDC") and development costs, has been invested in the Tilbury liquefied natural gas ("LNG") facility expansion, in British Columbia, to the end of the second quarter of 2018. The total cost of the project is estimated at approximately $470 million, including approximately $70 million of AFUDC and development costs, and includes a new LNG storage tank and liquefier. The commissioning process of the facility was interrupted in the third quarter of 2017. The restart of commissioning and LNG production is anticipated to commence during the second half of 2018. Based on the commissioning process going as planned, the project will be completed in 2019.

MANAGEMENT DISCUSSION AND ANALYSIS 15 June 30, 2018

The Lower Mainland System Upgrade project is designed 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 approved, substantially as filed, the application for this project in October 2015. The project is being 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") phase, which is focused on addressing pipeline condition issues. Construction activities for the CTS phase 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 which resulted in a revised cost estimate for the LMIPSU. The LMIPSU is expected to be constructed primarily during 2018 and 2019. The total capital cost of both phases of the Lower Mainland System Upgrade is now estimated to be approximately $640 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 Transmission Power Project.

The Wataynikaneyap Transmission 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. The leave-to-construct application was filed with the OEB in June 2018 and approval is expected 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.

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.

MANAGEMENT DISCUSSION AND ANALYSIS 16 June 30, 2018

FortisBC - Liquefied Natural Gas

The Corporation continues to pursue additional 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 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.

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.

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 and the related cash payments from 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 subsidiaries' regulator-approved capital structures. 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.

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.

As at June 30, 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 June 30, 2018 and are expected to remain compliant throughout 2018.

MANAGEMENT DISCUSSION AND ANALYSIS 17 June 30, 2018

CREDIT FACILITIES

As at June 30, 2018, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.1 billion, of which approximately $3.8 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 2023.

Credit facilities are summarized below.

Credit Facilities					As at
	Regulated Utilities		Corporate and Other		June 30, 2018		December 31, 2017
($ millions)
Total credit facilities	3,706		1,385		5,091		4,952
Credit facilities utilized:
Short-term borrowings	(69	)	—		(69	)	(209	)
Long-term debt (including current portion) (1)	(803	)	(248	)	(1,051	)	(671	)
Letters of credit outstanding	(69	)	(59	)	(128	)	(129	)
Credit facilities unutilized	2,765		1,078		3,843		3,943

⁽¹⁾  The current portion was $601 million (December 31, 2017 - $312 million).

Borrowings under 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 $128 million as at June 30, 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

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 18 June 30, 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

Effective January 1, 2018, Fortis adopted ASC Topic 606, Revenue from Contracts with Customers, which clarifies the principles for recognizing revenue and requires additional disclosures. Fortis adopted the new standard using the modified retrospective approach, under which comparative periods are not restated and the cumulative impact is recognized at the date of adoption supplemented by additional disclosures. Upon adoption, there were no adjustments to the opening balance of retained earnings.

Most 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 contracts have a single performance obligation, being the delivery of energy or the provision of transmission services. Revenue is generally measured in kilowatt hours, gigajoules, or transmission load delivered. The billing of energy sales is based on customer meter readings, which occur systematically throughout each month. The billing of transmission services at ITC is based on peak monthly load.

FortisAlberta is a distribution company and is required by its regulator to arrange and pay for transmission services with the Alberta Electric System Operator. These services include the collection of transmission revenue from its customers, which is achieved through invoicing the customers' retailers through the 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 unbilled revenue estimate for energy consumed or services provided since the last meter reading that have not been billed at the end of the accounting period. Sales estimates generally reflect an analysis of historical consumption in relation to key inputs, such as current energy prices, population growth, economic activity, weather conditions and system losses. Unbilled revenue accruals are adjusted in the periods actual consumption becomes known.

Generation revenue from non-regulated operations is recognized on delivery at contracted rates.

The Corporation estimates variable consideration at the most likely amount and reassesses its estimate at each reporting date until the amount is known. Variable consideration, including amounts subject to a future regulatory decision, is recognized as a refund liability until the Corporation is certain that it will be entitled to the consideration.

The Corporation's revenue excludes sales and municipal taxes collected from customers. 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 these taxes from revenue resulted in a decrease in revenue of$12 million and $26 millionfor the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017.

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 will be less than one year.

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

MANAGEMENT DISCUSSION AND ANALYSIS 19 June 30, 2018

Financial Instruments

Effective January 1, 2018, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. Principally, it requires: (i) equity investments in unconsolidated entities not accounted for using the equity method 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 liabilities to be presented separately in the financial statement notes, grouped by measurement category and form. Adoption of this ASU did not impact the Interim Financial Statements.

Pension and Postretirement Benefit Costs

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, which requires current service costs to be disaggregated and grouped in the statement of earnings with other employee compensation costs arising from services rendered. The other components of net periodic benefit costs must be presented separately and outside of operating income. Additionally, only the service cost component is eligible for capitalization. On adoption, the Corporation applied the presentation guidance retrospectively and the capitalization guidance prospectively. This resulted in a retrospective $4 million and $7 million reclassification from Operating Expenses to Other Income, Net for the three and six months ended June 30, 2017, respectively, in the Interim Financial Statements.

FUTURE ACCOUNTING PRONOUNCEMENTS

Leases

ASU No. 2016-02, Leases (ASC Topic 842), was issued in February 2016, is effective for Fortis January 1, 2019 with earlier adoption permitted, and is to be applied using a modified retrospective approach with implementation options, referred to as practical expedients. Principally, it requires balance sheet recognition of a right-of-use asset and a lease liability by lessees for those leases that are classified as operating leases along with additional disclosures. Based on Fortis' assessment to date, leasing activities accounted for as operating leases primarily relate to office facilities and utility plant and equipment.

Fortis expects to elect a package of practical expedients that will allow it 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. Fortis also expects to elect an additional practical expedient that permits entities to not evaluate existing land easements that were not previously accounted for as leases.

Fortis continues to assess the impact of adoption and monitor standard-setting activities that may affect transition requirements.

Hedging

ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, was issued in August 2017, is effective for Fortis January 1, 2019 with earlier adoption permitted and is to be applied as of the beginning of the fiscal year of adoption. Principally, it better aligns risk management activities and financial reporting for hedging relationships through changes to designation, measurement, presentation and disclosure guidance. 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 opening retained earnings. Amended presentation and disclosure guidance is to be applied prospectively. Fortis is assessing the impact of adoption.

Financial Instruments

ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016, is effective for Fortis January 1, 2020 and is to be applied on a modified retrospective basis. Principally, it requires entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to estimate credit losses. Fortis is assessing the impact of adoption.

MANAGEMENT DISCUSSION AND ANALYSIS 20 June 30, 2018

FINANCIAL INSTRUMENTS

Excluding long-term debt, the consolidated carrying value of the Corporation's financial instruments approximates fair value, reflecting their short-term maturity, normal trade credit terms and/or nature.

As at June 30, 2018, the carrying value of long-term debt, including current portion, was $22,747 million (December 31, 2017 - $21,535 million) compared to an estimated fair value of $24,055 million (December 31, 2017 - $23,481 million).

The fair value of long-term debt is calculated using quoted market prices or, when unavailable, 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, considered Level 2 inputs. Since the Corporation does not intend to settle the long-term debt 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. Fair values reflect estimates based on current market information about the instruments as at the balance sheet dates. 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.

Refer to Note 14 to the Corporation's Interim Financial Statements for further details. There were no material changes in the nature and amount of the Corporations' derivative instruments from those disclosed in the Corporation's 2017 Annual MD&A.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Interim Financial Statements requires management to make estimates and judgments, including those related to regulatory decisions, that affect the reported amounts of, and disclosures related to, assets, liabilities, revenues and expenses. Actual results could differ from estimates.

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

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 three and six months ended June 30, 2017, the correction resulted in $183 million and $245 million, respectively, which was previously reported within Net Repayments/Borrowings under Committed Credit Facilities, now being reported on a gross basis as Borrowings under Committed Credit Facilities of $324 million and $807 million, respectively, and Repayments under Committed Credit Facilities of $507 million and $1,052 million, respectively.

MANAGEMENT DISCUSSION AND ANALYSIS 21 June 30, 2018

The correction of the error for the periods ended March 31, 2017, June 30, 2017 and September 30, 2017 is detailed below.

	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	)

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 amount of consideration agreed to by the related parties. There were no material related-party transactions for the three and six months ended June 30, 2018 and 2017.

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

Inter-company transactions
Periods Ended June 30	Quarter		Year-to-Date
($ millions)	2018	2017	2018	2017
Sale of capacity from Waneta Expansion to FortisBC Electric	4	3	19	19
Sale of energy from Belize Electric Company Limited to BEL	9	7	18	14
Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy	6	5	13	13

As at June 30, 2018, accounts receivable included approximately $10 million due from BEL (December 31, 2017 - $20 million).

The Corporation periodically provides short-term financing to subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements. There were no inter-segment loans outstanding as atJune 30, 2018 and December 31, 2017.

MANAGEMENT DISCUSSION AND ANALYSIS 22 June 30, 2018

SUMMARY OF QUARTERLY RESULTS

Quarterly information has been obtained from the Corporation's Interim Financial Statements and is provided below. 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 ($)	Diluted ($)
June 30, 2018	1,947	240	0.57	0.57
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

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.

June 2018/June 2017: Net earnings attributable to common equity shareholders were $240 million, or $0.57 per common share, for the second quarter of 2018 compared to earnings of $257 million or $0.62 per common share, for the second 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.

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. The increase in earnings 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.

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.

MANAGEMENT DISCUSSION AND ANALYSIS 23 June 30, 2018

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 Transmission Power Project.

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 Program 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 Program 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 the 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 Program, 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 July 30, 2018, the Corporation had issued and outstanding 424.8 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 July 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 June 30, 2018