Exhibit 99.3

Interim Management Discussion and Analysis

For the three and nine months ended September 30, 2018

Dated November 1, 2018

TABLE OF CONTENTS
Forward-Looking Information	1	Contractual Obligations	16
Corporate Overview	2	Capital Structure	16
Financial Highlights	3	Credit Ratings	16
Segmented Results of Operations	5	Capital Expenditure Plan	17
Regulated Utilities	6	Additional Investment Opportunities	19
ITC	6	Cash Flow Requirements	19
UNS Energy	6	Credit Facilities	20
Central Hudson	7	Off-Balance Sheet Arrangements	21
FortisBC Energy	8	Business Risk Management	21
FortisAlberta	8	Changes in Accounting Policies	21
FortisBC Electric	9	Future Accounting Pronouncements	22
Other Electric	10	Financial Instruments	23
Non-Regulated	10	Critical Accounting Estimates	23
Energy Infrastructure	10	Related-Party and Inter-Company Transactions	24
Corporate and Other	11	Summary of Quarterly Results	25
Regulatory Highlights	11	Outlook	26
Consolidated Financial Position	13	Outstanding Share Data	26
Liquidity and Capital Resources	14	Condensed Consolidated Interim Financial Statements (Unaudited)	F-1
Summary of Consolidated Cash Flows	14

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 nine months ended September 30, 2018 ("Interim Financial Statements") and the MD&A and audited consolidated financial statements for the year ended December 31, 2017 included in the Corporation's 2017 Annual Report. Financial information contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") and is presented in Canadian dollars unless otherwise specified.

Fortis includes forward-looking information in the MD&A within the meaning of applicable Canadian securities laws and forward-looking statements within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, collectively referred to as "forward-looking information". Forward-looking information included in the MD&A reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which include, without limitation: the expectation that regulatory deferral mechanisms will capture the financial impacts of changes in usage, gas costs and material costs incurred beyond the control of FortisBC Energy as a result of the incident affecting Enbridge Inc.'s natural gas transmission pipeline; the expectation that the Federal Energy Regulatory Commission's order reducing adders for the Midcontinent Independent System Operator regulated operating subsidiaries will not have a material adverse impact on the results of operations, cash flows or financial position; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the Corporation's forecast capital expenditures for 2018 and for the period from 2019 through 2023 and potential funding sources for the capital plan; the nature, timing, benefits, expected costs of certain capital projects including, without limitation, the Tilbury liquefied natural gas expansion, the Lower Mainland System Upgrade Project, the Wataynikaneyap Transmission Power Project, the Southline Transmission Project, the New Mexico Wind Project, and the Inland Gas Upgrades Project and additional opportunities beyond the base capital expenditure plan including the Lake Erie Connector Project and liquefied natural gas infrastructure investment opportunities in British Columbia; the expectation that subsidiary operating expenses and interest costs will be paid out of subsidiary operating cash flows; the expected sources of cash required of subsidiaries and Fortis to complete subsidiary capital expenditure programs; the expectation that maintaining the targeted capital structure of the Corporation's regulated operating subsidiaries will not have an

MANAGEMENT DISCUSSION AND ANALYSIS 1 September 30, 2018

impact on its ability to pay dividends in the foreseeable future; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2018; the intent of management to refinance certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities with long-term permanent financing; the expected timing and impact, if any, of the adoption of future accounting pronouncements; the expectation that long-term debt will not be settled prior to maturity; the Corporation's forecast rate base for 2021 and 2023; the expectation that the Corporation's significant capital expenditure plan will support continuing growth in earnings and dividends; and targeted average annual dividend growth through 2023.

Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; no material capital project and financing cost overrun related to any of the Corporation's capital projects; the realization of additional opportunities; the Board of Directors exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; no significant changes in tax laws; no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel, coal and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans, environmental laws and regulations that may have a material negative affect on the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the continued tax deferred treatment of earnings from the Corporation's foreign operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital expenditure plan.

Forward-looking information involves significant risks, uncertainties and assumptions. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risk Management" in this MD&A and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2018 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation's utilities; the impact of fluctuations in foreign exchange rates; the impact of the Tax Cuts and Jobs Act on the Corporation's future results of operations and cash flows; risk associated with the impacts of less favourable economic conditions on the Corporation's results of operations; risk associated with the Corporation's ability to continue to comply with Section 404(a) of the Sarbanes-Oxley Act of 2002 and the related rules of the U.S. Securities and Exchange Commission and the Public Company Accounting Oversight Board; risk associated with the completion of the Corporation's 2018 capital expenditure plan, including completion of major capital projects in the timelines anticipated and at the expected amounts; and uncertainty in the timing and access to capital markets to arrange sufficient and cost-effective financing to finance, among other things, capital expenditures and the repayment of maturing debt.

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

CORPORATE OVERVIEW

Fortis is a leader in the North American regulated electric and gas utility industry, with 2017 revenue of $8.3 billion and total assets of $50 billion as at September 30, 2018. The Corporation's 8,500 employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.

Year-to-date September 30, 2018, the Corporation's electricity systems met a combined peak demand of 33,458 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,599 terajoules. For additional information on the Corporation's operations and reportable segments, refer to Note 1 to the Corporation's Interim Financial Statements and to the "Corporate Overview" section of the 2017 Annual MD&A.

MANAGEMENT DISCUSSION AND ANALYSIS 2 September 30, 2018

FINANCIAL HIGHLIGHTS

Fortis has adopted a strategy of long-term profitable growth with the primary measures of financial performance being earnings per common share and total shareholder return. Key financial highlights are provided below.

Consolidated Financial Highlights
Periods Ended September 30	Quarter				Year-to-Date
($ millions, except for common share data)	2018	2017	Variance		2018	2017	Variance
Revenue	2,040	1,901	139		6,184	6,190	(6	)
Energy Supply Costs	574	478	96		1,810	1,756	54
Operating Expenses	557	503	54		1,663	1,649	14
Depreciation and Amortization	313	290	23		924	885	39
Other Income, Net	23	22	1		50	70	(20	)
Finance Charges	245	225	20		724	686	38
Income Tax Expense	52	106	(54	)	135	314	(179	)
Net Earnings	322	321	1		978	970	8
Net Earnings Attributable to:
Non-Controlling Interests	30	27	3		90	92	(2	)
Preference Equity Shareholders	16	16	—		49	49	—
Common Equity Shareholders	276	278	(2	)	839	829	10
Net Earnings	322	321	1		978	970	8
Earnings per Common Share
Basic ($)	0.65	0.66	(0.01	)	1.98	2.00	(0.02	)
Diluted ($)	0.65	0.66	(0.01	)	1.98	2.00	(0.02	)
Weighted Average Number of Common Shares Outstanding (# millions)	425.6	418.6	7.0		423.8	413.9	9.9
Cash Flow from Operating Activities	796	800	(4	)	2,067	1,990	77

Revenue

The increase in revenue for the quarter was primarily due to favourable foreign exchange, rate base growth, increased electricity sales at UNS Energy, and the flow through in customer rates of higher overall purchased commodity costs. The increase was partially offset by lower customer rates reflecting the recovery of reduced income tax expense due to a change in the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018 ("U.S. tax reform").

The decrease in revenue year to date was primarily due to: (i) unfavourable foreign exchange; (ii) lower customer rates reflecting the recovery of reduced income tax expense due to U.S. tax reform; (iii) lower earnings from the Aitken Creek natural gas storage facility ("Aitken Creek") related to unrealized net losses of $28 million on the mark-to-market of natural gas derivatives period over period; and (iv) a change in presentation of certain revenues to a net basis upon implementation of Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers. The decrease was partially offset by rate base growth, increased sales at UNS Energy and the flow through in customer rates of higher overall purchased commodity costs.

Energy Supply Costs

The increase in energy supply costs for the quarter and year to date was primarily due to increased electricity sales at UNS Energy due to an increase in system capacity and seasonality, and overall higher commodity costs. Unfavourable foreign exchange contributed to the increase for the quarter, while favourable foreign exchange partially offset the year-to-date increase.

Operating Expenses

The increase in operating expenses for the quarter was primarily due to the receipt of a break fee associated with the termination of the Waneta Dam purchase agreement recognized in the third quarter of 2017, along with unfavourable foreign exchange.

MANAGEMENT DISCUSSION AND ANALYSIS 3 September 30, 2018

The increase in operating expenses year to date was due to the break fee discussed above and increased maintenance expense, mainly due to planned outages at UNS Energy, partially offset by the corresponding change in presentation discussed above for revenue, and favourable foreign exchange.

Depreciation and Amortization

The increase in depreciation and amortization for the quarter and year to date was primarily due to continued investment in energy infrastructure at the Corporation's utilities.

Other Income, Net

Other income, net of expenses, was comparable for the quarter.

The decrease in other income, net of expenses, year to date was due to the favourable settlement of matters at UNS Energy pertaining to the Federal Energy Regulatory Commission ("FERC") ordered transmission refunds in 2017, lower equity component of allowance for funds used during construction (“AFUDC”) at FortisBC Energy, and mark-to-market net losses on foreign exchange contracts and total return swaps in 2018.

Finance Charges

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

Income Tax Expense

The decrease in income tax expense for the quarter and year to date was primarily due to U.S. tax reform. The decrease year to date was also due to a one-time $30 million remeasurement of the Corporation's deferred income tax liabilities that resulted from an election to file a consolidated state income tax return.

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

The decrease in net earnings attributable to common equity shareholders for the quarter was primarily due to: (i) the receipt of a break fee associated with the termination of the Waneta Dam purchase agreement recognized in the third quarter of 2017; and (ii) lower earnings from Aitken Creek related to unrealized net losses on the mark-to-market of natural gas derivatives quarter over quarter. The decrease was partially offset by: (i) rate base growth driven by ITC; (ii) favourable electricity sales at UNS Energy; (iii) performance at the Canadian and Caribbean utilities, tempered by higher operating and interest expenses at FortisBC Energy; and (iv) favourable foreign exchange.

The increase in net earnings attributable to common equity shareholders year to date was primarily due to: (i) the one-time remeasurement of the Corporation's deferred income tax liabilities as a result of an election to file a consolidated state income tax return; (ii) rate base growth driven by ITC; and (iii) the impact of a full year of new rates compared to last year and favourable electricity sales at UNS Energy. The increase was partially offset by: (i) lower earnings from Aitken Creek related to unrealized net losses on the mark-to-market of natural gas derivatives; (ii) the receipt of a break fee, as discussed above; (iii) unfavourable foreign exchange; and (iv) the impact of U.S. tax reform.

Basic earnings per common share for the quarter and year to date were lower by $0.01 and $0.02, respectively, compared to the same periods in 2017. The decrease was due to the impact of the above-noted items on net earnings attributable to common equity shareholders and an increase in the weighted average number of common shares outstanding associated with the Corporation's dividend reinvestment and share plans, and on a year-to-date basis by the issuance of $500 million of common equity in March 2017.

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

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

MANAGEMENT DISCUSSION AND ANALYSIS 4 September 30, 2018

The Corporation calculates adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes are not reflective of the normal, ongoing operations of the business. Adjusted basic earnings per common share is calculated by dividing adjusted net earnings attributable to common equity shareholders by the weighted average number of common shares outstanding.

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

Non-US GAAP Reconciliation
Periods Ended September 30	Quarter					Year-to-Date
($ millions, except for common share data)	2018	2017		Variance		2018		2017		Variance
Net Earnings Attributable to Common Equity Shareholders	276	278		(2	)	839		829		10
Adjusting Items:
UNS Energy - Settlement of FERC-ordered transmission refunds	—	—		—		—		(11	)	11
Corporate and Other -
Remeasurement of deferred income tax liabilities - consolidated state income tax election	—	—		—		(30	)	—		(30	)
Acquisition break fee	—	(24	)	24		—		(24	)	24
Adjusted Net Earnings Attributable to Common Equity Shareholders	276	254		22		809		794		15
Adjusted Basic Earnings Per Common Share ($)	0.65	0.61		0.04		1.91		1.92		(0.01	)
Weighted Average Number of Common Shares Outstanding (# millions)	425.6	418.6		7.0		423.8		413.9		9.9

SEGMENTED RESULTS OF OPERATIONS

Segmented Net Earnings Attributable to Common Equity Shareholders
Periods Ended September 30	Quarter						Year-to-Date
($ millions)	2018		2017		Variance		2018		2017		Variance
Regulated Utilities
ITC	97		89		8		269		273		(4	)
UNS Energy	135		112		23		266		242		24
Central Hudson	17		15		2		50		48		2
FortisBC Energy	(22	)	(15	)	(7	)	83		88		(5	)
FortisAlberta	39		35		4		98		91		7
FortisBC Electric	12		11		1		43		42		1
Other Electric	30		20		10		83		73		10
Non-Regulated
Energy Infrastructure	12		21		(9	)	50		69		(19	)
Corporate and Other	(44	)	(10	)	(34	)	(103	)	(97	)	(6	)
Net Earnings Attributable to Common Equity Shareholders	276		278		(2	)	839		829		10

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

MANAGEMENT DISCUSSION AND ANALYSIS 5 September 30, 2018

REGULATED UTILITIES

ITC

Financial Highlights (1)
Periods Ended September 30	Quarter			Year-to-Date
($ millions)	2018	2017	Variance	2018	2017	Variance
Average US:CAD Exchange Rate (2)	1.31	1.25	0.06	1.29	1.31	(0.02	)
Revenue	386	376	10	1,114	1,179	(65	)
Earnings	97	89	8	269	273	(4	)

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

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

Revenue

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

The decrease in revenue year to date was primarily due to the impact of U.S. tax reform as discussed above and approximately $17 million of unfavourable foreign exchange, partially offset by rate base growth.

Earnings

The increase in earnings for the quarter was primarily due to approximately $4 million of favourable foreign exchange and rate base growth, partially offset by the net unfavourable impact of U.S. tax reform.

The decrease in earnings year to date was primarily due to the net unfavourable impact of U.S. tax reform, approximately $4 million of unfavourable foreign exchange, and higher business development costs, partially offset by rate base growth.

UNS ENERGY ⁽¹⁾ 

Financial Highlights	Quarter			Year-to-Date
Periods Ended September 30	2018	2017	Variance	2018	2017	Variance
Average US:CAD Exchange Rate (2)	1.31	1.25	0.06	1.29	1.31	(0.02	)
Electricity Sales (gigawatt hours ("GWh"))	5,356	4,416	940	12,655	11,418	1,237
Gas Volumes (petajoules ("PJ"))	1	1	—	8	9	(1	)
Revenue ($ millions)	687	599	88	1,661	1,609	52
Earnings ($ millions)	135	112	23	266	242	24

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

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

Electricity Sales & Gas Volumes

The increase in electricity sales for the quarter and year to date was primarily a result of an increase in short-term wholesale sales due to an increase in system capacity related to Gila River generating station Unit 2 and warmer summer temperatures increasing air conditioning load. Short-term wholesale revenues are primarily returned to customers through regulatory deferral mechanisms and, as a result, do not have an impact on earnings.

Gas volumes were comparable with the same periods in 2017.

Revenue

The increase in revenue for the quarter was primarily due to higher electricity sales as discussed above, approximately $27 million of favourable foreign exchange, and the flow through of higher energy supply costs. The increase was partially offset by the recovery of lower corporate income tax in customer rates associated with U.S. tax reform.

MANAGEMENT DISCUSSION AND ANALYSIS 6 September 30, 2018

The increase in revenue year to date was primarily due to the same factors discussed above for the quarter, with the exception of foreign exchange which had an unfavourable impact of approximately $15 million. Also contributing to the increase in revenue year to date was the impact of the rate case settlement effective February 27, 2017, partially offset by the impact of U.S. tax reform.

Earnings

The increase in earnings for the quarter was primarily due to higher electricity sales as discussed above, lower income tax expense associated with U.S. tax reform, and approximately $5 million of favourable foreign exchange. The increase was partially offset by higher operating expenses resulting from planned generation outages in 2018.

The increase in earnings year to date was primarily due to the same factors discussed above for the quarter, with the exception of foreign exchange which had no significant impact year to date. Also contributing to the increase in earnings year to date was the impact of the rate case settlement effective February 27, 2017, partially offset by the favourable settlement of matters pertaining to FERC-ordered transmission refunds in 2017 and increased operating expenses resulting from planned generation outages in 2018.

CENTRAL HUDSON

Financial Highlights	Quarter			Year-to-Date
Periods Ended September 30	2018	2017	Variance	2018	2017	Variance
Average US:CAD Exchange Rate (1)	1.31	1.25	0.06	1.29	1.31	(0.02	)
Electricity Sales (GWh)	1,416	1,318	98	3,868	3,696	172
Gas Volumes (PJ)	4	3	1	17	16	1
Revenue ($ millions)	214	197	17	690	661	29
Earnings ($ millions)	17	15	2	50	48	2

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

Electricity Sales & Gas Volumes

The increase in electricity sales and gas volumes for the quarter and year to date was primarily due to higher average consumption as a result of colder temperatures increasing heating load during the winter months and warmer temperatures increasing air conditioning load during the summer months.

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

Revenue

The increase in revenue for the quarter and year to date was primarily due to the recovery from customers of higher commodity costs and increases in customer delivery rates effective July 1, 2017 and 2018, partially offset by the recovery of lower corporate income tax in customer rates associated with U.S. tax reform. Revenue was also impacted by approximately $8 million of favourable and $12 million of unfavourable foreign exchange for the quarter and year to date, respectively.

Earnings

The increase in earnings for the quarter and year to date was primarily due to the rate increases effective July 1, 2017 and 2018 reflecting a return on increased rate base assets. Favourable foreign exchange of approximately $1 million also contributed to earnings for the quarter. The increase in earnings year to date was partially offset by storm restoration costs and approximately $1 million of unfavourable foreign exchange.

MANAGEMENT DISCUSSION AND ANALYSIS 7 September 30, 2018

FORTISBC ENERGY

Financial Highlights	Quarter						Year-to-Date
Periods Ended September 30	2018		2017		Variance		2018	2017	Variance
Gas Volumes (PJ)	30		27		3		149	152	(3	)
Revenue ($ millions)	161		156		5		816	832	(16	)
Earnings ($ millions)	(22	)	(15	)	(7	)	83	88	(5	)

Gas Volumes

The increase in gas volumes for the quarter was primarily due to higher average consumption, as a result of colder temperatures increasing heating load.

The decrease in gas volumes year to date was primarily due to lower average consumption as a result of warmer temperatures reducing heating load in the first half of 2018, partially offset by the increase in consumption in the third quarter of 2018, as discussed above.

Revenue

The increase in revenue for the quarter was primarily due to rate base growth, partially offset by lower commodity cost of natural gas charged to customers.

The decrease in revenue year to date was primarily due to lower commodity cost of natural gas charged to customers, partially offset by rate base growth.

Earnings

The decrease in earnings for the quarter and year to date was primarily due to the timing of operating expenses incurred throughout 2018 and higher interest expense, partially offset by rate base growth.

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

On October 9, 2018, an incident took place affecting Enbridge Inc.'s natural gas transmission pipeline near Prince George, British Columbia ("BC"). This pipeline supplies natural gas which FortisBC Energy distributes to its customers in various locations across BC. Both the duration and amount of reduced capacity from the disrupted pipeline will determine the effect on FortisBC Energy and its customers. Regulatory deferral mechanisms are in place that are expected to capture the financial impact of changes in usage, gas costs and material costs incurred that are beyond the control of the Company. No FortisBC Energy infrastructure has been damaged as a result of this incident.

FORTISALBERTA

Financial Highlights	Quarter			Year-to-Date
Periods Ended September 30	2018	2017	Variance	2018	2017	Variance
Energy Deliveries (GWh)	4,240	4,156	84	12,811	12,690	121
Revenue ($ millions)	155	153	2	439	448	(9	)
Earnings ($ millions)	39	35	4	98	91	7

Energy Deliveries

The increase in energy deliveries for the quarter was primarily due to higher average consumption as a result of warmer temperatures increasing air conditioning load.

The increase in energy deliveries year to date was primarily due to increased average consumption as a result of colder temperatures increasing heating load in winter months and warmer temperatures increasing air conditioning load in summer months, along with higher farm and irrigation consumption due to lower precipitation, partially offset by a lower number of oil and gas customer sites period over period.

MANAGEMENT DISCUSSION AND ANALYSIS 8 September 30, 2018

Revenue

The increase in revenue for the quarter was primarily due to higher distribution rates effective January 1, 2018 reflecting a return on increased rate base assets and incremental return due to efficiencies achieved in the first performance-based rate setting ("PBR") term through the return on equity ("ROE") efficiency carryover mechanism, and revenue associated with customer additions. Also increasing revenue for the quarter was a capital tracker revenue true-up of $5 million related to capital expenditures in 2016 and 2017. The increase was partially offset by a decrease of approximately $10 million resulting from an election to record municipal franchise fee revenue on a net basis upon implementation of ASC Topic 606, Revenue from Contracts with Customers, effective January 1, 2018, using the modified retrospective approach under which comparative periods are not restated.

The decrease in revenue year to date was primarily due to a decrease of approximately $32 million related to the change in presentation of municipal franchise fees as discussed above, partially offset by higher distribution rates, customer additions and capital tracker revenue also discussed above.

Earnings

The increase in earnings for the quarter and year to date was primarily due to higher distribution rates reflecting a return on increased rate base assets and the ROE efficiency carryover mechanism, the impact of customer additions, and capital tracker revenue as discussed above. The increase was partially offset by higher operating expenses related to vegetation management and labour costs, as well as increased interest expense related to a long-term debt issuance in 2017.

FORTISBC ELECTRIC

Financial Highlights	Quarter				Year-to-Date
Periods Ended September 30	2018	2017	Variance		2018	2017	Variance
Electricity Sales (GWh)	769	779	(10	)	2,411	2,436	(25	)
Revenue ($ millions)	96	93	3		297	291	6
Earnings ($ millions)	12	11	1		43	42	1

Electricity Sales

The decrease in electricity sales for the quarter and year to date was due to lower average consumption as a result of colder temperatures reducing air conditioning load. Also contributing to the year-to-date decrease was reduced heating load in the first quarter of 2018 as a result of warmer temperatures.

Revenue

The increase in revenue for the quarter and year to date was primarily due to an increase in revenue recognized from third-party contract work.

Earnings

Earnings for the quarter and year to date were comparable with the same periods in 2017.

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

MANAGEMENT DISCUSSION AND ANALYSIS 9 September 30, 2018

OTHER ELECTRIC ⁽¹⁾ 

Financial Highlights	Quarter			Year-to-Date
Periods Ended September 30	2018	2017	Variance	2018	2017	Variance
Average US:CAD Exchange Rate (2)	1.31	1.25	0.06	1.29	1.31	(0.02	)
Electricity Sales (GWh)	1,798	1,740	58	6,871	6,841	30
Revenue ($ millions)	307	283	24	1,040	1,016	24
Earnings ($ millions)	30	20	10	83	73	10

⁽¹⁾  Comprised of utilities in Eastern Canada and the Caribbean as follows: Newfoundland Power Inc.; Maritime Electric Company, Limited; FortisOntario Inc.; a 49% equity investment in Wataynikaneyap Power Limited Partnership; an approximate 60% controlling interest in Caribbean Utilities Company, Ltd. ("Caribbean Utilities"); FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "FortisTCI"); and a 33% equity investment in Belize Electricity Limited ("BEL").

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

Electricity Sales

The increase in electricity sales for the quarter was primarily due to higher electricity sales at FortisTCI, due to the unfavourable impact of Hurricane Irma on electricity sales during the third quarter of 2017, and customer additions.

The increase in electricity sales year to date was primarily due to higher electricity sales during the third quarter, as discussed above, as well as colder temperatures during the winter months increasing heating load. The increase was partially offset by the completion of a large project by a commercial customer in Newfoundland.

Revenue

The increase in revenue for the quarter and year to date was primarily due to the flow through in customer rates of higher fuel costs in the Caribbean and overall higher electricity sales. Favourable foreign exchange of approximately $3 million contributed to the increase for the quarter, while unfavourable foreign exchange decreased revenue by approximately $3 million on a year-to-date basis.

Earnings

The increase in earnings for the quarter was primarily due to changes in the seasonality of energy supply costs at Newfoundland Power, business development costs of approximately $2 million incurred in the third quarter of 2017 related to the Wataynikaneyap Transmission Power Project, and higher electricity sales, partially offset by lower equity income from BEL.

The increase in earnings year to date was primarily due to the receipt of FortisTCI's business interruption insurance proceeds in the second quarter of 2018, timing of operating expenses and higher electricity sales, partially offset by lower equity income from BEL.

NON-REGULATED

ENERGY INFRASTRUCTURE ⁽¹⁾ 

Financial Highlights	Quarter				Year-to-Date
Periods Ended September 30	2018	2017	Variance		2018	2017	Variance
Energy Sales (GWh)	151	178	(27	)	768	760	8
Revenue ($ millions)	37	47	(10	)	134	162	(28	)
Earnings ($ millions)	12	21	(9	)	50	69	(19	)

⁽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.

MANAGEMENT DISCUSSION AND ANALYSIS 10 September 30, 2018

Energy Sales

The decrease in energy sales for the quarter was primarily due to lower rainfall reducing hydroelectric production in Belize. Energy sales increased year to date due to higher rainfall in the first half of 2018 increasing hydroelectric production in Belize.

Revenue and Earnings

The decrease in revenue and earnings for the quarter and year to date was primarily due to the unfavourable impact of the mark-to-market accounting of natural gas derivatives at Aitken Creek with unrealized losses of $2 million and $16 million, respectively, compared to unrealized gains of $3 million and $12 million, respectively, for the same periods in 2017. Revenue and earnings for the quarter were also impacted by lower hydroelectric production in Belize. The decrease in revenue and earnings year to date was partially offset by increased gas volumes and favourable pricing at Aitken Creek during the first half of 2018.

CORPORATE AND OTHER ⁽¹⁾ 

Financial Highlights
Periods Ended September 30	Quarter						Year-to-Date
($ millions)	2018		2017		Variance		2018		2017		Variance
Net loss	(44	)	(10	)	(34	)	(103	)	(97	)	(6	)

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

The increase in net expenses for the quarter and year to date was primarily driven by the receipt of a $24 million break fee associated with the termination of the Waneta Dam purchase agreement in the third quarter of 2017. Net expenses were also impacted by U.S. tax reform, which resulted in lower income tax recovery due to holding company interest being deductible at a lower corporate tax rate of 21%. The increase in net expenses year to date was partially offset by: (i) higher income tax recovery, due to a one-time $30 million remeasurement of the Corporation's deferred income tax liabilities which resulted from an election to file a consolidated state income tax return; and (ii) lower stock-based compensation and finance charges, which were substantially offset by mark-to-market net losses on foreign exchange contracts and total return swaps.

REGULATORY HIGHLIGHTS

Regulation of the Corporation's utilities is generally consistent with that disclosed in its 2017 Annual MD&A. A summary of significant regulatory developments year-to-date 2018 follows.

U.S. Tax Reform

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

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

UNS Energy: In April 2018 the Arizona Corporation Commission approved TEP's application to return ongoing income tax savings through a combination of customer bill credits and regulatory liabilities. Customer bill credits became effective in May 2018. As at September 30, 2018, a regulatory liability of $3 million (US$2 million) was recognized for amounts to be returned to customers during the remainder of 2018. In 2019 and beyond, TEP will continue to return savings to customers using the same approach. Regulatory liabilities will be returned to customers as part of TEP's next rate case, which is expected to be filed in 2019.

In March 2018 FERC issued an order directing TEP to either: (i) submit proposed revisions to its transmission rates or transmission revenue requirement to reflect the reduction in the federal corporate income tax rate; or (ii) show why a rate adjustment is not required. In May 2018 TEP proposed an overall customer rate reduction, to be effective March 2018, reflecting the lower federal corporate income tax rate. The proposal is currently being reviewed by FERC.

MANAGEMENT DISCUSSION AND ANALYSIS 11 September 30, 2018

Central Hudson: In June 2018, as part of its approval of a joint proposal, discussed below, the New York Public Service Commission ("PSC") approved Central Hudson's recommendation to reflect the recovery of lower federal corporate income tax in customer rates effective July 1, 2018. As at September 30, 2018, a regulatory liability of $12 million (US$10 million) was recognized related to the income tax savings realized in the first six months of 2018. As approved by the PSC, the refund of this regulatory liability to customers will be determined as part of a future regulatory proceeding.

ITC

Independence Incentive Adders

In April 2018 a third-party complaint was filed with FERC challenging independence incentive adders that were included in transmission rates charged by ITC's MISO-regulated operating subsidiaries. Independence incentive adders were established to encourage transmission investment and recognize that ITC's operating subsidiaries are independent, dedicated transmission-only operations, with no affiliation to market participants in their regions. The adders allowed up to 0.50% or 1.00% to be added to the authorized ROE, subject to any ROE cap established by FERC. On October 18, 2018, FERC issued an order in respect of this matter reducing the adders for each of the MISO-regulated operating subsidiaries to 0.25% effective April 20, 2018. On October 22, 2018, MISO filed a motion requesting an extension to January 17, 2019 to issue refunds. The resolution of this proceeding is not expected to have a material adverse impact on results of operations, cash flows or financial position.

ROE Complaints

On October 16, 2018, in response to complaints challenging the methodology used by FERC in setting the regional base ROE for ISO New England transmission owners, FERC issued an order proposing a new methodology for determining (i) when an existing ROE is no longer just and reasonable, and (ii) the regional base ROE if an existing ROE is found to no longer be just and reasonable. If finalized, this proposed methodology will be used to address ROE complaints currently pending before FERC, including ITC's outstanding ROE complaints.

Central Hudson

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

FortisAlberta

Generic Cost of Capital Proceeding: Oral hearings to determine the ROE and capital structure for 2018, 2019 and 2020 were completed in March 2018. In August 2018 the Alberta Utilities Commission ("AUC"), approved an allowed ROE of 8.50% on a capital structure of 37% common equity for 2018, 2019 and 2020, unchanged from 2017.

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

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

MANAGEMENT DISCUSSION AND ANALYSIS 12 September 30, 2018

CONSOLIDATED FINANCIAL POSITION

Significant Changes in the Consolidated Balance Sheets between September 30, 2018 and December 31, 2017
Balance Sheet Account	Increase/ (Decrease) (1) ($ millions)	Explanation
Cash and cash equivalents	(132)	The decrease was mainly due to the timing of transmission cost payments at FortisAlberta and a debt issuance at ITC in November 2017.
Property, plant and equipment, net	2,059	The increase was mainly due to capital expenditures, foreign exchange, and the recognition of a capital lease for Gila River generating station Unit 2 at UNS Energy, partially offset by depreciation.
Goodwill	295	The increase was due to foreign exchange.
Accounts payable and other current liabilities	(147)	The decrease was primarily due to the timing of the declaration of common share dividends and lower amounts owing for energy supply costs associated with the seasonality of operations. The decrease was partially offset by capital accruals mainly at UNS Energy and foreign exchange.
Regulatory liabilities (including current and long-term)	155	The increase was mainly due to the normal operation of rate stabilization accounts at ITC and foreign exchange.
Deferred income tax liabilities	235	The increase was mainly due to timing differences related to capital expenditures at the regulated utilities and foreign exchange.
Long-term debt (including current portion and short-term borrowings)	897	The increase was mainly due to the issuance of first mortgage bonds by ITC and debt issuances at other regulated utilities. The increase was also due to foreign exchange and higher net borrowings under committed credit facilities, partially offset by regularly scheduled debt repayments.
Capital lease and finance obligations (including current portion)	202	The increase was mainly due to UNS Energy's recognition of a capital lease for Gila River generating station Unit 2.
Shareholders' equity	981	The increase was due to: (i) net earnings attributable to common shareholders for the nine months ended September 30, 2018, less dividends declared on common shares; (ii) the increase in accumulated other comprehensive income associated with the translation of the Corporation's US dollar-denominated investments in subsidiaries, net of hedging activities and tax; and (iii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans.

⁽¹⁾  Includes the impact of foreign exchange based upon the closing foreign exchange rate at September 30,2018 of US$1.00=CAD$1.29 compared to the closing foreign exchange rate at December 31, 2017 of US$1.00=CAD$1.25.

MANAGEMENT DISCUSSION AND ANALYSIS 13 September 30, 2018

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CONSOLIDATED CASH FLOWS

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

Summary of Consolidated Cash Flows
Periods Ended September 30	Quarter						Year-to-Date
($ millions)	2018		2017		Variance		2018		2017		Variance
Cash, Beginning of Period	197		231		(34	)	327		269		58
Cash Provided by (Used in):
Operating Activities	796		800		(4	)	2,067		1,990		77
Investing Activities	(783	)	(683	)	(100	)	(2,253	)	(2,143	)	(110	)
Financing Activities	(12	)	(87	)	75		46		148		(102	)
Effect of Exchange Rate Changes on Cash and Cash Equivalents	(3	)	(9	)	6		8		(12	)	20
Cash, End of Period	195		252		(57	)	195		252		(57	)

Operating Activities

Cash provided by operating activities was comparable for the quarter.

The increase in cash provided by operating activities year to date was primarily due to favourable changes in working capital, mainly due to the payment of an ROE complaint refund in the first quarter of 2017 at ITC, and higher cash earnings, mainly due to warmer temperatures increasing energy consumption at UNS Energy in 2018, partially offset by lower receipts from operating revenue at U.S. subsidiaries as a result of U.S. tax reform.

Investing Activities

The increase in cash used in investing activities for the quarter and year to date was due to higher capital spending, primarily at UNS Energy.

Financing Activities

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

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

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 credit facility borrowings related to the financing of the ITC acquisition.

MANAGEMENT DISCUSSION AND ANALYSIS 14 September 30, 2018

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

Proceeds from Long-Term Debt, Net of Issue Costs
Periods Ended September 30	Quarter					Year-to-Date
($ millions)	2018		2017	Variance		2018	2017	Variance
ITC (1)	(3	)	—	(3	)	287	601	(314	)
Central Hudson (2)	—		75	(75	)	32	75	(43	)
FortisAlberta (3)	149		199	(50	)	149	199	(50	)
Newfoundland Power	—		—	—		—	75	(75	)
FortisOntario (4)	100		—	100		100	—	100
Caribbean Utilities	—		—	—		—	80	(80	)
FortisTCI (5)	7		—	7		37	—	37
Total	253		274	(21	)	605	1,030	(425	)

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

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

⁽³⁾  In September 2018 FortisAlberta issued 30-year $150 million unsecured debentures at 3.73%. The net proceeds were used to repay credit facility borrowings and for general corporate purposes.

⁽⁴⁾  In August 2018 FortisOntario issued 30-year $100 million unsecured notes at 4.10%. The net proceeds were used to repay maturing long-term debt and for general corporate purposes.

⁽⁵⁾  In February 2018 FortisTCI issued 5-year US$25 million unsecured notes at a floating interest rate of a one-month LIBOR plus a spread of 1.75%. In September 2018 FortisTCI entered into a 7-year US$10 million unsecured non-revolving term loan credit agreement with a floating interest rate of a one‑month LIBOR plus a spread of 1.75%. As at September 30, 2018, borrowings under the term loan credit agreement were US$5 million. The net proceeds were used to repay a hurricane-related emergency standby loan and for general corporate purposes.

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 third quarter of 2018 totalled $110 million, net of $71 million of dividends reinvested, compared to $106 million, net of $61 million of dividends reinvested, paid in the third quarter of 2017. Common share dividends paid year-to-date 2018 were $340 million, net of $200 million of dividends reinvested, compared to $308 million, net of $186 million of dividends reinvested, paid year-to-date 2017. The dividend paid per common share for each of the first, second and third quarters of 2018 was $0.425 compared to $0.40 for the same periods in 2017. The weighted average number of common shares outstanding for the third quarter and year-to-date of 2018 was 425.6 million and 423.8 million, respectively, compared to 418.6 million and 413.9 million for the same periods in 2017.

On October 15, 2018, Fortis declared a dividend of $0.45 per common share payable on December 1, 2018.

On October 29, 2018, Central Hudson issued 8-year US$40 million unsecured notes at 3.99% and 15-year US$40 million unsecured notes at 4.21%. The net proceeds will be used to repay maturing long-term debt and for general corporate purposes.

On November 1, 2018, ITC issued 33-year US$162 million first mortgage bonds at 4.32% and expects to issue an additional US$13 million in early November. The net proceeds will be used to repay credit facility borrowings, finance capital expenditures and for general corporate purposes.

MANAGEMENT DISCUSSION AND ANALYSIS 15 September 30, 2018

CONTRACTUAL OBLIGATIONS

There were no material changes in contractual obligations from that disclosed in the Corporation's 2017 Annual MD&A, except issuances of long-term debt stated above and other items as follows.

In March 2018 Maritime Electric extended its power purchase agreement with New Brunswick Power from March 2019 to February 2024, increasing the total commitment under this agreement by approximately$262 million as at September 30, 2018.

In May 2018, following the acquisition of Gila River generating station Units 1 and 2 by a third party with whom UNS Energy has a power purchase agreement, UNS Energy recorded an increase of US$164 millionto capital lease obligations to reflect the anticipated exercising of UNS Energy's option to purchase Unit 2 in December 2019.

CAPITAL STRUCTURE

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

The consolidated capital structure of Fortis is presented below.

Capital Structure	As at
	September 30, 2018		December 31, 2017
	($ millions)	(%)	($ millions)	(%)
Total debt and capital lease and finance obligations (net of cash) (1)	22,970	59.0	21,739	59.2
Preference shares	1,623	4.2	1,623	4.4
Common shareholders' equity	14,361	36.8	13,380	36.4
Total	38,954	100.0	36,742	100.0

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

Including amounts related to non-controlling interests, the Corporation's capital structure as at September 30, 2018 was 56.3% total debt and capital lease and finance obligations (net of cash), 4.0% preference shares, 35.2% common shareholders' equity and 4.5% non-controlling interests (December 31, 2017 - 56.5% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 34.8% common shareholders' equity and 4.5% non-controlling interests).

CREDIT RATINGS

As at September 30, 2018, the Corporation's credit ratings were as follows.

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

The above-noted credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company.

MANAGEMENT DISCUSSION AND ANALYSIS 16 September 30, 2018

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

In July 2018 Moody's revised its outlook on Central Hudson from stable to negative due to the impacts of U.S. tax reform and higher capital expenditures.

CAPITAL EXPENDITURE PLAN

A breakdown of the consolidated capital expenditures by reporting segment is provided below.

Consolidated Capital Expenditures (1)
Year-to-date September 30, 2018
($ millions)
	Regulated
								Total
		UNS	Central	FortisBC	Fortis	FortisBC	Other	Regulated	Non-
	ITC	Energy	Hudson	Energy	Alberta	Electric	Electric	Utilities	Regulated (2)	Total
Total	717	419	175	318	325	81	193	2,228	37	2,265

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

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

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

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

Approximately $460 million, including AFUDC and development costs, has been invested in the Tilbury LNG facility expansion, in British Columbia, to the end of the third quarter of 2018. The total cost of the project is estimated at approximately $470 million, including approximately $70 million of AFUDC and development costs, and includes a new LNG storage tank and liquefier. The commissioning process of the facility was interrupted in the third quarter of 2017. The restart of commissioning has begun with LNG production anticipated in the fourth quarter of 2018. Subject to the commissioning and LNG production going as planned, the project will be completed in 2019.

FortisBC Energy’s Lower Mainland System Upgrade project is designed to address system capacity and pipeline condition issues for the gas supply system in the Lower Mainland area of British Columbia. The project is being completed in two phases: (i) the Coastal Transmission System ("CTS") phase, which increases security of supply; and (ii) the Lower Mainland Intermediate Pressure System Upgrade ("LMIPSU") phase, which is focused on addressing pipeline condition issues. Construction activities for the CTS phase are complete, and the new pipelines have been commissioned and are in-service. FortisBC Energy conducted further detailed engineering work and evaluated construction bids and other costs which resulted in a revised cost estimate for the LMIPSU. The LMIPSU is expected to be constructed primarily during 2018 and 2019. The total capital cost of both phases of the Lower Mainland System Upgrade is now estimated to be approximately $640 million.

MANAGEMENT DISCUSSION AND ANALYSIS 17 September 30, 2018

Five-Year Capital Program

Over the five-year period from 2019 through 2023 (“five-year capital program”), consolidated capital expenditures are expected to be approximately $17.3 billion, $2.8 billion higher than the $14.5 billion disclosed in the 2017 Annual MD&A for the period from 2018 through 2022. The improvement in the five-year capital program is the result of the Corporation’s sustainable organic growth platform, the inclusion of Fortis’ effective investment in the Wataynikaneyap Transmission Power Project, and reflects increased investment in grid modernization, renewables, and natural gas infrastructure primarily at ITC, UNS Energy and FortisBC Energy, respectively. The low-risk, highly executable five-year capital program is virtually all occurring at the regulated utility businesses and contains only a small number of major projects.

The Wataynikaneyap Transmission Power Project will connect 17 remote First Nations communities in Northwestern Ontario to the main electricity grid through construction of 1,800 kilometres of transmission lines. Wataynikaneyap Power is a licensed transmission company, regulated by the Ontario Energy Board ("OEB"), equally owned by 22 First Nations communities (51%), in partnership with Fortis (49%). In 2016 the Government of Ontario designated Wataynikaneyap Power as the licensed transmission company to complete this project. In 2017 the OEB approved a deferral account to recover development costs incurred between November 2010 and the commencement of construction. In March 2018 the project reached a significant milestone with the formal announcement of a funding framework among Wataynikaneyap Power, the Government of Canada and the Government of Ontario. FortisOntario will be responsible for construction management and operation of the transmission line.

The total estimated capital cost for the Wataynikaneyap Transmission Power Project is approximately $1.6 billion. The initial phase of the project to connect the Pikangikum First Nation to Ontario’s power grid is fully funded by the Canadian government and is expected to be completed by the end of 2018. The next two phases are subject to receipt of all necessary regulatory approvals, including the leave-to-construct approval from the OEB. The leave-to-construct application was filed with the OEB in June 2018 and approval is expected in early 2019. These phases are targeted to be completed by the end of 2020 and 2023, respectively. In addition to providing participating First Nations communities ownership in the transmission line, the project provides socio-economic benefits, reduces environmental risk and lessens greenhouse gas emissions associated with diesel-fired generation currently used in remote locations.

At ITC, the five-year capital program has increased by approximately $900 million. The increase is driven by infrastructure investments for reliability improvements, increased capacity needs and new interconnections in support of economic development and changes in generation sources.

The five-year capital program includes two new major capital projects at UNS Energy. The Southline Transmission Project is a 600MW transmission line designed to collect and transmit electricity across southern New Mexico and southern Arizona. UNS Energy expects to purchase a 250MW ownership in the project. Construction is expected to commence in 2019, with completion expected in 2021. The capital cost of the Southline Transmission Project for UNS Energy is estimated at approximately $390 million (US$304 million). The transmission line will improve reliability in the region and facilitate the connection of renewable energy resources to the grid, including a New Mexico Wind Project.

The New Mexico Wind Project is a 750MW wind power generating plant that will be interconnected to the Southline Transmission line and complements UNS Energy’s existing renewable solar generation portfolio. UNS Energy will have a 150MW ownership under a build-transfer asset contract, with an option to purchase additional ownership in the future. Construction is expected to commence in 2018, with completion expected in 2020. The capital cost of the project for UNS Energy is estimated at approximately $280 million (US$217 million).

The five-year capital program also includes $220 million associated with a multi-year Inland Gas Upgrades Project at FortisBC Energy. The project will provide gas line modifications and replacements enabling in-line inspection capabilities, a key tool to confirm the integrity of transmission gas lines. A Certificate of Public Convenience and Necessity (“CPCN”) application is expected to be filed with the British Columbia Utilities Commission in the fourth quarter of 2018 and approval is expected in the second half of 2019. Subject to the CPCN approval, construction of the project is expected to commence in 2020.

Also included in the five-year capital program is approximately $570 million associated with a multi-year Transmission Integrity Management Capabilities Project at FortisBC Energy, an increase of approximately $260 million from the amount disclosed in the 2017 Annual MD&A. The project is focused on improving gas line safety and the integrity of the high-pressure transmission system, including gas line modifications and looping.

MANAGEMENT DISCUSSION AND ANALYSIS 18 September 30, 2018

The five-year capital program is expected to be funded with cash from operations, debt raised at the utilities and common equity from the Corporation's dividend reinvestment plan. The remaining funds required to finance the increased growth in regulated assets are expected to be generated from asset sales, with approximately $1 billion to $2 billion of proceeds expected over the five-year planning period. The Corporation's at-the-market common equity program will also be available to provide further financing flexibility.

ADDITIONAL INVESTMENT OPPORTUNITIES

Management is pursuing additional investment opportunities within existing service territories. These additional investment opportunities, as discussed below, are not included in the Corporation’s base five-year capital program.

ITC - Lake Erie Connector

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

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

FortisBC - Liquefied Natural Gas

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

Other Opportunities

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

CASH FLOW REQUIREMENTS

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

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

MANAGEMENT DISCUSSION AND ANALYSIS 19 September 30, 2018

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

In November 2016 Fortis filed a short-form base shelf prospectus, under which the Corporation may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $5 billion during the 25-month life of the base shelf prospectus. In March 2018 the Corporation established an at-the-market common equity program that allows the Corporation to issue up to $500 million of common shares from treasury to the public at the Corporation's discretion, effective until December 2018. In July 2017 Fortis exchanged its US$2.0 billion ($2.6 billion) unregistered senior unsecured notes for US$2.0 billion ($2.6 billion) registered senior unsecured notes under the base shelf prospectus. In March 2017 Fortis issued $500 million common equity and in December 2016 issued $500 million unsecured notes at 2.85%, both under the base shelf prospectus. A principal amount of approximately $1.0 billion remains under the base shelf prospectus.

As at September 30, 2018, management expects consolidated fixed-term debt maturities and repayments to average approximately $759 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 September 30, 2018 and are expected to remain compliant throughout 2018.

CREDIT FACILITIES

As at September 30, 2018, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.0 billion, of which approximately $3.9 billion was unused, including $1.1 billion unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $4.8 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2023.

Credit facilities are summarized below.

Credit Facilities					As at
	Regulated Utilities		Corporate and Other		September 30,2018		December 31, 2017
($ millions)
Total credit facilities	3,648		1,385		5,033		4,952
Credit facilities utilized:
Short-term borrowings	(37	)	(2	)	(39	)	(209	)
Long-term debt (including current portion) (1)	(762	)	(236	)	(998	)	(671	)
Letters of credit outstanding	(69	)	(55	)	(124	)	(129	)
Credit facilities unutilized	2,780		1,092		3,872		3,943

⁽¹⁾  The current portion was $552 million (December 31, 2017 - $312 million).

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

MANAGEMENT DISCUSSION AND ANALYSIS 20 September 30, 2018

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $124 million as at September 30, 2018 (December 31, 2017 - $129 million), the Corporation had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.

BUSINESS RISK MANAGEMENT

Business risks of the Corporation were generally consistent with those disclosed in the Corporation's 2017 Annual MD&A. Updates to regulatory risk and credit ratings are provided in the "Regulatory Highlights" and "Credit Ratings" sections of this MD&A.

CHANGES IN ACCOUNTING POLICIES

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

Revenue

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

Most of the Corporation's revenue is derived from energy sales and the provision of transmission services to customers based on regulator-approved tariff rates. Most contracts have a single performance obligation, being the delivery of energy or the provision of transmission services. Revenue is generally measured in kilowatt hours, gigajoules, or transmission load delivered. The billing of energy sales is based on customer meter readings, which occur systematically throughout each month. The billing of transmission services at ITC is based on peak monthly load.

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

Electricity, gas and transmission service revenue includes an unbilled revenue estimate for energy consumed or services provided since the last meter reading that have not been billed at the end of the accounting period. Sales estimates generally reflect an analysis of historical consumption in relation to key inputs, such as current energy prices, population growth, economic activity, weather conditions and system losses. Unbilled revenue accruals are adjusted in the periods actual consumption becomes known.

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

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

The Corporation's revenue excludes sales and municipal taxes collected from customers. Prior to the adoption of ASC Topic 606, Central Hudson recognized sales tax and FortisAlberta recognized municipal tax on a gross basis, in both revenue and expense. Effective January 1, 2018, the exclusion of these taxes from revenue resulted in a decrease in revenue of$12 million and $38 millionfor the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017.

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

MANAGEMENT DISCUSSION AND ANALYSIS 21 September 30, 2018

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

Financial Instruments

Effective January 1, 2018, the Corporation adopted Accounting Standards Update ("ASU") No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities. Principally, it requires: (i) equity investments in unconsolidated entities not accounted for using the equity method to be measured at fair value through earnings; however, entities may elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and liabilities to be presented separately in the financial statement notes, grouped by measurement category and form. Adoption of this ASU did not impact the Interim Financial Statements.

Pension and Postretirement Benefit Costs

Effective January 1, 2018, the Corporation adopted ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, which requires current service costs to be disaggregated and grouped in the statement of earnings with other employee compensation costs arising from services rendered. The other components of net periodic benefit costs must be presented separately and outside of operating income. Additionally, only the service cost component is eligible for capitalization. On adoption, the Corporation applied the presentation guidance retrospectively and the capitalization guidance prospectively. This resulted in a retrospective $1 million and $8 million reclassification from Operating Expenses to Other Income, Net for the three and nine months ended September 30, 2017, respectively, in the Interim Financial Statements.

FUTURE ACCOUNTING PRONOUNCEMENTS

Leases

ASU No. 2016-02, Leases (ASC Topic 842), issued in February 2016, is effective for Fortis January 1, 2019 with earlier adoption permitted, and is to be applied using a modified retrospective approach or an optional transition method with implementation options, referred to as practical expedients. Principally, it requires balance sheet recognition of a right-of-use asset and a lease liability by lessees for those leases that are classified as operating leases along with additional disclosures.

Fortis plans to select the optional transition method which allows entities to continue to apply the current lease guidance in the comparative periods presented in the year of adoption and apply the transition provisions of the new guidance on the effective date of the new guidance. Fortis will elect a package of practical expedients that allows it to not reassess whether any expired or existing contract is a lease or contains a lease, the lease classification of any expired or existing leases, and the initial direct costs for any existing leases. Fortis also will elect an additional practical expedient that permits entities to not evaluate existing land easements that were not previously accounted for as leases.

Based on Fortis' assessment to date, leasing activities accounted for as operating leases primarily relate to office facilities and utility property. Ongoing implementation efforts include the evaluation of business processes and controls to support recognition under the new standard and preparation of expanded disclosures. Fortis continues to assess the impact of adoption and monitor standard-setting activities that may affect transition requirements.

Hedging

ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, issued in August 2017, is effective for Fortis January 1, 2019 with earlier adoption permitted and is to be applied as of the beginning of the fiscal year of adoption. Principally, it better aligns risk management activities and financial reporting for hedging relationships through changes to designation, measurement, presentation and disclosure guidance. For cash flow and net investment hedges existing at the date of adoption, the amendments should be applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to opening retained earnings. Amended presentation and disclosure guidance is to be applied prospectively. The adoption of this ASU will not have a material impact on the consolidated financial statements and related disclosures.

MANAGEMENT DISCUSSION AND ANALYSIS 22 September 30, 2018

Financial Instruments

ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, issued in June 2016, is effective for Fortis January 1, 2020 and is to be applied on a modified retrospective basis. Principally, it requires entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to estimate credit losses. The adoption of this ASU will not have a material impact on the consolidated financial statements and related disclosures.

FINANCIAL INSTRUMENTS

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

As at September 30, 2018, the carrying value of long-term debt, including current portion, was $22,599 million (December 31, 2017 - $21,535 million) compared to an estimated fair value of $23,540 million (December 31, 2017 - $23,481 million).

The fair value of long-term debt is calculated using quoted market prices or, when unavailable, by either: (i) discounting the associated future cash flows 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 prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.

Derivative Instruments

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

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

CRITICAL ACCOUNTING ESTIMATES

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

There were no material changes in the nature of the Corporation's critical accounting estimates from those disclosed in the 2017 Annual MD&A.

Contingencies

There were no material changes in the Corporation's contingencies from those disclosed in the 2017 Annual MD&A.

MANAGEMENT DISCUSSION AND ANALYSIS 23 September 30, 2018

Comparative Figures in the Consolidated Statement of Cash Flows

During the year ended December 31, 2017, the Corporation discovered an immaterial error with respect to the presentation of credit facility borrowings within the financing section of its statement of cash flows. The Corporation evaluated the error and determined that there was no impact to its results of operations or financial position in previously issued financial statements and that the impact was not material to its cash flows in previously issued financial statements. For the three and nine months ended September 30, 2017, the correction resulted in $11 million and $234 million, respectively, which was previously reported within Net Repayments/Borrowings under Committed Credit Facilities, now being reported on a gross basis as Borrowings under Committed Credit Facilities of $659 million and $1,466 million, respectively, and Repayments under Committed Credit Facilities of $648 million and $1,700 million, respectively.

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

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

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

RELATED-PARTY AND INTER-COMPANY TRANSACTIONS

Related-party transactions are in the normal course of operations and are measured at the amount of consideration agreed to by the related parties. There were no material related-party transactions for the three and nine months ended September 30, 2018 and 2017.

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

Inter-Company Transactions
Periods Ended September 30	Quarter		Year-to-Date
($ millions)	2018	2017	2018	2017
Sale of capacity from Waneta Expansion to FortisBC Electric	12	11	31	30
Sale of energy from Belize Electric Company Limited to BEL	8	11	26	25
Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy	6	5	19	18

As at September 30, 2018, accounts receivable included approximately $16 million due from BEL (December 31, 2017 - $20 million).

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

MANAGEMENT DISCUSSION AND ANALYSIS 24 September 30, 2018

SUMMARY OF QUARTERLY RESULTS

Quarterly information has been obtained from the Corporation's Interim Financial Statements and is provided below. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.

Summary of Quarterly Results		Net Earnings
		Attributable to
		Common Equity
	Revenue	Shareholders	Earnings per Common Share
Quarter Ended	($ millions)	($ millions)	Basic ($)	Diluted ($)
September 30, 2018	2,040	276	0.65	0.65
June 30, 2018	1,947	240	0.57	0.57
March 31, 2018	2,197	323	0.77	0.76
December 31, 2017	2,111	134	0.32	0.31
September 30, 2017	1,901	278	0.66	0.66
June 30, 2017	2,015	257	0.62	0.62
March 31, 2017	2,274	294	0.72	0.72
December 31, 2016	2,053	189	0.49	0.49

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

September 2018/September 2017: Net earnings attributable to common equity shareholders were $276 million, or $0.65 per common share, for the third quarter of 2018 compared to earnings of $278 million or $0.66 per common share, for the third quarter of 2017. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.

June 2018/June 2017: Net earnings attributable to common equity shareholders were $240 million, or $0.57 per common share, for the second quarter of 2018 compared to earnings of $257 million, or $0.62 per common share, for the second quarter of 2017. The decrease in earnings was primarily due to: (i) lower earnings from Aitken Creek related to unrealized net losses on the mark-to-market of natural gas derivatives quarter over quarter; (ii) the impact of U.S. tax reform; (iii) unfavourable foreign exchange; and (iv) the favourable settlement of matters at UNS Energy pertaining to FERC-ordered transmission refunds in 2017. The decrease was partially offset by the settlement of FortisTCI's business interruption insurance claim, related to the impact of Hurricane Irma, and growth in rate base.

March 2018/March 2017: Net earnings attributable to common equity shareholders were $323 million, or $0.77 per common share, for the first quarter of 2018 compared to earnings of $294 million, or $0.72 per common share, for the first quarter of 2017. The increase in earnings was primarily due to: (i) the one-time remeasurement of the Corporation's deferred income tax liabilities as a result of an election to file a consolidated state income tax return; (ii) the impact of a full quarter of new rates compared to last year at UNS Energy; and (iii) growth in rate base. The increase was partially offset by: (i) unfavourable foreign exchange; (ii) lower earnings from Aitken Creek related to unrealized net losses on the mark-to-market of natural gas derivatives quarter over quarter; (iii) timing differences at Newfoundland Power; and (iv) the favourable settlement of matters at UNS Energy pertaining to FERC-ordered transmission refunds of $7 million in 2017.

MANAGEMENT DISCUSSION AND ANALYSIS 25 September 30, 2018

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

OUTLOOK

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

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

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

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

OUTSTANDING SHARE DATA

As at November 1, 2018, the Corporation had issued and outstanding 426.6 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. 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 November 1, 2018 is approximately 4.1 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 26 September 30, 2018