Exhibit 99.3

Interim Management Discussion and Analysis

For the three and six months ended June 30, 2017

Dated July 27, 2017

TABLE OF CONTENTS
Forward-Looking Information	1	Summary of Consolidated Cash Flows	16
Corporate Overview	3	Contractual Obligations	18
Significant Items	3	Capital Structure	18
Financial Highlights	4	Credit Ratings	19
Segmented Results of Operations	7	Capital Expenditure Program	19
Regulated Electric & Gas Utilities - United States	7	Additional Investment Opportunities	20
ITC	7	Cash Flow Requirements	21
UNS Energy	8	Credit Facilities	22
Central Hudson	9	Off-Balance Sheet Arrangements	22
Regulated Gas Utility - Canadian	9	Business Risk Management	23
FortisBC Energy	9	Changes in Accounting Policies	23
Regulated Electric Utilities - Canadian	10	Future Accounting Pronouncements	23
FortisAlberta	10	Financial Instruments	25
FortisBC Electric	10	Critical Accounting Estimates	26
Eastern Canadian Electric Utilities	11	Related-Party and Inter-Company Transactions	27
Regulated Electric Utilities - Caribbean	11	Summary of Quarterly Results	27
Non-Regulated - Energy Infrastructure	12	Outlook	29
Corporate and Other	12	Outstanding Share Data	29
Regulatory Highlights	13	Condensed Consolidated Interim Financial Statements (Unaudited)	F-1
Consolidated Financial Position	15
Liquidity and Capital Resources	16

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, 2017 and the MD&A and audited consolidated financial statements for the year ended December 31, 2016 included in the Corporation’s 2016 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 nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas (“LNG”) facility and Multi-Value Projects, and additional opportunities including the pipeline expansion to the Woodfibre LNG site, the Lake Erie Connector Project and the Wataynikaneyap Project; the Corporation’s forecast gross consolidated and segmented capital expenditures for 2017 and from 2017 to 2021; statements related to the acquisition of an interest in the Waneta Dam and related transmission assets, including the expected timing and benefits thereof, total expected consideration and adjustments, the expected financing of the acquisition and conditions precedent to the closing, including receipt of certain approvals and consents; the expectation that the Corporation’s 2017 results will continue to benefit from the acquisition of ITC and the impact of Tucson Electric Power Company’s general rate case; the Corporation’s forecast rate base over the five-year period through 2021; the expectation that the Corporation’s significant capital expenditure program will support continuing growth in earnings and dividends; target average

MANAGEMENT DISCUSSION AND ANALYSIS 1 June 30, 2017

annual dividend growth through 2021; 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 and advances from minority investors; 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 2017; the intent of management to refinance certain borrowings under Corporation’s and subsidiaries’ long-term committed credit facilities with long-term permanent financing; the expectation that long-term debt will not be settled prior to maturity; the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation’s consolidated financial statements; and 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.

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 materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the continued tax deferred treatment of earnings from the Corporation’s Caribbean operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital program.

Forward-looking information involves significant risks, uncertainties and assumptions. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. 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 2017 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation’s utilities; uncertainty of the impact a continuation of a low interest rate environment may have on the allowed rate of return on common shareholders’ equity at the Corporation’s regulated utilities; the impact of fluctuations in foreign exchange rates; uncertainty related to proposed tax reform in the United States; risk associated with the impacts of less favourable economic conditions on the Corporation’s results of operations; risk that the expected benefits of the acquisition of ITC may fail to materialize, or may not occur within the time periods anticipated; risk associated with the Corporation’s ability 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 2017 capital expenditures 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 qualified in its entirety by the above cautionary statements and, except as required by law, Fortis disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

MANAGEMENT DISCUSSION AND ANALYSIS 2 June 30, 2017

CORPORATE OVERVIEW

Fortis is a leader in the North American regulated electric and gas utility business, with total assets of approximately $48 billion and fiscal 2016 revenue of $6.8 billion. More than 8,000 employees of the Corporation serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.

Year-to-date June 30, 2017, the Corporation’s electricity systems met a combined peak demand of 31,671 megawatts (“MW”) and its gas distribution systems met a peak day demand of 1,567 terajoules. For additional information on the Corporation’s regulated operations and business segments, refer to Note 1 to the Corporation’s unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2017 and to the “Corporate Overview” section of the 2016 Annual MD&A.

SIGNIFICANT ITEMS

Pending Acquisition of an Interest in Waneta Dam: In May 2017 Fortis entered into an agreement with Teck Resources Limited (“Teck”) to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia for a purchase price of $1.2 billion(the “Waneta Acquisition”), subject to certain adjustments. The Waneta Acquisition will be funded by a combination of cash on hand, debt and equity. The Waneta Dam is a renewable energy facility that is currently operated and maintained by FortisBC Inc. Under the purchase agreement, Teck Metals Ltd. will be granted a 20-year lease, with an option to extend for a further 10 years, to use the two-thirds interest in the Waneta Dam to produce power for its industrial operations in Trail, British Columbia. BC Hydro, the owner of the remaining one-third ownership interest in the Waneta Dam, has a right of first offer. Closing of the Waneta Acquisition will also be subject to certain customary conditions, including receipt of certain approvals and consents from Canadian and U.S. governmental authorities. Provided BC Hydro does not exercise its right to purchase Teck’s two-thirds interest in the Waneta Dam, the transaction is expected to close in the fourth quarter of 2017.

MANAGEMENT DISCUSSION AND ANALYSIS 3 June 30, 2017

FINANCIAL HIGHLIGHTS

Fortis has adopted a strategy of long-term profitable growth with the primary measure of financial performance being earnings per common share. Key financial highlights for the second quarter and year-to-date periods ended June 30, 2017 and 2016 are provided in the following table.

Consolidated Financial Highlights
Periods Ended June 30	Quarter				Year-to-Date
($ millions, except for common share data)	2017	2016	Variance		2017	2016	Variance
Revenue	2,015	1,485	530		4,289	3,257	1,032
Energy Supply Costs	524	488	36		1,278	1,195	83
Operating Expenses	571	454	117		1,153	928	225
Depreciation and Amortization	298	232	66		595	466	129
Other Income, Net	24	9	15		55	25	30
Finance Charges	232	150	82		461	293	168
Income Tax Expense	102	28	74		208	70	138
Net Earnings	312	142	170		649	330	319
Net Earnings Attributable to:
Non-Controlling Interests	38	17	21		65	24	41
Preference Equity Shareholders	17	18	(1	)	33	37	(4	)
Common Equity Shareholders	257	107	150		551	269	282
Net Earnings	312	142	170		649	330	319
Earnings per Common Share
Basic ($)	0.62	0.38	0.24		1.34	0.95	0.39
Diluted ($)	0.62	0.38	0.24		1.34	0.95	0.39
Weighted Average Number of Common Shares   Outstanding (# millions)	416.8	283.7	133.1		411.5	283.0	128.5
Cash Flow from Operating Activities	649	448	201		1,190	931	259

Revenue

The increase in revenue for the quarter was driven by the acquisition of ITC in October 2016, the impact of the rate case settlement and higher electricity sales at UNS Energy, the flow through in customer rates of higher overall energy supply costs, and favourable foreign exchange associated with the translation of US dollar-denominated revenue. Also contributing to the increase in revenue was the reversal of transmission refund accruals of $7 million ($4 million after tax), in the second quarter of 2017, due to the United States Federal Energy Regulatory Commission (“FERC”) ending its investigation into the late-filed transmission service agreements at UNS Energy.

The increase in revenue year to date was driven by the same factors discussed above for the quarter, as well as $18 million ($11 million after tax) in FERC ordered transmission refunds, recognized in the first quarter of 2016, associated with late-filed transmission service agreements at UNS Energy.

Energy Supply Costs

The increase in energy supply costs for the quarter and year to date was mainly due to higher overall commodity costs. Unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs also contributed to the increase for the quarter.

Operating Expenses

The increase in operating expenses for the quarter and year to date was primarily due to the acquisition of ITC and general inflationary and employee-related cost increases. The increase was partially offset by acquisition-related transaction costs of $19 million ($15 million after tax) and $35 million ($29 million after tax) for the second quarter and year-to-date 2016, respectively, associated with the acquisition of ITC. Unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses also contributed to the increase for the quarter.

MANAGEMENT DISCUSSION AND ANALYSIS 4 June 30, 2017

Depreciation and Amortization

The increase in depreciation and amortization for the quarter and year to date was primarily due to the acquisition of ITC and continued investment in energy infrastructure at the Corporation’s other regulated utilities.

Other Income, Net

The increase in other income, net of expenses, for the quarter and year to date was primarily due to the acquisition of ITC. The favourable settlement of matters at UNS Energy pertaining to FERC ordered transmission refunds of $11 million ($7 million after tax), in the first quarter of 2017, also contributed to the year-to-date increase.

Finance Charges

The increase in finance charges for the quarter and year to date was primarily due to the acquisition of ITC, including interest expense on debt issued to complete the financing of the acquisition. The increase was partially offset by acquisition-related transaction costs of $10 million ($7 million after tax) and $14 million ($10 million after tax) for the second quarter and year-to-date 2016, respectively, associated with the acquisition of ITC.

Income Tax Expense

The increase in income tax expense for the quarter and year to date was driven by the acquisition of ITC and higher earnings before taxes. ITC’s higher federal and state jurisdictional tax rates increased the total effective tax rate of Fortis.

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

The increase in net earnings attributable to common equity shareholders for the quarter was driven by earnings of $93 million at ITC, which was 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 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.

The increase in net earnings attributable to common equity shareholders year to date was driven by earnings of $184 million at ITC. The year-to-date increase was also due to: (i) strong performance at UNS Energy, as discussed above for the quarter; (ii) the overall favourable impact of $22 million associated with FERC ordered refunds on late-filed transmission service agreements at UNS Energy; (iii) lower Corporate and Other expenses, primarily due to $39 million in acquisition-related transaction costs associated with ITC recognized year-to-date 2016; and (iv) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives period over period and contribution from the first quarter of 2017. The increase was partially offset by: (i) higher finance charges associated with the acquisitions of ITC and Aitken Creek; (ii) lower contribution from FortisAlberta, mainly due to lower customer rates and higher operating expenses; and (iii) lower contribution from the Caribbean, mainly due to higher finance charges and lower equity income from Belize Electricity Limited (“Belize Electricity”).

Earnings per common share for the quarter and year to date were $0.24 and $0.39 higher, respectively, compared to the same periods in 2016. The impact of the above-noted items on net earnings attributable to common equity shareholders were partially offset by an increase in the weighted average number of common shares outstanding associated with the financing of the acquisition of ITC and the Corporation’s dividend reinvestment and share plans.

MANAGEMENT DISCUSSION AND ANALYSIS 5 June 30, 2017

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

Fortis supplements the use of US GAAP financial measures with non-US GAAP financial measures, including adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share. The Corporation refers to these measures as non-US GAAP financial measures since they are not required by, or presented in accordance with, US GAAP. 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 underlying operations of the business. For the quarter and year-to-date periods ended June 30, 2017 and 2016, the Corporation adjusted net earnings attributable to common equity shareholders for: (i) acquisition-related transactions costs; and (ii) cumulative adjustments for regulatory decisions pertaining to prior periods considered to be outside the normal course of business for the periods presented. The Corporation no longer excludes mark-to-market adjustments related to derivative instruments at Aitken Creek, which occur in the normal course of Aitken Creek’s business, in its calculation of adjusted net earnings attributable to common equity shareholders as comparative information is now presented in reported net earnings.

The adjusting items described above 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 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.

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

Non-US GAAP Reconciliation
Periods Ended June 30	Quarter					Year-to-Date
($ millions, except for common share data)	2017		2016	Variance		2017		2016	Variance
Net Earnings Attributable to Common Equity Shareholders	257		107	150		551		269	282
Adjusting Items:
UNS Energy - Settlement of FERC ordered transmission refunds	(4	)	—	(4	)	(11	)	—	(11	)
FERC ordered transmission refunds	—		—	—		—		11	(11	)
Corporate and Other -
Acquisition-related transaction costs	—		22	(22	)	—		39	(39	)
Adjusted Net Earnings Attributable to Common Equity Shareholders	253		129	124		540		319	221
Adjusted Basic Earnings Per Common Share ($)	0.61		0.45	0.16		1.31		1.13	0.18
Weighted Average Number of Common Shares Outstanding(# millions)	416.8		283.7	133.1		411.5		283.0	128.5

MANAGEMENT DISCUSSION AND ANALYSIS 6 June 30, 2017

SEGMENTED RESULTS OF OPERATIONS

Segmented Net Earnings Attributable to Common Equity Shareholders
Periods Ended June 30	Quarter						Year-to-Date
($ millions)	2017		2016		Variance		2017		2016		Variance
Regulated Electric & Gas Utilities - United States
ITC	93		—		93		184		—		184
UNS Energy	89		56		33		130		68		62
Central Hudson	10		12		(2	)	33		36		(3	)
Regulated Gas Utility - Canadian
FortisBC Energy	6		8		(2	)	103		100		3
Regulated Electric Utilities  - Canadian
FortisAlberta	31		30		1		56		61		(5	)
FortisBC Electric	16		15		1		31		30		1
Eastern Canadian	18		16		2		36		34		2
Regulated Electric Utilities - Caribbean	9		11		(2	)	17		21		(4	)
Non-Regulated - Energy Infrastructure	25		19		6		48		30		18
Corporate and Other	(40	)	(60	)	20		(87	)	(111	)	24
Net Earnings Attributable to Common Equity Shareholders	257		107		150		551		269		282

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

REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES

ITC

Financial Highlights (1)
Periods Ended June 30, 2017	Quarter	Year-to-Date
Average US:CAD Exchange Rate (2)	1.34	1.33
Revenue ($ millions)	408	803
Earnings ($ millions)	93	184

⁽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 and Earnings

ITC was acquired by Fortis in October 2016 and, therefore, there are no revenue and earnings reported for the comparative periods.

There were no transactions or events, outside the normal course of operations, that materially impacted revenue or earnings for the quarter and year to date.

MANAGEMENT DISCUSSION AND ANALYSIS 7 June 30, 2017

UNS ENERGY ⁽¹⁾ 

Financial Highlights	Quarter			Year-to-Date
Periods Ended June 30	2017	2016	Variance	2017	2016	Variance
Average US:CAD Exchange Rate (2)	1.34	1.29	0.05	1.33	1.33	—
Electricity Sales (gigawatt hours (“GWh”))	3,618	3,608	10	7,002	6,652	350
Gas Volumes (petajoules (“PJ”))	3	3	—	8	8	—
Revenue ($ millions)	552	490	62	1,010	930	80
Earnings ($ millions)	89	56	33	130	68	62

⁽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 was primarily due to higher residential and commercialretail electricity sales due to warmer temperatures that increased air conditioning load. The increase was partially offset by lower short-term wholesale sales due to unplanned generation outages and lower long-term wholesale sales due to the expiration of a large contract as compared to the same period in 2016. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings.

The increase in electricity sales year to date was primarily due to the same factors discussed above for the quarter and higher short-term wholesale sales in the first quarter of 2017 as a result of more favourable commodity prices.

Gas volumes were comparable with the same periods in 2016.

Revenue

The increase in revenue for the quarter was primarily due to the impact of the rate settlement effective February 27, 2017, higher retail electricity sales, as discussed above, and approximately $22 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. Also contributing to the increase was the reversal of $7 million (US$5 million), or $4 million (US$3 million) after-tax, in transmission refund accruals due to FERC ending its investigation into TEP’s late-filed transmission agreements in the second quarter of 2017. The increase was partially offset by lower revenue related to a decrease in cost recovery rates, which has no impact on earnings.

The increase in revenue year to date was due to the same factors discussed above for the quarter, as well as approximately $18 million (US$13 million), or $11 million (US$8 million) after tax, in FERC ordered transmission refunds in the first quarter of 2016 and higher short-term wholesale sales. Also contributing to the increase year to date was approximately $5 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue.

Earnings

The increase in earnings for the quarter was primarily due to the impact of the rate case settlement, higher retail electricity sales, and the reversal of $4 million (US$3 million) in transmission refund accruals, all discussed above. Also contributing to the increase was more favourably priced long-term wholesale contracts and approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, partially offset by higher deferred income taxes.

The increase in earnings year to date was due to the same factors discussed above for the quarter, as well as approximately $11 million (US$8 million) in FERC ordered transmission refunds in the first quarter of 2016 and approximately $7 million (US$5 million) related to the favourable settlement of matters pertaining to FERC ordered transmission refunds in the first quarter of 2017. Also contributing to the increase was approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings.

MANAGEMENT DISCUSSION AND ANALYSIS 8 June 30, 2017

CENTRAL HUDSON

Financial Highlights	Quarter				Year-to-Date
Periods Ended June 30	2017	2016	Variance		2017	2016	Variance
Average US:CAD Exchange Rate (1)	1.34	1.29	0.05		1.33	1.33	—
Electricity Sales (GWh)	1,134	1,149	(15	)	2,378	2,404	(26	)
Gas Volumes (PJ)	4	4	—		13	13	—
Revenue ($ millions)	206	185	21		464	434	30
Earnings ($ millions)	10	12	(2	)	33	36	(3	)

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

Electricity Sales & Gas Volumes

The decrease in electricity sales for the quarter and year to date was primarily due to lower average consumption in the second quarter of 2017 as a result of cooler temperatures. Also contributing to the year-to-date decrease was lower average consumption in the first quarter of 2017, as a result of warmer temperatures. Gas volumes were comparable with the same periods in 2016.

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 annual revenue and earnings.

Revenue

The increase in revenue for the quarter and year to date was due to higher delivery revenue from increases in base electricity rates effective July 1, 2016 and the recovery from customers of higher commodity costs. Also contributing to the increase for the quarter was favourable foreign exchange of approximately $8 million associated with the translation of US dollar-denominated revenue.

Earnings

The decrease in earnings for the quarter and year to date was primarily due to the timing of unbilled revenue, which is not subject to the operation of the decoupling mechanism. Also contributing to the decrease was higher operating costs, partially offset by increases in delivery revenue. Higher-than-expected storm restoration costs incurred in the first quarter of 2017 also contributed to the decrease year to date.

REGULATED GAS UTILITY - CANADIAN

FORTISBC ENERGY

Financial Highlights	Quarter				Year-to-Date
Periods Ended June 30	2017	2016	Variance		2017	2016	Variance
Gas Volumes (PJ)	42	34	8		125	102	23
Revenue ($ millions)	227	201	26		676	607	69
Earnings ($ millions)	6	8	(2	)	103	100	3

Gas Volumes

The increase in gas volumes for the quarter and year to date was primarily due to growth in the number of customers and higher average consumption by residential and commercial customers as a result of colder temperatures. Also contributing to the increase was higher volumes for transportation customers due to additional customers switching to natural gas compared to alternative fuel sources.

Revenue

The increase in revenue for the quarter and year to date was primarily due to higher gas volumes and a higher commodity cost of natural gas charged to customers, partially offset by an increase in flow-through adjustments owing to customers.

Earnings

The decrease in earnings for the quarter was primarily due to the timing of quarterly revenue and operating expenses compared to the same period in 2016 and higher operating expenses, partially offset by higher allowance for funds used during construction (“AFUDC”).

MANAGEMENT DISCUSSION AND ANALYSIS 9 June 30, 2017

The increase in earnings year to date was primarily due to higher AFUDC and the timing of quarterly revenue and operating expenses as compared to the same period in 2016, 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 materially affect earnings.

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

Financial Highlights	Quarter			Year-to-Date
Periods Ended June 30	2017	2016	Variance	2017	2016	Variance
Energy Deliveries (GWh)	3,983	3,799	184	8,534	8,355	179
Revenue ($ millions)	148	144	4	295	286	9
Earnings ($ millions)	31	30	1	56	61	(5	)

Energy Deliveries

The increase in energy deliveries for the quarter and year to date was primarily due to higher average consumption by oil and gas customers in the second quarter of 2017 and growth in the number of residential and commercial customers. The increase year to date was partially offset by lower oil and gas activity in the first quarter of 2017.

Revenue

The increase in revenue for the quarter and year to date was primarily due to an increase in capital tracker revenue. Higher revenue related to the flow through of costs to customers and higher energy deliveries, due to customer growth and higher average consumption, also contributed to the increase, partially offset by a decrease in customer rates effective January 1, 2017 based on a combined inflation and productivity factor of negative 1.9%.

Earnings

The increase in earnings for the quarter was primarily due to an increase in capital tracker revenue and customer growth, partially offset by higher operating costs, mainly due to timing, and lower customer rates, as discussed above.

The decrease in earnings year to date was mainly due to higher operating expenses and timing differences related to certain operating expenses. Lower customer rates, partially offset by an increase in capital tracker revenue and customer growth, also contributed to the decrease year to date.

FORTISBC ELECTRIC ⁽¹⁾ 

Financial Highlights	Quarter			Year-to-Date
Periods Ended June 30	2017	2016	Variance	2017	2016	Variance
Electricity Sales (GWh)	712	684	28	1,657	1,535	122
Revenue ($ millions)	85	83	2	198	187	11
Earnings ($ millions)	16	15	1	31	30	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 increase in electricity sales for the quarter and year to date was primarily due to higher average consumption as a result of favourable weather conditions.

MANAGEMENT DISCUSSION AND ANALYSIS 10 June 30, 2017

Revenue

The increase in revenue for the quarter and year to date was primarily due to higher electricity sales and an increase in base electricity rates effective January 1, 2017, partially offset by higher flow-through adjustments owing to customers.

Earnings

The increase in earnings for the quarter and year to date was due to lower operating expenses.

Variances from regulated forecasts used to set rates for electricity revenue and power purchase 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.

EASTERN CANADIAN ELECTRIC UTILITIES ⁽¹⁾ 

Financial Highlights	Quarter			Year-to-Date
Periods Ended June 30	2017	2016	Variance	2017	2016	Variance
Electricity Sales (GWh)	1,934	1,921	13	4,671	4,627	44
Revenue ($ millions)	251	245	6	583	574	9
Earnings ($ millions)	18	16	2	36	34	2

⁽¹⁾  Comprised of Newfoundland Power Inc. (“Newfoundland Power”), Maritime Electric Company, Limited and FortisOntario Inc. (“FortisOntario”).

Electricity Sales

The increase in electricity sales for the quarter and year to date was due to higher average consumption and growth in the number of customers.

Revenue

The increase in revenue for the quarter and year to date was primarily due to higher electricity sales and an increase in customer electricity rates.

Earnings

The increase in earnings for the quarter and year to date was due to lower-than-anticipated finance costs, an increase in customer electricity rates, and higher electricity sales. The recognition of the cumulative impact of a decrease in the allowed return on equity (“ROE”) at Newfoundland Power, effective January 1, 2016, in the second quarter of 2016 also had a favourable impact on earnings quarter over quarter.

REGULATED ELECTRIC UTILITIES - CARIBBEAN ⁽¹⁾ 

Financial Highlights	Quarter				Year-to-Date
Periods Ended June 30	2017	2016	Variance		2017	2016	Variance
Average US:CAD Exchange Rate (2)	1.34	1.29	0.05		1.33	1.33	—
Electricity Sales (GWh)	220	215	5		411	405	6
Revenue ($ millions)	80	71	9		150	146	4
Earnings ($ millions)	9	11	(2	)	17	21	(4	)

⁽¹⁾  Comprised of Caribbean Utilities Company, Ltd. (“Caribbean Utilities”), in which Fortis holds an approximate 60% controlling interest, and two wholly owned utilities, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively “Fortis Turks and Caicos”). Also includes the Corporation’s 33% equity investment in 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.

Electricity Sales

Electricity sales for the quarter and year to date were comparable with the same periods in 2016.

MANAGEMENT DISCUSSION AND ANALYSIS 11 June 30, 2017

Revenue

The increase in revenue for the quarter and year to date was mainly due to the flow through in customer electricity rates of higher fuel costs. Also contributing to the increase for the quarter is approximately $3 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue.

Earnings

The decrease in earnings for the quarter and year to date was due to higher finance costs, primarily due to lower capitalized interest, partially offset by lower operating costs. Also contributing to the decrease year to date was lower equity income from Belize Electricity.

NON-REGULATED - ENERGY INFRASTRUCTURE ⁽¹⁾ 

Financial Highlights	Quarter				Year-to-Date
Periods Ended June 30	2017	2016	Variance		2017	2016	Variance
Energy Sales (GWh)	519	516	3		601	605	(4	)
Revenue ($ millions)	59	67	(8	)	115	95	20
Earnings ($ millions)	25	19	6		48	30	18

⁽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

Energy sales for the quarter and year to date were comparable with the same periods in 2016.

Revenue

The decrease in revenue for the quarter was primarily due to Aitken Creek. The increase in revenue year to date was driven by the acquisition of Aitken Creek in April 2016.

Earnings

The increase in earnings for the quarter and year to date was primarily due to higher earnings from Aitken Creek associated with the unrealized gains on the mark-to-market of derivatives period over period. Earnings from Aitken Creek in the first quarter of 2017 also contributed to the year-to-date increase.

CORPORATE AND OTHER ⁽¹⁾ 

Financial Highlights
Periods Ended June 30	Quarter						Year-to-date
($ millions)	2017		2016		Variance		2017		2016		Variance
Revenue	1		3		(2	)	1		5		(4	)
Operating Expenses	10		28		(18	)	22		53		(31	)
Depreciation and Amortization	1		1		—		1		2		(1	)
Other Income, Net	2		1		1		2		4		(2	)
Finance Charges	47		34		13		97		62		35
Income Tax Recovery	(32	)	(17	)	(15	)	(63	)	(34	)	(29	)
	(23	)	(42	)	19		(54	)	(74	)	20
Preference Share Dividends	17		18		(1	)	33		37		(4	)
Corporate and Other	(40	)	(60	)	20		(87	)	(111	)	24

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

The decrease in Corporate and Other for the quarter and year to date was primarily due to lower operating expenses, a higher income tax recovery and lower preference share dividends, partially offset by an increase in finance charges.

MANAGEMENT DISCUSSION AND ANALYSIS 12 June 30, 2017

The decrease in operating expenses for the quarter and year to date was primarily due to acquisition-related transaction costs, including investment banking, legal, consulting and other fees, associated with the acquisition of ITC totalling approximately $19 million ($15 million after tax) and $35 million ($29 million after tax) for the second quarter and year-to-date 2016, respectively. The decrease was partially offset by higher compensation-related expenditures, general inflationary increases and ancillary expenses to support the acquisition of ITC and the Corporation’s listing on the New York Stock Exchange.

The increase in finance charges for the quarter and year to date was mainly due to the acquisition of ITC in October 2016, partially offset by fees associated with the Corporation’s acquisition credit facilities totalling approximately $10 million ($7 million after tax) and $14 million ($10 million after tax) for the second quarter and year-to-date 2016, respectively. Finance charges associated with the acquisition of Aitken Creek in April 2016 also contributed to the year-to-date increase.

The higher income tax recovery for the quarter and year to date was mainly due to the increase in finance charges, partially offset by lower acquisition-related transaction costs.

The decrease in preference share dividends for the quarter and year to date was due to the redemption of First Preference Shares, Series E in September 2016.

REGULATORY HIGHLIGHTS

The nature of regulation associated with each of the Corporation’s regulated electric and gas utilities is generally consistent with that disclosed in the 2016 Annual MD&A. The following summarizes the significant ongoing regulatory proceedings and significant decisions and applications for the Corporation’s regulated utilities in the first half of 2017.

ITC

ROE Complaints

Since 2013 two third-party complaints were filed with FERC requesting that FERC find the Midcontinent Independent System Operator (“MISO”) regional base ROE for all MISO transmission owners, including some of ITC’s operating subsidiaries, for the periods November 2013 through February 2015 (the “Initial Refund Period” or “Initial Complaint”) and February 2015 through May 2016 (the “Second Refund Period” or “Second Complaint”) to no longer be just and reasonable. In September 2016 FERC issued an order affirming the presiding Administrative Law Judge’s (“ALJ”) initial decision for the Initial Refund Period and setting the base ROE for the Initial Refund Period at 10.32%, with a maximum ROE of 11.35%. Additionally, the rates established by the September 2016 order will be used prospectively from the date of the order until a new approved rate is established for the Second Refund Period. FERC’s September 2016 order regarding the Initial Complaint is currently under appeal by the MISO transmission owners. In June 2016 the presiding ALJ issued an initial decision for the Second Refund Period, which recommended a base ROE of 9.70%, with a maximum ROE of 10.68%, which is a recommendation to FERC.

The total estimated refund for the Initial Complaint was $158 million (US$118 million), including interest, as at December 31, 2016. The true-up of the net refund was substantially finalized in the second quarter of 2017 and paid during the first half of 2017. The total amount of the refund, including interest and the associated true-up, for the Initial Complaint was not materially different from the amount recorded as at December 31, 2016.

An order has not yet been issued by FERC in connection with the Second Complaint; however, it is expected that FERC will establish a new base ROE and range of reasonableness to calculate the refund liability for the Second Refund Period and future ROEs for ITC’s operating subsidiaries. As at June 30, 2017, the estimated range of refunds for the Second Refund Period was between US$104 million to US$142 million and ITC has recognized an aggregated estimated regulatory liability of $184 million (US$142 million).

The estimated regulatory liabilities were accrued by ITC before its acquisition by Fortis. There is uncertainty regarding the final outcome of the Initial and Second Complaints and the timing of the completion of these matters. This is due, in part, to a recent court decision requiring FERC to further justify the methodology used to establish new ROEs. It is possible that the outcome of these matters could differ materially from the estimated range of refunds.

MANAGEMENT DISCUSSION AND ANALYSIS 13 June 30, 2017

UNS Energy

General Rate Application

In February 2017 the Arizona Corporation Commission issued a rate order for new rates that took effect February 27, 2017 (“2017 Rate Order”). Provisions of the 2017 Rate Order include: (i) an increase in non-fuel base revenue of $108 million (US$81.5 million), including $20 million (US$15 million) of operating costs related to the 50.5% undivided interest in Unit 1 of Springerville Generating Station purchased by TEP in September 2016; (ii) a 7.04% return on original cost rate base, including a cost of equity of 9.75% and an embedded cost of long-term debt of 4.32%; (iii) a common equity component of capital structure of approximately 50%; and (iv) the adoption of proposed depreciation rates which reflect a reduction in the depreciable life for Unit 1 of San Juan Generating Station. Certain aspects of the general rate application, including net metering and rate design for new distributed generation customers, have been deferred to a second phase of TEP’s rate case proceeding, which is currently expected to be completed in the first quarter of 2018. TEP cannot predict the outcome of this proceeding.

FERC Order

In May 2017 FERC informed TEP that no further enforcement actions were necessary regarding TEP’s transmission refunds and closed the related investigation. As a result, TEP reversed the remaining $7 million (US$5 million) provision related to potential time-value refunds.

Central Hudson

General Rate Application

In July 2017 Central Hudson will file a rate case with the New York Public Service Commission (“PSC”) requesting an increase in electric and nature gas rates. Included in the rate case will be a request to increase the allowed ROE to 9.5% from 9.0% and the equity component of the capital structure to 50% from 48%. An order from the PSC is expected in June 2018 with the new rates to become effective no later than July 1, 2018.

FortisAlberta

Capital Tracker Applications

In January 2017 the Alberta Utilities Commission (“AUC”) issued its decision on FortisAlberta’s 2015 True-Up Application approving the 2015 capital tracker revenue as filed, pending the approval of the Company’s Compliance Filing, filed in February 2017. The AUC approved the Compliance Filing in May 2017. In June 2017 the Company filed its 2016 True-Up Application for 2016 capital tracker revenue and a decision is expected in the first quarter of 2018. There was no material adjustment to capital tracker revenue resulting from this application.

Generic Cost of Capital

In July 2017 the AUC established a process to determine an ROE and capital structure for 2018, 2019 and 2020. The process will commence in October 2017, with an oral hearing in March 2018. A decision is expected in the third quarter of 2018.

Next Generation Performance-Based Rate-Setting Proceeding

In December 2016 the AUC issued its decision outlining the manner in which distribution rates will be determined during the second performance-based rate-setting (“PBR”) term, being the five-year period from 2018 through 2022. FortisAlberta filed a rebasing application in April 2017 to establish the going-in revenue requirement for the second PBR term, which will be used to determine the going-in rates upon which the PBR formula will be applied to establish distribution rates for 2018. A decision on this application is expected in the first quarter of 2018.

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	Second MISO Base ROE Complaint	Not applicable	To be determined
Central Hudson	General Rate Application	July 2017	July 2018

MANAGEMENT DISCUSSION AND ANALYSIS 14 June 30, 2017

CONSOLIDATED FINANCIAL POSITION

The following table outlines the significant changes in the consolidated balance sheets between June 30,2017 and December 31, 2016.

Significant Changes in the Consolidated Balance Sheets between June 30, 2017 and December 31, 2016
Balance Sheet Account	Increase/ (Decrease) ($ millions)	Explanation
Capital assets, net	82	The increase was mainly due to capital expenditures, primarily at ITC, UNS Energy, Central Hudson and FortisAlberta. The increase was partially offset by the reclassification of a reserve from regulatory liabilities, the impact of foreign exchange associated with the translation of US dollar-denominated capital assets and depreciation.
Goodwill	(373)	The decrease was due to the impact of foreign exchange associated with the translation of US dollar-denominated goodwill.
Short-term borrowings	(587)	The decrease was mainly due to repayment of the Corporation’s equity bridge credit facility, which was used to finance a portion of the acquisition of ITC, and the repayment of short-term borrowings at FortisBC Energy.
Accounts payable and other current liabilities	(167)	The decrease was primarily due to the timing of the declaration of the Corporation’s common share dividends and lower amounts owing for energy supply costs at FortisBC Energy, Newfoundland Power and Central Hudson associated with the seasonality of operations, partially offset by an increase in capital accruals at ITC and FortisAlberta.
Regulatory liabilities - current and   long-term	(289)	The decrease was primarily due to a reduction in regulatory liabilities at ITC associated with the payment of the Initial Refund Period ROE complaint, the reclassification of a reserve to capital assets and the impact of foreign exchange on the translation of US dollar-denominated regulatory liabilities.
Long-term debt (including current portion)	44	The increase was mainly due to the issuance of term loan credit agreements and first mortgage bonds by ITC and debt issued at other of the regulated utilities. The increase was partially offset by regularly scheduled debt repayments and the impact of foreign exchange associated with the translation of US dollar-denominated debt.
Deferred income tax liabilities	105	The increase was mainly due to timing differences associated with capital expenditures at the regulated utilities, partially offset by taxable losses at the Corporation and the impact of foreign exchange on the translation of US dollar-denominated deferred income tax liabilities.
Shareholders’ equity (before   non-controlling interests)	717	The increase was primarily due to: (i) the issuance of $500 million of common shares; (ii) net earnings attributable to common shareholders for the six months ended June 30, 2017, 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. The increase was partially offset by a decrease 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.

MANAGEMENT DISCUSSION AND ANALYSIS 15 June 30, 2017

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CONSOLIDATED CASH FLOWS

The table below outlines the Corporation’s sources and uses of cash for the second quarter and year-to-date periods ended June 30, 2017 compared to the same periods in 2016, 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)	2017		2016		Variance		2017		2016		Variance
Cash, Beginning of Period	298		232		66		269		242		27
Cash Provided by (Used in):
Operating Activities	649		448		201		1,190		931		259
Investing Activities	(741	)	(762	)	21		(1,460	)	(1,175	)	(285	)
Financing Activities	27		380		(353	)	235		314		(79	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	(2	)	(2	)	—		(3	)	(16	)	13
Cash, End of Period	231		296		(65	)	231		296		(65	)

Operating Activities: Cash flow provided by operating activities was $201 million higher quarter over quarter and $259 million higher year to date compared to the same period in 2016. The increase was primarily due to higher cash earnings, driven by ITC and UNS Energy. The year-to-date increase was partially offset by timing differences in working capital, mainly due to the payment of the Initial Refund Period ROE complaint at ITC in the first quarter of 2017.

Investing Activities: Cash used in investing activities was $21 million lower quarter over quarter. The decrease was primarily due to the acquisition of Aitken Creek in the second quarter of 2016 for a net cash purchase price of $318 million, largely offset by an increase in capital expenditures. The increase in capital expenditures was driven by capital spending at ITC along with higher capital spending at most of the Corporation’s regulated utilities.

Cash used in investing activities was $285 million higher year to date compared to the same period in 2016. The increase was primarily due to an increase in capital expenditures, partially offset by the acquisition of Aitken Creek, as discussed above for the quarter.

Financing Activities: Cash provided by financing activities was $353 million lower quarter over quarter. The decrease was primarily due to higher net repayments under committed credit facilities, partially offset by lower net repayments of short-term borrowings at FortisBC Energy.

Cash provided by financing activities was $79 million lower year to date compared to the same period in 2016. The decrease was primarily due to higher net repayments under both committed credit facilities and short-term borrowings. The decrease was partially offset by higher proceeds from the issuance of long-term debt, largely at ITC.

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, repayments of long-term debt and capital lease and finance obligations, and net (repayments) borrowings under committed credit facilities for the quarter and year to date compared to the same periods last year are summarized in the following tables.

MANAGEMENT DISCUSSION AND ANALYSIS 16 June 30, 2017

Proceeds from Long-Term Debt, Net of Issue Costs
Periods Ended June 30	Quarter				Year-to-Date
($ millions)	2017	2016	Variance		2017	2016	Variance
ITC (1)	267	—	267		601	—	601
Central Hudson (2)	—	29	(29	)	—	29	(29	)
FortisBC Energy (3)	—	298	(298	)	—	298	(298	)
Eastern Canadian (4)	75	—	75		75	—	75
Caribbean Electric (5)(6)	26	29	(3	)	80	29	51
Total	368	356	12		756	356	400

⁽¹⁾  In March 2017 ITC entered into 1-year and 2-year unsecured term loan credit agreements at floating interest rates of a one-month LIBOR plus a spread of 0.90% and 0.65%, respectively. As at June 30, 2017, borrowings under the term loan credit agreements were US$200 million ($268 million) and US$50 million ($67 million), respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes. In April 2017 ITC issued 30-year US$200 million ($268 million) 4.16% secured first mortgage bonds. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.

⁽²⁾  In June 2016 Central Hudson issued 4-year US$24 million ($29 million) 2.16% unsecured notes. The net proceeds were used to finance capital expenditures and for general corporate purposes.

⁽³⁾  In April 2016 FortisBC Energy issued $300 million of unsecured debentures in a dual tranche of 10-year $150 million unsecured debentures at 2.58% and 30-year $150 million unsecured debentures at 3.67%. The net proceeds were used to repay short-term borrowings and to finance capital expenditures.

⁽⁴⁾  In June 2017 Newfoundland Power issued 40-year $75 million3.82% first mortgage sinking fund bonds. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.

⁽⁵⁾  In March and May 2017, Caribbean Utilities issued US$60 million ($80 million) of unsecured notes in a dual tranche of 15-year US$40 million ($54 million) at 3.90% and 30‑year US$20 million ($26 million) at 4.64%, respectively. The net proceeds from the issuances were used to finance capital expenditures and repay short-term borrowings.

⁽⁶⁾  In May 2016 Fortis Turks and Caicos issued 15-year US$23 million ($29 million) 5.14% unsecured notes. The net proceeds were used to finance capital expenditures.

Repayments of Long-Term Debt and Capital Lease and Finance Obligations
Periods Ended June 30	Quarter					Year-to-Date
($ millions)	2017		2016		Variance	2017		2016		Variance
UNS Energy	(6	)	(6	)	—	(19	)	(19	)	—
Central Hudson	(1	)	(10	)	9	(1	)	(10	)	9
FortisBC Energy	(1	)	(7	)	6	(3	)	(9	)	6
FortisBC Electric	—		—		—	(1	)	(25	)	24
Eastern Canadian	—		(30	)	30	—		(30	)	30
Caribbean Electric	(11	)	(16	)	5	(11	)	(16	)	5
Total	(19	)	(69	)	50	(35	)	(109	)	74

Net (Repayments) Borrowings Under Committed Credit Facilities
Periods Ended June 30	Quarter					Year-to-Date
($ millions)	2017		2016	Variance		2017		2016	Variance
ITC	(219	)	—	(219	)	(242	)	—	(242	)
UNS Energy	26		22	4		40		68	(28	)
FortisAlberta	60		45	15		95		62	33
Eastern Canadian	(80	)	24	(104	)	(52	)	46	(98	)
Corporate (1)	(28	)	330	(358	)	(17	)	337	(354	)
Total	(241	)	421	(662	)	(176	)	513	(689	)

⁽¹⁾  Borrowings under the Corporation’s committed credit facility in the second quarter of 2016 were primarily used to finance the acquisition of Aitken Creek.

MANAGEMENT DISCUSSION AND ANALYSIS 17 June 30, 2017

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 2017 were $104 million, net of $63 million of dividends reinvested, compared to $70 million, net of $36 million of dividends reinvested, paid in the second quarter of 2016. Common share dividends paid year-to-date2017 were $202 million, net of $125 million of dividends reinvested, compared to $147 million, net of $65 million of dividends reinvested, paid year-to-date2016. The dividend paid per common share for each of the first and second quarters of 2017 was $0.40 compared to $0.375 for each of the first and second quarters of 2016. The weighted average number of common shares outstanding for the second quarter and year-to-date2017 was 416.8 million and 411.5 million, respectively, compared to 283.7 million and 283.0 million for the same periods in 2016.

CONTRACTUAL OBLIGATIONS

There were no material changes in the nature and amount of the Corporation’s contractual obligations during the three and six months ended June 30, 2017 from those disclosed in the 2016 Annual MD&A.

CAPITAL STRUCTURE

The Corporation’s principal businesses of regulated electric and gas utilities require 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, and advances from minority investors. 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 in the following table.

Capital Structure	As at
	June 30, 2017		December 31, 2016
	($ millions)	(%)	($ millions)	(%)
Total debt and capital lease and finance obligations (net of cash) (1)	21,959	58.9	22,490	60.6
Preference shares	1,623	4.4	1,623	4.4
Common shareholders’ equity	13,691	36.7	12,974	35.0
Total	37,273	100.0	37,087	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, 2017 was 56.1% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 35.0% common shareholders’ equity and 4.7% non-controlling interests (December 31, 2016 - 57.8% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 33.3% common shareholders’ equity and 4.7% non-controlling interests). The change in the Corporation’s capital structure was mainly due to an increase in common equity at the Corporation due to the issuance of $500 million of common shares in March 2017, used to repay short-term borrowings.

MANAGEMENT DISCUSSION AND ANALYSIS 18 June 30, 2017

CREDIT RATINGS

The Corporation’s credit ratings are as follows.

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

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 May 2017 S&P and DBRS affirmed the Corporation’s long-term corporate and unsecured debt credit ratings as presented above.

CAPITAL EXPENDITURE PROGRAM

A breakdown of the $1,428 million in gross consolidated capital expenditures by segment year-to-date 2017 is provided in the following table.

Gross Consolidated Capital Expenditures (1)
Year-to-Date June 30, 2017
($ millions)
	Regulated
									Total
		UNS	Central	FortisBC	Fortis	FortisBC	Eastern	Caribbean	Regulated	Non-
	ITC	Energy	Hudson	Energy	Alberta	Electric	Canadian	Electric	Utilities	Regulated (2)	Total
Total	512	248	103	197	195	46	63	57	1,421	7	1,428

⁽¹⁾  Represents cash payments to construct capital and intangible assets, as reflected on the condensed consolidated interim statement of cash flows. Excludes the non-cash equity component of AFUDC.

⁽²⁾  Includes Energy Infrastructure and Corporate and Other segments

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

Gross consolidated capital expenditures for 2017 are forecast to be approximately $3.1 billion. 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 2016 Annual MD&A, with the exception of those noted below for UNS Energy and FortisBC Energy.

Capital expenditures at UNS Energy are expected to be higher than the original forecast, primarily due to capital spending related to investment in natural gas-fired facilities and distribution modernization projects. At FortisBC Energy capital expenditures are expected to be higher than the original forecast, primarily due to advancing the capital spend for the Lower Mainland System Upgrade to 2017 from 2018.

At ITC approximately $228 million (US$176 million) was invested in the Multi-Value Projects (“MVPs”) from the date of acquisition and an additional $135 million (US$102 million) is expected to be spent in the second half of 2017. The MVPs consist of four regional electric transmission projects that have been identified by MISO to address system capacity needs and reliability in various states.

MANAGEMENT DISCUSSION AND ANALYSIS 19 June 30, 2017

The Tilbury liquefied natural gas (“LNG”) facility expansion (“Tilbury LNG Facility Expansion”) by FortisBC Energy in British Columbia is nearing completion. Approximately $439 million, including AFUDC and development costs, has been invested to the end of the second quarter of 2017. The total cost of the project scope that is currently under construction is estimated at approximately $470 million, including approximately $70 million of AFUDC and development costs, which could be impacted depending on the date the project is considered in service for rate-making purposes. The facility includes a second LNG tank and a new liquefier, both expected to be in service in the third quarter of 2017. Key activities during the first half of 2017 included commissioning of the LNG storage tank and the continued installation of the liquefaction process area piping insulation, electrical and instrumentation cable and terminations.

Beginning with the first Order in Council (“OIC”) in 2013, the Government of British Columbia has continued to support the Tilbury LNG Facility Expansion. The most recent OIC issued in March 2017 further facilitates the expansion of the facility by increasing the capital cost limit to $425 million from $400 million, before AFUDC and development costs. This latest OIC also provides greater discretion around when certain projects approved pursuant to previous OICs, including the Tilbury LNG Facility Expansion, could be added to rate base.

Over the five-year period 2017 through 2021, gross consolidated capital expenditures are expected to be approximately $13 billion. The breakdown of the capital spending has not changed materially from that disclosed in the 2016 Annual MD&A.

ADDITIONAL INVESTMENT OPPORTUNITIES

In addition to the Corporation’s base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. These additional investment opportunities, as discussed below, are not included in the Corporation’s base capital expenditure forecast.

The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including a pipeline expansion to the proposed Woodfibre LNG site and a further expansion of Tilbury.

FortisBC Energy’s potential pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG export facility. FortisBC Energy received an OIC from the Government of British Columbia effectively exempting this project from further regulatory approval by the British Columbia Utilities Commission. Woodfibre LNG has obtained an export license from the National Energy Board (“NEB”), which was recently extended from 25 to 40 years, and received environmental assessment approvals from the Squamish First Nation, the British Columbia Environmental Assessment Office, and the Canadian Environmental Assessment Agency. FortisBC Energy also received environmental assessment approval from the Squamish First Nation and provincial environmental assessment approval in 2016. The potential pipeline expansion was initially estimated at a total project cost, before any customer contribution, of up to $600 million; however, this estimate will be updated for final scoping, detailed construction estimates and scheduling. In November 2016 Woodfibre LNG announced the approval from its parent company, Pacific Oil & Gas Limited, which is part of the Singapore-based RGE group of companies, of the funds necessary to complete the project. This project may move forward pending additional approvals and a final investment decision by Woodfibre LNG but is not expected to be in service any earlier than 2020.

The Corporation’s Tilbury LNG facility 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.

In January 2017 ITC received approval of a Presidential Permit from the U.S. Department of Energy for the Lake Erie Connector transmission line, which is a required approval for international border-crossing projects. Also in January, ITC received a report from Canada’s NEB recommending the issuance of a Certificate of Public Convenience and Necessity (“CPCN”) with prescribed conditions for the transmission line. In May 2017 ITC completed the major permit process in Pennsylvania upon receipt of two required permits from the Pennsylvania Department of Environmental Protection. In June 2017 ITC received approval from Canada’s Governor in Council and the CPCN was issued by the NEB. The Lake Erie Connector project 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

MANAGEMENT DISCUSSION AND ANALYSIS 20 June 30, 2017

efficiently access energy, capacity and renewable energy credit opportunities in both markets. The project continues to advance through regulatory, operational, and economic milestones. Remaining key milestones include: receiving approval from the U.S. Army Corps of Engineers of a joint application, of which approval by the Pennsylvania Department of Environmental Protection was received in May 2017; completing project cost refinements; and securing favourable transmission service agreements with prospective counterparties. Pending achievement of key milestones, the expected in-service date for the project is late 2020.

The Wataynikaneyap Power Project continues to advance in Ontario. Wataynikaneyap Power consists of a partnership between 22 First Nations and FortisOntario, with a mandate to develop new transmission lines to connect remote First Nations communities to the electricity grid in Ontario. In 2016 the Government of Ontario designated Wataynikaneyap Power as the licensed transmission company to complete this project. FortisOntario reached an agreement with Renewable Energy Systems Canada in December 2016 to acquire its ownership interest in the Wataynikaneyap Partnership. The transaction was approved by the Ontario Energy Board (“OEB”) and closed in March 2017. As a result, FortisOntario’s ownership interest in the Wataynikaneyap Partnership has increased to 49%, with the remaining 51% ownership interest held by the 22 First Nations communities. The total estimated capital cost for the project, subject to final cost estimation, is approximately $1.35 billion and is expected to contribute to significant savings for the First Nations communities and result in a significant reduction in greenhouse gas emissions. In March 2017 the project reached a significant milestone with the approval by the OEB of a deferral account to recognize development costs incurred between November 2010 and the commencement of construction. In addition to environmental assessments underway, other regulatory approvals are currently being sought and the next regulatory milestone will be the preparation and filing of the leave to construct with the OEB, which is expected in the fourth quarter of 2017. Construction will commence pending the receipt of permits, approvals and a cost-sharing agreement between the federal and provincial government.

The Corporation also has other significant opportunities that have not yet been included in the Corporation’s capital expenditure forecast including, but not limited to: transmission investment opportunities at ITC; investment opportunities for CH Energy in New York Transco, LLC to address electric transmission constraints in New York State; renewable energy investments, energy storage projects 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 operating 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 operating subsidiaries to pay dividends based on management’s intent to maintain the regulator-approved capital structures for each of its regulated operating subsidiaries. The Corporation does not expect that maintaining the targeted capital structures of its regulated operating 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 and finance acquisitions 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, and advances from minority investors. 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.

MANAGEMENT DISCUSSION AND ANALYSIS 21 June 30, 2017

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 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 $1.5 billion remains under the base shelf prospectus.

As at June 30, 2017, management expects consolidated fixed-term debt maturities and repayments to average approximately $730 million annually over the next five years. 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, 2017 and are expected to remain compliant throughout 2017.

CREDIT FACILITIES

As at June 30, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.4 billion, of which approximately $4.0 billion was unused, including $940 million 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 $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2017 through 2022.

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

Credit Facilities					As at
	Regulated Utilities		Corporate and Other		June 30, 2017		December 31, 2016
($ millions)
Total credit facilities (1)	4,041		1,385		5,426		5,976
Credit facilities utilized:
Short-term borrowings (1)	(564	)	(4	)	(568	)	(1,155	)
Long-term debt (including current portion) (2)	(420	)	(359	)	(779	)	(973	)
Letters of credit outstanding	(67	)	(57	)	(124	)	(119	)
Credit facilities unused (1)	2,990		965		3,955		3,729

⁽¹⁾  Total credit facilities and short-term borrowings as atJune 30, 2017include $207 millionoutstanding under ITC’s commercial paper program (December 31, 2016 -$195 million). Outstanding commercial paper does not reduce available capacity under the Corporation’s consolidated credit facilities.

⁽²⁾  As at June 30, 2017, credit facility borrowings classified as long-term debt included$104 millionin current installments of long-term debt on the consolidated balance sheet (December 31, 2016 - $61 million).

As at June 30, 2017 and December 31, 2016, certain 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 2016 Annual MD&A, except that, in March 2017, the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares.

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $124 million as at June 30, 2017 (December 31, 2016 - $119 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.

MANAGEMENT DISCUSSION AND ANALYSIS 22 June 30, 2017

BUSINESS RISK MANAGEMENT

Year-to-date 2017, the business risks of the Corporation were generally consistent with those disclosed in the Corporation’s 2016 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: In April 2017 S&P upgraded TEP’s unsecured debt rating to ‘A-’ from ‘BBB+’ with a stable outlook. For a discussion on the Corporation’s credit ratings refer to the “Liquidity and Capital Resources” section of this MD&A.

Defined Benefit Pension and Other Post-Employment Benefit Plan Assets:As at June 30, 2017, the fair value of the Corporation’s consolidated defined benefit pension and other post-employment benefit plan assets was $3,032 million compared to $2,898 million as at December 31, 2016.

CHANGES IN ACCOUNTING POLICIES

The condensed consolidated interim financial statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation’s 2016 annual audited consolidated financial statements, except as described below.

Simplifying the Test for Goodwill Impairment

Effective January 1, 2017, the Corporation adopted Accounting Standards Update (“ASU”) No. 2017-04, Simplifying the Test for Goodwill Impairment. The amendments in this update simplify the subsequent measurement of goodwill by eliminating step two in the current two-step goodwill impairment test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. The above-noted ASU was applied prospectively and did not impact the Corporation’s unaudited condensed consolidated interim financial statementsfor the three and six months ended June 30, 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.

Revenue from Contracts with Customers

ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, and supersede 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 can be applied consistently across various transactions, industries and capital markets. In 2016 a number of additional ASUs were issued that clarify implementation guidance in ASC Topic 606. This standard, and all related ASUs, is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted for annual and interim periods beginning after December 15, 2016. The Corporation has elected not to early adopt.

The new guidance permits two methods of adoption: (i) the full retrospective method, under which comparative periods would be restated, and the cumulative impact of applying the standard would be recognized as at January 1, 2017, the earliest period presented; and (ii) the modified retrospective method, under which comparative periods would not be restated and the cumulative impact of applying the standard would be recognized at the date of initial adoption, January 1, 2018. The Corporation expects to use the modified retrospective approach; however, it continues to monitor interpretative issues that remain outstanding. Any significant developments in interpretative issues could change the Corporation’s expected method of adoption.

MANAGEMENT DISCUSSION AND ANALYSIS 23 June 30, 2017

More than 80% of the Corporation’s revenue is generated from energy sales to retail and wholesale customers based on published tariff rates, as approved by the respective regulators, and is considered to be in the scope of ASU No. 2014-09. Fortis has assessed retail and wholesale tariff revenue and expects that the adoption of this standard will not change the Corporation’s accounting policy for recognizing retail and wholesale tariff revenue and, therefore, will not have an impact on earnings.

Fortis continues to assess whether this standard will have an impact on its remaining revenue streams. The Corporation has not disclosed the expected impact of the adoption of this standard on its consolidated financial statements as it is not expected to be material. However, certain specific interpretative issues remain outstanding and the conclusions reached, if different than currently anticipated, could have a material impact on the Corporation’s consolidated financial statements and related disclosures. Fortis continues to closely monitor developments related to the new standard.

The adoption of this standard will impact the Corporation’s revenue disclosures as revenue from contracts with customers is required to be reported separately from alternative revenue, which is outside the scope of ASC Topic 606. Fortis is in the process of drafting these required disclosures.

As part of its effort to adopt the new revenue recognition standard, Fortis is monitoring its adoption process under its existing internal controls over financial reporting (“ICFR”), including accounting processes and the gathering and evaluation of information used in assessing the required disclosures. As the implementation process continues, Fortis will assess any necessary changes to ICFR.

Recognition and Measurement of Financial Assets and Financial Liabilities

ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and 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 will be able to 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 asset. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

Leases

ASU No. 2016-02 was issued in February 2016 and the amendments in this update 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 is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

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. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

MANAGEMENT DISCUSSION AND ANALYSIS 24 June 30, 2017

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

ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, was issued in March 2017 and the amendments in this update require that an employer disaggregate the current service costs 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. This update is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted. The amendments in this update should be applied retrospectively for the presentation of the net periodic benefit costs and prospectively, on and after the effective date, for the capitalization in assets of only the service cost component of net periodic benefit costs. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

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
	June 30, 2017		December 31, 2016
	Carrying	Estimated	Carrying	Estimated
($ millions)	Value	Fair Value	Value	Fair Value
Long-term debt, including current portion	21,257	23,137	21,219	22,523
Waneta Partnership promissory note	61	62	59	61

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.

For further details of the Corporation’s derivative instruments as at June 30, 2017 refer to Note 14 to the Corporation’s unaudited condensed consolidated interim financial statements. There were no material changes in the nature and amount of the Corporations’ derivative instruments from those disclosed in the 2016 Annual MD&A, except as follows.

In 2017 ITC entered into additional forward-starting interest rate swaps, all effective December 2017, with a combined notional amount of $247 million and 10-year original terms. The agreements include a mandatory early termination provision and will be terminated no later than the effective date. The interest rate swaps manage the interest rate risk associated with the forecasted future issuance of fixed-rate debt.

MANAGEMENT DISCUSSION AND ANALYSIS 25 June 30, 2017

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Corporation’s condensed consolidated 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 financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation’s regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. 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 2016 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 17 to the Corporation’s unaudited condensed consolidated interim financial statements. There were no material changes in the Corporation’s contingencies from those disclosed in the 2016 Annual MD&A, except as described below.

Fortis and ITC

Following announcement of the acquisition of ITC in February 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan (“Superior Court”) and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified damages, and costs, including attorneys’ fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc.

In January 2017 the defendants filed an additional motion for summary disposition, which was to be heard by the court in March 2017. A hearing on class certification occurred in February 2017.

In March 2017 an agreement in principle was reached to settle the case, subject to formal documentation and court approval. The court has stayed the matter, except for all settlement-related proceedings. In May 2017 the court preliminarily approved the settlement and set a final settlement approval hearing for September 2017.

MANAGEMENT DISCUSSION AND ANALYSIS 26 June 30, 2017

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 transactionsfor the three and six months ended June 30, 2017 and 2016.

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
Periods Ended June 30	Quarter		Year-to-Date
($ millions)	2017	2016	2017	2016
Sale of capacity from Waneta Expansion to FortisBC Electric	3	3	19	18
Sale of energy from Belize Electric Company Limited to Belize Electricity	7	6	14	14
Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy	5	5	13	5

As at June 30, 2017, accounts receivable on the Corporation’s condensed consolidated interim balance sheet included approximately $11 million due from Belize Electricity (December 31, 2016 - $16 million), in which Fortis holds a 33% equity investment.

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 unaudited condensed consolidated 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 ($)	Diluted ($)
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
March 31, 2016	1,772	162	0.57	0.57
December 31, 2015	1,723	135	0.48	0.48
September 30, 2015	1,579	151	0.54	0.54

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 the impact of the sale of non-regulated assets, as well as the 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 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.

MANAGEMENT DISCUSSION AND ANALYSIS 27 June 30, 2017

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. A discussion of the quarter over quarter variance in financial results is provided in the “Financial Highlights” section of this MD&A.

March 2017/March 2016: Net earnings attributable to common equity shareholders were $294 million, or $0.72 per common share, for the first quarter of 2017 compared to earnings of $162 million, or $0.57 per common share, for the first quarter of 2016. The increase was driven by earnings of $91 million at ITC, acquired in October 2016. The increase was also due to: (i) strong performance at UNS Energy, due to the favourable settlement of matters pertaining to FERC ordered transmission refunds of $7 million, after-tax, in January 2017 compared to $11 million, after-tax, in FERC ordered transmission refunds in the first quarter of 2016, and higher retail rates as approved pursuant to its 2017 general rate case; (ii) acquisition-related transactions costs associated with ITC recognized in Corporate and Other expenses in the first quarter of 2017; (iii) contribution from Aitken Creek, including an after-tax $6 million unrealized gain on the mark-to-market of derivatives; and (iv) the timing of quarterly revenue and operating expenses as compared to the same period in 2016 and higher AFUDC at FortisBC Energy. The increase was partially offset by: (i) lower contribution from FortisAlberta, mainly due to lower customer rates and higher operating expenses; (ii) higher finance charges at Corporate and Other associated with the acquisitions of ITC and Aitken Creek; and (iii) unfavourable foreign exchange associated with US dollar-denominated earnings.

December 2016/December 2015: Net earnings attributable to common equity shareholders were $189 million, or $0.49 per common share, for the fourth quarter of 2016 compared to earnings of $135 million, or $0.48 per common share, for the fourth quarter of 2015. The increase in earnings was driven by contribution of $59 million from ITC, which was reduced by $22 million in expenses associated with the accelerated vesting of the Company’s stock-based compensation awards as a result of the acquisition. Strong performance at most of the Corporation’s regulated utilities and contribution of $6 million from Aitken Creek, net of an after-tax $3 million unrealized loss on the mark-to-market of derivatives, also contributed to higher earnings. The increase was partially offset by higher Corporate and Other expenses. Corporate and Other expenses reflected after-tax acquisition-related transaction costs of $32 million in the fourth quarter of 2016, compared to $7 million in the fourth quarter of 2015, with the remaining increase primarily due to finance charges associated with the acquisition of ITC.

September 2016/September 2015: Net earnings attributable to common equity shareholders were $127 million, or $0.45 per common share, for the third quarter of 2016 compared to earnings of $151 million, or $0.54 per common share, for the third quarter of 2015. The decrease in earnings was primarily due to: $7 million (US$5 million) in FERC ordered transmission refunds at UNS Energy, $19 million in acquisition-related transaction costs, and a $1 million unrealized loss on the mark-to-market of derivatives in the third quarter of 2016; a $5 million positive tax adjustment on the sale of hotel assets, a $5 million gain on the sale of non-regulated generation assets, and a foreign exchange gain of $5 million in the third quarter of 2015; partially offset by the $9 million loss on the settlement of expropriation matters in Belize in the third quarter of 2015. Also contributing to the decrease in earnings were: (i) lower earnings at FortisAlberta due to higher operating expenses, a negative capital tracker revenue adjustment as a result of the outcome of the 2016 Generic Cost of Capital Proceeding in Alberta, and lower average energy consumption; (ii) the sale of hotel assets in 2015; and (iii) an increase in Corporate and Other expenses. Partially offsetting the above decreases in earnings were: (i) strong performance at most of the Corporation’s regulated utilities driven by UNS Energy, largely due to the settlement of Springerville Unit 1 matters, and Central Hudson, due to an increase in delivery revenue; (ii) the timing of quarterly earnings at FortisBC Electric compared to the third quarter of 2015; and (iii) contribution of $2 million from Aitken Creek, which was acquired in early April 2016.

MANAGEMENT DISCUSSION AND ANALYSIS 28 June 30, 2017

OUTLOOK

The Corporation’s results for 2017 will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital plan, the balance and strength of its diversified portfolio of utility businesses, as well as growth opportunities within its service territories.

Over the five-year period through 2021, the Corporation’s capital program is expected to be approximately $13 billion, increasing rate base to almost $30 billion in 2021. Fortis expects this 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 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation’s utilities, the successful execution of the five-year capital expenditure program, and management’s continued confidence in the strength of the Corporation’s diversified portfolio of utilities and record of operational excellence.

OUTSTANDING SHARE DATA

As at July 27, 2017, the Corporation had issued and outstanding 417.9 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 27, 2017 is approximately 4.0 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 29 June 30, 2017