Fortis (FTS) 6-K Fortis Inc. Reports Third Quarter 2019 EARNINGS1

Exhibit 99.3

Interim Management Discussion and Analysis

For the three and nine months ended September 30, 2019

Dated October 31, 2019

TABLE OF CONTENTS
Corporate Overview	1	Liquidity and Capital Resources	11
Significant Item	2	Cash Flow Requirements	11
Performance Overview	2	Cash Flow Summary	12
Business Unit Performance	3	Contractual Obligations	14
ITC	4	Capital Structure and Credit Ratings	15
UNS Energy	4	Capital Expenditure Plan	15
Central Hudson	5	Business Risk Management	17
FortisBC Energy	6	Off-Balance Sheet Arrangements	17
FortisAlberta	6	Financial Instruments	17
FortisBC Electric	7	Related-Party and Inter-Company Transactions	17
Other Electric	7	Summary of Quarterly Results	18
Energy Infrastructure	8	Critical Accounting Estimates	19
Corporate and Other	8	Accounting Policy Changes	19
Non-US GAAP Financial Measures	9	Future Accounting Pronouncements	19
Regulatory Developments	9	Outlook	20
Consolidated Financial Position	10	Forward-Looking Information	20
		Condensed Consolidated Interim Financial Statements (Unaudited)	F-1

This 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, 2019 ("Interim Financial Statements") and the audited consolidated financial statements and notes thereto and MD&A for the year ended December 31, 2018. 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 in this MD&A by reference.

Financial information herein has been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP"), except for indicated non-US GAAP financial measures, and, unless otherwise specified, is presented in Canadian dollars based, as applicable, on the following Canadian-to-US dollar exchange rates: (i) average of 1.32 and 1.31 for the quarters ended September 30, 2019 and 2018, respectively; (ii) average of 1.33 and 1.29 year-to-date September 30, 2019 and 2018, respectively; (iii) 1.32 and 1.29 as at September 30, 2019 and 2018, respectively; and (iv) 1.36 as at December 31, 2018.

CORPORATE OVERVIEW

Fortis is a leader in the North American regulated electric and gas utility industry, with 2018 revenue of $8.4 billion and total assets of approximately $53 billion as at September 30, 2019. The Corporation's 8,800 employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries. Fortis shares are listed on the Toronto and New York Stock Exchanges under the symbol FTS.

For additional information on the Corporation's operations, reportable segments and strategy, refer to the "Corporate Overview" and "Corporate Strategy" sections of the Corporation's 2018 annual MD&A and Note 1 to the Interim Financial Statements.

MANAGEMENT DISCUSSION AND ANALYSIS
1
September 30, 2019

SIGNIFICANT ITEM

On April 16, 2019, Fortis sold its 51% ownership interest in the 335-megawatt ("MW") Waneta expansion hydroelectric generating facility ("Waneta Expansion") for proceeds of $995 million. A gain on disposition of $577 million ($484 million after tax), net of expenses, was recognized in the Corporate and Other segment.

Fortis used the proceeds from the disposition of the Waneta Expansion to repay credit facility borrowings and repurchase, via a tender offer, US$400 million of its outstanding 3.055% unsecured senior notes due in 2026. The reduced earnings from the Waneta Expansion were offset by lower finance charges and a gain on repayment of Corporate debt.

PERFORMANCE OVERVIEW

Key Financial Metrics
Periods Ended September 30	Quarter				Year-to-Date
($ millions, except as indicated)	2019	2018	Variance		2019	2018	Variance
Revenue	2,051	2,040	11		6,457	6,184	273
Net Earnings Attributable to Common Equity Shareholders
Actual	278	276	2		1,309	839	470
Adjusted (1)	287	277	10		838	825	13
Earnings per Common Share ($)
Basic	0.64	0.65	(0.01	)	3.02	1.98	1.04
Diluted	0.63	0.65	(0.02	)	3.02	1.98	1.04
Adjusted (1)	0.66	0.65	0.01		1.93	1.95	(0.02	)
Dividends Paid per Common Share ($)	0.450	0.425	0.025		1.350	1.275	0.075
Weighted Average Number of Common Shares Outstanding (# millions)	437.4	425.6	11.8		433.3	423.8	9.5
Cash Flow from Operating Activities	857	796	61		2,029	2,067	(38	)
Capital Expenditures	1,013	788	225		2,596	2,265	331

⁽¹⁾ See "Non-US GAAP Financial Measures" on page 9.

Revenue

The $11 million and $273 million increases in revenue for the quarter and year to date, respectively, were due primarily to: (i) favourable foreign exchange of $14 million and $113 million, respectively; (ii) rate base growth at the regulated utilities, led by ITC; (iii) overall higher flow-through costs in customer rates; and (iv) higher short-term wholesale sales at UNS Energy due to increased system capacity. These increases were partially offset by lower revenue contribution from the Energy Infrastructure segment due primarily to the disposition of the Waneta Expansion and lower hydroelectric production in Belize due to rainfall levels. Lower market pricing on short-term wholesale sales and lower retail sales due to weather, both at UNS Energy, also unfavourably impacted revenue for the quarter and year to date, respectively.

Earnings

The $2 million increase in net earnings attributable to common equity shareholders ("Common Equity Earnings") for the quarter was due primarily to rate base growth at the regulated utilities, led by ITC. The increase was tempered by: (i) the unfavourable impact of the mark-to-market accounting of natural gas derivatives at the Aitken Creek natural gas storage facility ("Aitken Creek"); and (ii) lower hydroelectric production in Belize.

The $470 million increase in Common Equity Earnings year to date was due primarily to: (i) a $484 million gain on the disposition of the Waneta Expansion; (ii) rate base growth at the regulated utilities, led by ITC; and (iii) favourable foreign exchange of $18 million. The increase was tempered by: (i) lower earnings contribution from the Energy Infrastructure segment due to lower hydroelectric production in Belize and lower realized margins at Aitken Creek; (ii) a one-time $30 million favourable remeasurement of deferred income tax liabilities in the Corporate and Other segment in the first quarter of 2018 as a result of an election to file a consolidated state income tax return; and (iii) lower earnings contribution from UNS Energy due to lower retail sales, driven by weather, and higher depreciation and interest expense.

MANAGEMENT DISCUSSION AND ANALYSIS
2
September 30, 2019

These results together with an increase in the weighted average number of common shares outstanding, associated with the Corporation's at-the-market common equity program ("ATM Program") and dividend reinvestment and share purchase plans, resulted in a decrease in basic earnings per common share ("EPS") of $0.01 for the quarter and an increase in basic EPS of $1.04 year to date. See "Cash Flow Requirements" on page 11 for further information about the ATM Program.

Adjusted Common Equity Earnings and adjusted basic EPS, which exclude the noted gain on disposition of the Waneta Expansion, the one-time 2018 remeasurement of deferred income tax liabilities and the mark-to-market accounting of Aitken Creek derivatives, increased by $10 million and $0.01, respectively, for the quarter. Adjusted basic EPS decreased by $0.02 year to date due primarily to the impact of weather in Arizona and Belize.

Dividends

Dividends paid per common share in the third quarter and year-to-date 2019 were $0.45 and $1.35, respectively, up 6% from the same periods last year. In September 2019 the Corporation announced a fourth quarter common share dividend of $0.4775, up 6.1% from its third quarter common share dividend. This marked the Corporation's 46^th consecutive year of dividend increases. The Corporation has targeted average annual dividend per common share growth of approximately 6% through 2024.

Cash Flow from Operating Activities

Cash flow from operating activities increased $61 million for the quarter and decreased $38 million year to date compared to the same periods in 2018.

Cash flow from operating activities for the quarter and year to date reflects: (i) favourable net changes in working capital, due primarily to timing differences; and (ii) higher cash earnings, due primarily to rate base growth at the regulated utilities, particularly those in the U.S., partially offset by lower operating cash flows as a result of the disposition of the Waneta Expansion.

Net favourable working capital and cash earnings were, for the quarter, partially offset by timing differences in the recovery of regulatory deferrals and, for year to date, more than offset by such timing differences.

Capital Expenditures

Capital expenditures were $2.6 billion year-to-date 2019, up $0.3 billion compared to the same period last year and in line with the Corporation's annual $4.3 billion capital expenditure plan for 2019. See "Capital Expenditure Plan" on page 15 for further information.

BUSINESS UNIT PERFORMANCE

Segmented Common Equity Earnings
	Quarter								Year-to-Date
Periods Ended September 30					Variance							Variance
($ millions)	2019		2018		FX (1)		Other		2019	2018		FX (1)	Other
Regulated Utilities
ITC	107		97		1		9		300	269		9	22
UNS Energy	139		135		1		3		254	266		6	(18	)
Central Hudson	16		17		—		(1	)	55	50		2	3
FortisBC Energy	(22	)	(22	)	—		—		88	83		—	5
FortisAlberta	37		39		—		(2	)	98	98		—	—
FortisBC Electric	11		12		—		(1	)	42	43		—	(1	)
Other Electric	32		30		1		1		84	83		1	—
Non-Regulated
Energy Infrastructure	(4	)	12		—		(16	)	12	50		—	(38	)
Corporate and Other	(38	)	(44	)	(1	)	7		376	(103	)	—	479
Common Equity Earnings	278		276		2		—		1,309	839		18	452

⁽¹⁾  FX means foreign exchange associated with the translation of U.S. dollar-denominated earnings and material U.S. dollar-denominated transactions at Corporate.

MANAGEMENT DISCUSSION AND ANALYSIS
3
September 30, 2019

ITC

Financial Highlights (1)	Quarter				Year-to-Date
Periods Ended September 30			Variance				Variance
($ millions)	2019	2018	FX	Other	2019	2018	FX	Other
Revenue	425	386	4	35	1,261	1,114	35	112
Earnings	107	97	1	9	300	269	9	22

⁽¹⁾  Revenue represents 100% of ITC. Earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflect consolidated purchase price accounting adjustments. The reporting currency of ITC is the US dollar.

Revenue

The increases in revenue, net of foreign exchange, for the quarter and year to date were due primarily to growth in rate base and higher flow-through costs in customer rates, partially offset by a reduction to the rate of return on common equity ("ROE") independence incentive adder.

Earnings

The increases in earnings, net of foreign exchange, for the quarter and year to date were due primarily to growth in rate base, partially offset by higher non-recoverable operating expenses and the decrease in the ROE independence incentive adder. Earnings were also favourably impacted by a lower effective tax rate.

UNS ENERGY

Financial Highlights (1)	Quarter					Year-to-Date
Periods Ended September 30			Variance					Variance
	2019	2018	FX	Other		2019	2018	FX	Other
Retail electricity sales (GWh)(2)	3,495	3,495	—	—		8,208	8,375	—	(167	)
Wholesale electricity sales (GWh)(2) (3)	2,161	1,861	—	300		6,109	4,280	—	1,829
Gas volumes (PJ) (2)	2	1	—	1		11	8	—	3
Revenue ($ millions)	659	687	7	(35	)	1,702	1,661	47	(6	)
Earnings ($ millions)	139	135	1	3		254	266	6	(18	)

⁽¹⁾  Includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. and UNS Gas, Inc. The reporting currency of UNS Energy is the US dollar.

⁽²⁾  GWh means gigawatt hours and PJ means petajoules.

⁽³⁾  Primarily comprised of short-term wholesale sales.

Electricity Sales and Gas Volumes

Retail electricity sales for the quarter were comparable with the same period in 2018. The decrease year to date was due to reduced air conditioning load as a result of colder-than-normal temperatures in 2019 compared to warmer-than-normal temperatures for the same period in 2018. Temperatures recorded in Tucson for the second quarter of 2019 were the lowest in the past 20 years.

The increases in wholesale electricity sales for the quarter and year to date were due primarily to higher short-term wholesale sales reflecting an increase in system capacity related to Gila River generating station Unit 2. Revenue from short-term wholesale sales is primarily returned to customers through regulatory deferral mechanisms and, therefore, does not materially impact earnings.

Gas volumes for the quarter were comparable with the same period in 2018. Increased gas volumes year to date were due primarily to heating load as a result of cooler temperatures in the winter months.

Revenue

The decrease in revenue, net of foreign exchange, for the quarter was due primarily to the flow through of lower energy supply costs and an overall decrease in short-term wholesale revenue due to lower market pricing. The decrease was partially offset by higher flow-through costs related to Springerville Units 3 and 4 and higher revenue related to the recovery of non-fuel costs through the normal operation of regulatory mechanisms.

MANAGEMENT DISCUSSION AND ANALYSIS
4
September 30, 2019

The decrease in revenue, net of foreign exchange, year to date was due primarily to the flow through of lower energy supply costs and lower retail sales. The decrease in revenue was partially offset by higher short-term wholesale sales, tempered by lower market pricing in the third quarter, and higher flow-through costs related to Springerville Units 3 and 4.

Earnings

The increase in earnings, net of foreign exchange, for the quarter was due primarily to higher revenue related to the recovery of non-fuel costs, noted above, partially offset by higher depreciation and interest expense resulting from rate base growth not yet reflected in customer rates.

The decrease in earnings, net of foreign exchange, year to date was due primarily to lower retail sales and the noted increase in depreciation and interest expense.

CENTRAL HUDSON

Financial Highlights (1)	Quarter					Year-to-Date
Periods Ended September 30			Variance					Variance
	2019	2018	FX	Other		2019	2018	FX	Other
Electricity sales (GWh)	1,374	1,416	—	(42	)	3,775	3,868	—	(93	)
Gas volumes (PJ)	3	4	—	(1	)	16	17	—	(1	)
Revenue ($ millions)	215	214	2	(1	)	691	690	24	(23	)
Earnings ($ millions)	16	17	—	(1	)	55	50	2	3

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

Electricity Sales and Gas Volumes

The decreases in electricity sales for the quarter and year to date were due primarily to lower average consumption as a result of warmer temperatures decreasing heating load and cooler temperatures decreasing air conditioning load. Gas volumes were comparable to 2018.

Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, therefore, do not materially impact earnings.

Revenue

The decreases in revenue, net of foreign exchange, for the quarter and year to date were due primarily to the flow through of lower energy supply costs and lower electricity sales. The decreases were partially offset by an increase in electricity and gas delivery rates effective July 1, 2018 and July 1, 2019, reflecting a return on increased rate base assets as well as the recovery of higher operating and finance expenses. The increase in delivery rates also reflects a rate design change that provides more revenue and earnings in higher gas consumption periods. See "Summary of Quarterly Results" on page 18 for further information on seasonality of the business.

Earnings

The decrease in earnings, net of foreign exchange, for the quarter primarily reflects the timing of operating expenses, partially offset by the increase in delivery rates effective July 1, 2019.

The increase in earnings, net of foreign exchange, year to date was primarily due to the increase in delivery rates effective July 1, 2018 and July 1, 2019 and higher storm restoration costs in 2018. The increase was partially offset by the timing of operating expenses and the rate design change.

MANAGEMENT DISCUSSION AND ANALYSIS
5
September 30, 2019

FORTISBC ENERGY

Financial Highlights	Quarter					Year-to-Date
Periods Ended September 30	2019		2018		Variance	2019	2018	Variance
Gas volumes (PJ)	33		30		3	156	149	7
Revenue ($ millions)	183		161		22	903	816	87
(Loss) earnings ($ millions)	(22	)	(22	)	—	88	83	5

Gas Volumes

The increases in gas volumes for the quarter and year to date were due primarily to higher consumption by transportation customers. Higher average residential and commercial consumption as a result of colder temperatures increasing heating load also contributed to the increase in gas volumes year to date.

Revenue

The increases in revenue for the quarter and year to date were due primarily to a higher cost of natural gas and other flow-through costs recovered from customers, the recovery of gas storage and transportation costs related to a third-party pipeline incident that occurred in the fourth quarter of 2018, and rate base growth.

Earnings

Earnings for the quarter were comparable with 2018 as the increase due to rate base growth was offset by the timing of operating expenses.

The increase in earnings year to date was due primarily to rate base growth, partially offset by higher operating expenses.

FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery. Due to regulatory deferral mechanisms, changes in consumption levels and commodity costs do not materially impact earnings.

FORTISALBERTA

Financial Highlights	Quarter				Year-to-Date
Periods Ended September 30	2019	2018	Variance		2019	2018	Variance
Energy deliveries (GWh)	3,997	4,240	(243	)	12,608	12,811	(203	)
Revenue ($ millions)	153	155	(2	)	448	439	9
Earnings ($ millions)	37	39	(2	)	98	98	—

Energy Deliveries

The decreases in energy deliveries for the quarter and year to date were due primarily to lower average consumption by oil and gas customers along with lower average residential consumption as a result of cooler temperatures decreasing air conditioning load. The decrease in energy deliveries year to date was partially offset by higher average commercial consumption due to customer additions.

As more than 80% of FortisAlberta's revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.

Revenue

The decrease in revenue for the quarter was due primarily to a favourable capital tracker revenue true-up in the third quarter of 2018 related to capital expenditures in 2016 and 2017, partially offset by rate base growth.

The increase in revenue year to date was due primarily to rate base growth and customer additions, partially offset by the 2018 capital tracker revenue true-up.

Earnings

The decrease in earnings for the quarter was due primarily to the 2018 capital tracker revenue true-up, partially offset by overall lower operating expenses.

Earnings year to date were comparable with 2018 as the decrease due to the 2018 capital tracker revenue true-up was offset by overall lower operating expenses.

MANAGEMENT DISCUSSION AND ANALYSIS
6
September 30, 2019

FORTISBC ELECTRIC

Financial Highlights	Quarter				Year-to-Date
Periods Ended September 30	2019	2018	Variance		2019	2018	Variance
Electricity sales (GWh)	764	769	(5	)	2,438	2,411	27
Revenue ($ millions)	97	96	1		306	297	9
Earnings ($ millions)	11	12	(1	)	42	43	(1	)

Electricity Sales

The decrease in electricity sales for the quarter was due primarily to lower average consumption as a result of cooler temperatures decreasing air conditioning load, partially offset by higher consumption by industrial customers.

The increase in electricity sales year to date was due primarily to higher consumption by industrial customers.

Revenue

The increases in revenue for the quarter and year to date were due primarily to overall higher flow-through costs, higher revenue related to a customer load growth regulatory mechanism, and higher third-party contract work. The increases were partially offset by the loss of revenue associated with the provision of operating, maintenance and management services to the Waneta Expansion. See "Significant Item" on page 2 for further information. Revenue for the quarter was also unfavourably impacted by lower surplus power sales.

Earnings

The decreases in earnings for the quarter and year to date were due to the loss of revenue associated with the Waneta Expansion, partially offset by rate base growth.

OTHER ELECTRIC

Financial Highlights (1)	Quarter					Year-to-Date
Periods Ended September 30			Variance					Variance
	2019	2018	FX	Other		2019	2018	FX	Other
Electricity sales (GWh)	1,782	1,797	—	(15	)	6,939	6,864	—	75
Revenue ($ millions)	317	307	1	9		1,086	1,040	7	39
Earnings ($ millions)	32	30	1	1		84	83	1	—

⁽¹⁾  Comprised of Newfoundland Power Inc.; Maritime Electric Company, Limited; FortisOntario Inc.; a 39% equity investment in Wataynikaneyap Power Limited Partnership ("Wataynikaneyap Power"); 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"). The reporting currency of Caribbean Utilities and FortisTCI is the US dollar. The reporting currency of BEL is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00.

Electricity Sales

The decrease in electricity sales for the quarter was due primarily to overall lower average consumption in Eastern Canada, partially offset by higher average consumption in the Caribbean.

The increase in electricity sales year to date was due primarily to overall higher average consumption and customer additions.

Revenue

The increase in revenue for the quarter, net foreign exchange, was due primarily to higher electricity sales in the Caribbean and higher energy supply costs flowed through to customers.

The increase in revenue year to date, net of foreign exchange, was due primarily to higher electricity sales and the flow through of higher energy supply costs, partially offset by Fortis TCI's business interruption insurance proceeds recognized in 2018 related to Hurricane Irma.

MANAGEMENT DISCUSSION AND ANALYSIS
7
September 30, 2019

Earnings

The increase in earnings for the quarter, net of foreign exchange, was due primarily to higher electricity sales in the Caribbean.

Earnings year to date, net of foreign exchange, were comparable with the same period in 2018. The increase in earnings due to higher electricity sales and rate base growth was offset by FortisTCI's insurance proceeds recognized in 2018.

ENERGY INFRASTRUCTURE

Financial Highlights (1)	Quarter					Year-to-Date
Periods Ended September 30	2019		2018	Variance		2019	2018	Variance
Energy sales (GWh)	11		151	(140	)	130	768	(638	)
Revenue ($ millions)	2		37	(35	)	63	134	(71	)
(Loss) earnings ($ millions)	(4	)	12	(16	)	12	50	(38	)

⁽¹⁾  Primarily comprised of long-term contracted generation assets in Belize, Aitken Creek in British Columbia and, until its April 16, 2019 disposition, the Waneta Expansion. See "Significant Item" on page 2 for further information.

Energy Sales

Energy sales decreased by 92 GWh and 509 GWh for the quarter and year to date, respectively, due to the disposition of the Waneta Expansion, with the remaining decrease due to lower hydroelectric production in Belize reflecting lower rainfall levels.

Revenue and Earnings

The decreases in revenue and earnings for the quarter and year to date reflect: (i) lower hydroelectric production in Belize; (ii) the disposition of the Waneta Expansion; and (iii) lower realized margins at Aitken Creek. Revenue and earnings variances for the quarter were also unfavourably impacted by the mark‑to‑market accounting of natural gas derivatives at Aitken Creek, with unrealized losses of $9 million this year compared to $1 million last year. Revenue and earnings variances year to date were favourably impacted by mark-to-market accounting with unrealized losses of $13 million this year compared to $16 million last year.

Aitken Creek is subject to commodity price risk, as it purchases and holds natural gas in storage to earn a profit margin from its ultimate sale. Aitken Creek mitigates this risk by using derivatives to materially lock in the profit margin that will be realized upon the sale of natural gas. The fair value accounting of these derivatives creates timing differences and the resultant earnings volatility can be significant.

CORPORATE AND OTHER

Financial Highlights (1)	Quarter							Year-to-Date
Periods Ended September 30					Variance						Variance
($ millions)	2019		2018		FX		Other	2019	2018		FX	Other
Net (expenses) income	(38	)	(44	)	(1	)	7	376	(103	)	—	479

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

The decrease in net expenses for the quarter was driven primarily by: (i) lower tax expense due to the timing of tax adjustments; and (ii) a reduction in finance charges due to the repayment of debt and credit facilities associated with the disposition of the Waneta Expansion. See "Significant Item" on page 2 for further information.

The year-to-date increase in net income was driven primarily by: (i) a net after-tax gain of $484 million on the disposition of the Waneta Expansion; and (ii) lower finance charges associated with the disposition along with a gain on the repayment of debt. The year-to-date increase was partially offset by lower income tax recovery due to a one-time $30 million favourable remeasurement of the Corporation's deferred income tax liabilities recognized during 2018 resulting from an election to file a consolidated state income tax return.

MANAGEMENT DISCUSSION AND ANALYSIS
8
September 30, 2019

NON-US GAAP FINANCIAL MEASURES

Fortis calculates adjusted Common Equity Earnings as Common Equity Earnings plus or minus items that management excludes in its key decision-making processes and evaluation of operating results. Adjusted basic EPS is calculated by dividing adjusted Common Equity Earnings by the weighted average number of common shares outstanding.

These financial measures do not have a standardized meaning prescribed by US GAAP and may not be comparable with similar measures of other entities. They are presented because management and external stakeholders use them in evaluating the Corporation's financial performance and prospects. The most directly comparable US GAAP measures are net earnings attributable to common equity shareholders (i.e. Common Equity Earnings) and basic EPS.

Non-US GAAP Reconciliation
Periods Ended September 30	Quarter			Year-to-Date
($ millions, except as indicated)	2019	2018	Variance	2019		2018		Variance
Common Equity Earnings	278	276	2	1,309		839		470
Adjusting Items:
Unrealized loss on mark-to-market of derivatives (1)	9	1	8	13		16		(3	)
Gain on disposition (2)	—	—	—	(484	)	—		(484	)
Consolidated state income tax election (3)	—	—	—	—		(30	)	30
Adjusted Common Equity Earnings	287	277	10	838		825		13
Adjusted Basic EPS ($)	0.66	0.65	0.01	1.93		1.95		(0.02	)

⁽¹⁾  Represents timing differences related to the accounting of Aitken Creek derivatives, included in the Energy Infrastructure segment.

⁽²⁾  See "Significant Item" on page 2 for further information.

⁽³⁾  Remeasurement of deferred income tax liabilities, included in the Corporate and Other segment.

REGULATORY DEVELOPMENTS

ITC

In March 2019 the Federal Energy Regulatory Commission ("FERC") issued a notice of inquiry ("NOI") seeking comments on whether and how to improve its electric transmission incentives policy. The outcome may impact the existing incentive adders that are included in transmission rates charged by transmission owners, including ITC. Also in March 2019, FERC issued a second NOI seeking comments on whether and how recent policies concerning the determination of the base ROE for electric utilities should be modified. The comment period of both NOI proceedings has ended. The outcome may impact ITC’s future ROE and incentive adders.

In September 2019 the regulated utilities in the Midcontinent Independent System Operator region, including ITC, filed an appeal in the U.S. Court of Appeal on FERC's order in 2018 that reduced the Company's incentive adders. The final resolution of this matter is not expected to have a material impact on the Corporation's earnings or cash flows.

Refer to the "Regulatory Highlights" section of the 2018 annual MD&A for further information on ITC's incentive adders and ROE complaints.

UNS Energy

General Rate Application

In April 2019 TEP filed a general rate application with the Arizona Corporation Commission requesting an increase in non-fuel revenue of US$115 million, effective May 1, 2020, with electricity rates based on a 2018 test year. The filing includes a request to increase TEP's allowed ROE to 10.35% from 9.75% and the equity component of its capital structure to 53% from 50% on a rate base of US$2.7 billion. Intervenor testimony in relation to TEP's revenue requirement and rate design was filed in October 2019. A decision is expected in 2020.

MANAGEMENT DISCUSSION AND ANALYSIS
9
September 30, 2019

Transmission Rate Application

In May 2019 TEP filed a proposal with FERC requesting that a forward-looking formula rate replace TEP's stated transmission rates which is intended to allow for more timely recovery of transmission-related costs. In July 2019 FERC issued an order accepting TEP's proposed rate revisions, effective August 1, 2019, subject to refund following hearing and settlement procedures.

FortisBC Energy and FortisBC Electric

In March 2019 FortisBC Energy and FortisBC Electric filed applications with the British Columbia Utilities Commission requesting approval of a multi-year rate plan and rate-setting methodology for 2020 through 2024. A decision is expected in 2020.

FortisAlberta

Second-Term Performance-Based Rate-Setting Proceeding

The Alberta Utilities Commission ("AUC") continues to review regulatory applications for rebasing inputs included in rates under performance-based rate setting ("PBR") for 2018 to 2022, including anomaly-related adjustments and approved changes to depreciation parameters. FortisAlberta's 2018 and 2019 PBR rates remain interim pending the completion of the AUC's review. A decision is expected in 2020.

Generic Cost of Capital Proceeding

In December 2018 the AUC initiated a generic cost of capital proceeding to consider a formula-based approach to setting the allowed ROE beginning in 2021 and whether any process changes are necessary for determining capital structure in years in which a ROE formula is in place. In April 2019 the AUC determined that a traditional non-formulaic approach for assessing ROE and deemed capital structure would be used in 2021, with consideration of a formula-based approach for determining the allowed ROE for 2022 and subsequent years.

2018 Alberta Independent System Operator Tariff Application

In September 2019 the AUC issued a decision that addressed, among other things, a proposal to change how the Alberta Electric System Operator's customer contribution policy is accounted for between distribution facility owners, such as FortisAlberta, and transmission facility owners ("TFO"). The decision prevents any future investment by FortisAlberta under the policy and directs that the unamortized customer contributions of approximately $400 million as at December 31, 2017, which form part of FortisAlberta's rate base, be transferred to the incumbent TFO in FortisAlberta's service area.

In October FortisAlberta filed additional evidence to oppose the decision. The decision is currently being reviewed by the AUC with a ruling expected before the end of 2019. The likely outcome of this process and potential impacts, if any, cannot be determined at this time.

CONSOLIDATED FINANCIAL POSITION

Significant Changes between September 30, 2019 and December 31, 2018
	(Decrease)/Increase
	FX	Other
Balance Sheet Account	($ millions)	($ millions)	Explanation
Cash and cash equivalents	(9)	(95)	Due primarily to capital expenditures and the timing of debt issuances and repayments.
Accounts receivable and other current assets	(20)	(219)	Due primarily to seasonality and a lower income tax receivable.
Assets held for sale	—	(766)	Due to the disposition of the Waneta Expansion.
Regulatory assets (including current and long-term)	(33)	151	Due primarily to the operation of rate stabilization accounts and derivative loss deferrals at UNS Energy.
Property, plant and equipment, net	(593)	1,537	Due primarily to capital expenditures, partially offset by depreciation.
Goodwill	(321)	1	The other increase was not significant.
Short-term borrowings	(1)	324	Due primarily to the issuance of commercial paper at ITC.

MANAGEMENT DISCUSSION AND ANALYSIS
10
September 30, 2019

Significant Changes between September 30, 2019 and December 31, 2018
	(Decrease)/Increase
	FX	Other
Balance Sheet Account	($ millions)	($ millions)	Explanation
Other liabilities	(20)	145	Due primarily to finance lease reclassifications and the balance sheet recognition of operating leases in accordance with the new lease standard. See "Accounting Policy Changes" on page 19.
Regulatory liabilities (including current and long-term)	(79)	(35)	The other decrease was not significant.
Deferred income tax liabilities	(43)	248	Due primarily to the utilization of taxable losses and timing differences related to capital expenditures.
Long-term debt (including current portion)	(482)	(594)	Due primarily to the repayment of Corporate debt (see "Significant Item" on page 2), partially offset by the issuance of debt at ITC.
Shareholders' equity	(335)	1,183	Due to: (i) Common Equity Earnings for the nine months ended September 30, 2019, less dividends declared on common shares; and (ii) the issuance of common shares.
Non-controlling interests	(46)	(292)	Due primarily to the disposition of the Waneta Expansion.

Outstanding Share Data

As at October 31, 2019, the Corporation had issued and outstanding 438.9 million common shares; and the following First Preference Shares: 5.0 million Series F; 9.2 million Series G; 7.0 million Series H; 3.0 million Series I; 8.0 million Series J; 10.0 million Series K; and 24.0 million 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 or declared.

If all outstanding stock options were converted as at October 31, 2019, an additional 3.4 million common shares would be issued and outstanding.

LIQUIDITY AND CAPITAL RESOURCES

CASH FLOW REQUIREMENTS

At the subsidiary level, it is expected that operating expenses and interest costs will be paid from 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 for 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 may be derived from a combination of borrowings under the Corporation's committed credit facility, proceeds from the dividend reinvestment plan and proceeds from the issuance of common shares, preference shares and long-term debt. Depending on the timing of subsidiary dividend receipts, borrowings under the Corporation's committed credit facility may be required periodically to support debt servicing and payment of dividends.

MANAGEMENT DISCUSSION AND ANALYSIS
11
September 30, 2019

Credit Facilities					As at
	Regulated Utilities		Corporate and Other		September 30, 2019		December 31, 2018
($ millions)
Total credit facilities	4,024		1,381		5,405		5,165
Credit facilities utilized:
Short-term borrowings	(383	)	—		(383	)	(60	)
Long-term debt (including current portion)	(575	)	(9	)	(584	)	(1,066	)
Letters of credit outstanding	(64	)	(50	)	(114	)	(119	)
Credit facilities unutilized	3,002		1,322		4,324		3,920

The Corporation's ability to service debt and pay dividends is dependent on the financial results of, and the related cash payments from, subsidiaries. Certain regulated subsidiaries are subject to restrictions that limit their ability to distribute cash to Fortis. These include restrictions by certain regulators limiting annual dividends and restrictions by certain lenders limiting debt to total capitalization. There are also practical limitations on using the net assets of the 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 December 2018 Fortis filed a short-form base shelf prospectus with a 25-month life under which it may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $2.5 billion. In December 2018 Fortis re-established its ATM Program that allows the issuance of up to $500 million of common shares from treasury to the public at the Corporation's discretion, effective until January 2021. As at September 30, 2019, 3.5 million common shares were issued under the ATM Program at an average price of $51.51 per share for gross proceeds of $181 million ($178 million net of commissions). The net proceeds were used primarily to fund capital expenditures. As at September 30, 2019, $319 million remains available under the ATM Program and $2.0 billion under the short-form base shelf prospectus.

As at September 30, 2019, consolidated fixed-term debt maturities and repayments are expected to average approximately $1,054 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, 2019 and are expected to remain compliant throughout 2019.

CASH FLOW SUMMARY

Summary of Consolidated Cash Flows
Periods Ended September 30	Quarter						Year-to-Date
($ millions)	2019		2018		Variance		2019		2018		Variance
Cash, beginning of period	191		197		(6	)	332		327		5
Cash provided by (used in):
Operating activities	857		796		61		2,029		2,067		(38	)
Investing activities	(1,031	)	(783	)	(248	)	(1,664	)	(2,253	)	589
Financing activities	209		(12	)	221		(473	)	46		(519	)
Foreign exchange	2		(3	)	5		(11	)	8		(19	)
Change in cash associated with assets held for sale	—		—		—		15		—		15
Cash, end of period	228		195		33		228		195		33

Operating Activities

See "Performance Overview - Cash Flow from Operating Activities" on page 3.

MANAGEMENT DISCUSSION AND ANALYSIS
12
September 30, 2019

Investing Activities

Cash used in investing activities reflects a higher capital spending level in 2019. See "Capital Expenditure Plan" on page 15 for further information. Cash used in investing activities year to date was partially offset by proceeds from the disposition of the Waneta Expansion.

Financing Activities

Borrowings under credit facilities by the regulated utilities are primarily in support of their capital expenditure plans 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. Periodically, proceeds from share and long-term debt offerings are used to repay borrowings under the Corporation's committed credit facility. Changes in these drivers along with scheduled debt maturities cause cash flows related to financing activities to fluctuate accordingly from period to period.

Net proceeds from the disposition of the Waneta Expansion were used to repay credit facility borrowings and repurchase US$400 million of Corporate debt.

Debt Financing

Long-Term Debt Issuances		Interest
Year-to-date September 30, 2019	Month	Rate					Use of
($ millions, except %)	Issued	(%)	Maturity	Amount			Proceeds
ITC
Secured notes	January	4.55	2049		US	50	(1)(2)(3)
Unsecured term loan credit agreement (4)	June	(5)	2021		US	200	(6)
Secured notes	July	4.65	2049		US	50	(1)(2)(3)
First mortgage bonds	August	3.30	2049		US	75	(1)(2)(3)
FortisBC Energy
Unsecured debentures	August	2.82	2049		200		(1)
FortisTCI
Unsecured non-revolving term loan (7)	February	(8)	2025		US	5	(2)(3)
Caribbean Utilities
Unsecured notes	May	4.14	2049		US	40	(1)(3)(6)
Unsecured notes	August	4.14	2049		US	20	(2)(3)(6)
Unsecured notes	August	3.83	2039		US	20	(2)(3)(6)

⁽¹⁾  Repay credit facility borrowings

⁽²⁾  Finance capital expenditures

⁽³⁾  General corporate purposes

⁽⁴⁾  Maximum amount of borrowings under this agreement is US$400 million.

⁽⁵⁾  Floating rate of a one-month LIBOR plus a spread of 0.60%

⁽⁶⁾  Repay maturing long-term debt

⁽⁷⁾  Maximum amount of borrowings under this agreement of US$10 million has been withdrawn.

⁽⁸⁾  Floating rate of a one-month LIBOR plus a spread of 1.75%

In October 2019 Central Hudson issued 30-year US$50 million senior notes at 3.89% and 40-year US$50 million senior notes at 3.99%. The net proceeds will be used to repay maturing long-term debt, finance capital expenditures, and for general corporate purposes.

MANAGEMENT DISCUSSION AND ANALYSIS
13
September 30, 2019

Common Equity Financing

Common Equity Issuances and Dividends Paid
Periods Ended September 30	Quarter						Year-to-Date
($ millions, except as indicated)	2019		2018		Variance		2019		2018		Variance
Common shares issued (1) (# millions)	2.5		1.8		0.7		9.8		5.5		4.3
Total common shares issued	125		77		48		474		226		248
Non-cash issuances	(74	)	(71	)	(3	)	(227	)	(200	)	(27	)
Cash proceeds from common shares issued	51		6		45		247		26		221
Dividends paid per common share ($)	0.450		0.425		0.025		1.350		1.275		0.075
Total dividends paid	(196	)	(181	)	(15	)	(583	)	(540	)	(43	)
Non-cash dividend reinvestment plan	73		71		2		224		200		24
Cash dividends paid	(123	)	(110	)	(13	)	(359	)	(340	)	(19	)

⁽¹⁾  Mainly related to the Corporation's dividend reinvestment plan and ATM Program. See "Cash Flow Requirements" on page 11 for further information.

On February 14, 2019 and July 31, 2019, Fortis declared a dividend of $0.45 per common share payable on June 1, 2019 and September 1, 2019, respectively. On September 10, 2019, Fortis declared a dividend of $0.4775 per common share payable on December 1, 2019. The payment of dividends is at the discretion of the Board of Directors and depends on the Corporation's financial condition and other factors.

CONTRACTUAL OBLIGATIONS

There were no material changes to the contractual obligations disclosed in the Corporation's 2018 annual MD&A, except issuances of long-term debt and credit facility utilization described above and other items as follows.

In the first quarter of 2019, FortisBC Energy entered into two separate agreements to purchase pipeline capacity on the Westcoast Pipeline over a 42-year term, beginning in the fourth quarter of 2020, increasing obligations by a total of approximately $334 million.

In March 2019 UNS Energy entered into a build-transfer agreement to develop a wind-powered electric generation facility, the Oso Grande Wind Project, which is expected to be completed by December 2020. UNS Energy expects to make payments under the agreement of US$259 million in 2019 and US$111 million in 2020, contingent upon certain performance obligations.

In April 2019 the Waneta Expansion ceased to be a related party. This resulted in the disclosure of power purchase obligations of approximately $2.6 billion related to FortisBC Electric's agreement to purchase capacity from the Waneta Expansion over the 40-year period that began in April 2015.

Under a funding framework with the Governments of Ontario and Canada, Fortis will contribute a minimum of approximately $155 million of equity capital into Wataynikaneyap Power, based on Fortis' proportionate 39% ownership interest and the final regulatory-approved capital cost of the Wataynikaneyap Power project. In October 2019 Wataynikaneyap Power entered into loan agreements to help finance the project during construction ("construction loan agreements"). In the event a lender under the construction loan agreements realizes security on the loans, Fortis may be required to accelerate its equity capital contributions, which may be in excess of the amount otherwise required of Fortis under the funding framework to a maximum of $235 million.

MANAGEMENT DISCUSSION AND ANALYSIS
14
September 30, 2019

CAPITAL STRUCTURE AND CREDIT RATINGS

Fortis requires ongoing access to capital to enable its utilities to fund infrastructure maintenance, modernization and expansion. The Corporation, therefore, targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. The regulated utilities maintain their own capital structures in line with those reflected in customer rates.

Consolidated Capital Structure	As at
	September 30,	December 31,
(%)	2019	2018
Debt (1)	55.6	57.0
Preference shares	3.8	3.8
Common shareholders' equity and minority interest	40.6	39.2
	100.0	100.0

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

The Corporation's credit ratings reflect its low-risk profile, diversity of operations, stand-alone nature and financial separation of each regulated subsidiary, and level of holding company debt.

Credit Ratings
As at September 30, 2019	Rating	Type	Outlook
S&P	A-	Corporate	Negative
	BBB+	Unsecured debt
DBRS	BBB (high)	Corporate	Stable
	BBB (high)	Unsecured debt
Moody's	Baa3	Issuer	Stable
	Baa3	Unsecured debt

Between March and May 2019, all three rating agencies affirmed the Corporation's credit ratings and outlooks. The negative outlook from S&P reflects a modest temporary weakening of financial measures as a result of U.S. tax reform reducing cash flow at the Corporation's U.S. regulated utilities.

In July 2019 Moody's downgraded Central Hudson's unsecured debt rating to A3 from A2 and revised its outlook to stable from negative due to higher capital expenditures and the impacts of U.S. tax reform.

In September 2019 S&P downgraded the senior unsecured debt rating of ITC Holdings Corp. to BBB+ from A- due to an expected increase in the ratio of debt at its regulated utilities relative to debt at the holding company and maintained its negative outlook. S&P also affirmed ITC's regulated subsidiaries' secured debt ratings of A.

In October 2019 S&P downgraded Caribbean Utilities' unsecured debt rating to BBB+ from A- due to climate change risk and revised its outlook to stable from negative due to its stable and predictable cash flows.

CAPITAL EXPENDITURE PLAN

Planned capital expenditures are based on detailed forecasts of energy demand, labour and material costs, general economic conditions, foreign exchange rates and other factors. These could change and cause actual expenditures to differ from forecast.

The planned capital expenditures are expected to be funded primarily with cash from operations, utility debt, and common equity from the Corporation's dividend reinvestment plan and ATM Program.

2019 Capital Plan

The 2019 annual capital plan has increased to $4.3 billion, up $0.6 billion from $3.7 billion as disclosed in the 2018 annual MD&A, with $2.6 billion spent in the first nine months of 2019.

MANAGEMENT DISCUSSION AND ANALYSIS
15
September 30, 2019

Consolidated Capital Expenditures (1)
Year-to-date September 30, 2019
($ millions)
	Regulated							Total
		UNS	Central	FortisBC	Fortis	FortisBC	Other	Regulated	Non-
	ITC	Energy	Hudson	Energy	Alberta	Electric	Electric	Utilities	Regulated (2)	Total
Total	907	513	228	324	297	74	205	2,548	48	2,596

⁽¹⁾  Excludes the non-cash equity component of the allowance for funds used during construction ("AFUDC")

⁽²⁾  Includes Energy Infrastructure and Corporate and Other segments

UNS Energy finalized its plans for the construction of the Oso Grande Wind Project (also referred to as the New Mexico Wind Project). This wind farm will complement UNS Energy's solar generation portfolio. UNS Energy's share will be 247 MW, under a build-transfer asset contract, up from 150 MW disclosed in the 2018 annual MD&A. Construction commenced in October 2019, with completion expected by the end of 2020. The 2019 capital cost of the project for UNS Energy has been updated to reflect the additional capacity, and is now expected to be approximately $346 million (US$262 million), including AFUDC, up from approximately $55 million (US$43 million) disclosed in the 2018 annual MD&A. Capital payments expected in the fourth quarter of 2019 are contingent upon certain performance obligations. The total capital cost for UNS Energy is estimated at $527 million (US$399 million) including AFUDC, up from approximately $280 million (US$217 million) disclosed in the 2018 annual MD&A.

At ITC, the 2019 capital forecast has increased by approximately $132 million (US$100 million) associated with the purchase of additional transmission assets in its service territory.

The 2019 capital plan is based on a forecast exchange rate of US$1.00=CAD$1.32, compared to US$1.00=CAD$1.28 disclosed in the 2018 Annual MD&A.

Major Capital Projects Updates

Wataynikaneyap Transmission Power Project

This 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. Fortis maintains a 39% equity investment in Wataynikaneyap Power. The initial phase of the project to connect the Pikangikum First Nation to Ontario's power grid was fully funded by the Canadian government and was completed in late 2018.

In April 2019 the Ontario Energy Board approved the leave-to-construct application. In June and July 2019, the environmental assessment notices of approval were received for the final two phases of the project. Also in July, Wataynikaneyap Power and the Government of Canada signed agreements that secure Canada's support. In September 2019 Wataynikaneyap Power awarded the engineering, procurement and construction contract to Valard LP, and a notice to proceed was issued in October when financial close was achieved. The estimated funding for this project is up to $1.9 billion, with the project targeted for completion by the end of 2023.

Eagle Mountain Woodfibre Gas Line Project

In July 2019 Woodfibre LNG Limited ("Woodfibre") received a permit from the British Columbia Oil and Gas Commission, one of the key permits for construction and operation of the project. FortisBC Energy's anticipated capital expenditures, net of forecast customer contributions, related to this project total approximately $350 million. Contingent on Woodfibre making a final investment decision, the project is targeted to be in service in 2023.

Five-Year Capital Plan

The Corporation's five-year 2020-2024 capital plan of $18.3 billion is $1.0 billion, or approximately 6%, higher than the five-year 2019-2023 capital plan of $17.3 billion disclosed in the 2018 annual MD&A. The increase is largely due to expected: (i) grid enhancements and cleaner energy resources at ITC and Caribbean Utilities; (ii) expansion of the Tilbury liquefied natural gas site ("Tilbury 1B") at FortisBC Energy; and (iii) increase in the forecast foreign exchange rate from US$1.00=CAD$1.28 to US$1.00=CAD$1.32.

At ITC, the five-year capital plan increased by approximately $400 million, driven by grid enhancements to interconnect customers and cleaner energy resources to the grid, infrastructure investments to support reliability improvements, and the impact of the updated forecast foreign exchange rate.

MANAGEMENT DISCUSSION AND ANALYSIS
16
September 30, 2019

The Tilbury 1B project, a regulated major capital project, involves construction of a marine bunkering facility in support of optimizing the existing investment in Tilbury 1A, including additional liquefaction and piping to a marine jetty. The capital cost of this new project is estimated at approximately $364 million. The project has received the Order-in-Council from the Government of British Columbia and an environment assessment for the marine jetty is in progress.

At Caribbean Utilities, the five-year capital plan increased approximately $200 million, driven by a shift to cleaner energy and is attributed to grid enhancements, alternative energy projects and utility scale solar projects, subject to competitive bid, as outlined in the utility's Integrated Resource Plan ("IRP"). The IRP was accepted by the regulator in 2019 and calls for 100 MW of renewable energy to replace diesel generation on Grand Cayman by 2025.

BUSINESS RISK MANAGEMENT

The Corporation's business risks are generally consistent with those disclosed in its 2018 annual MD&A. See "Regulatory Developments" on page 9 and "Capital Structure and Credit Ratings" on page 14 for applicable updates.

OFF-BALANCE SHEET ARRANGEMENTS

There were no significant changes to off-balance sheet arrangements from those disclosed in the 2018 annual MD&A.

FINANCIAL INSTRUMENTS

Derivatives

The Corporation records all derivatives at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception.

There were no material changes with respect to the nature and purpose, methodologies for fair value determination, and carrying values of the Corporation's derivatives from that disclosed in the 2018 annual MD&A. Additional details are provided in Note 16 to the Interim Financial Statements.

Financial Instruments Not Carried at Fair Value

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

As at September 30, 2019, the carrying value of long-term debt, including current portion, was $23,144 million (December 31, 2018 - $24,231 million) compared to an estimated fair value of $26,422 million (December 31, 2018 - $25,110 million). These fair values were calculated in the manner described in the Corporation's 2018 annual MD&A and in Note 16 to the Interim Financial Statements.

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, 2019 and 2018.

The Corporation periodically provides short-term financing to subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements. As at September 30, 2019, there were inter-segment loans outstanding of $79 million (December 31, 2018 - $nil). Total interest charged was $1 million for the three and nine months ended September 30, 2019.

Additional details are provided in Note 5 to the Interim Financial Statements.

MANAGEMENT DISCUSSION AND ANALYSIS
17
September 30, 2019

SUMMARY OF QUARTERLY RESULTS

		Common Equity
	Revenue	Earnings	Basic EPS	Diluted EPS
Quarter Ended	($ millions)	($ millions)	($)	($)
September 30, 2019	2,051	278	0.64	0.63
June 30, 2019	1,970	720	1.66	1.66
March 31, 2019	2,436	311	0.72	0.72
December 31, 2018	2,206	261	0.61	0.61
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

These quarterly results reflect organic growth, the timing and recognition of regulatory decisions, seasonality associated with electricity and gas demand, and the disposition of the Waneta Expansion. Revenue is also affected by the cost of fuel, purchased power and natural gas that is flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality varies. Earnings of the gas utilities tend to be highest in the first and fourth quarters due to space-heating requirements. Earnings of the electric distribution utilities in the United States tend to be highest in the second and third quarters due to the use of air conditioning and other cooling equipment.

September 2019/September 2018: Common Equity Earnings were $278 million, or $0.64 per common share, for the third quarter of 2019 compared to $276 million or $0.65 per common share, for the third quarter of 2018. See "Performance Overview" on page 2.

June 2019/June 2018: Common Equity Earnings were $720 million, or $1.66 per common share, for the second quarter of 2019 compared to $240 million, or $0.57 per common share, for the second quarter of 2018. The increase in earnings was due primarily to: (i) a $484 million gain on the disposition of the Waneta Expansion; (ii) the favourable impact of the mark-to-market accounting of natural gas derivatives at Aitken Creek; (iii) rate base growth at the regulated utilities, led by ITC; and (iv) favourable foreign exchange of $7 million. The increase in earnings was tempered by: (i) lower retail sales, driven by weather, and higher depreciation and interest expense at UNS Energy; (ii) lower earnings contribution from the Energy Infrastructure segment due to lower hydroelectric production in Belize; and (iii) lower realized margins at Aitken Creek.

March 2019/March 2018: Common Equity Earnings were $311 million, or $0.72 per common share, for the first quarter of 2019 compared to $323 million, or $0.77 per common share, for the first quarter of 2018. The decrease in earnings was due primarily to a one-time $30 million favourable remeasurement of the Corporation's deferred income tax liabilities in the first quarter of 2018 as a result of an election to file a consolidated state income tax return, which offsets earnings growth in the first quarter of 2019. Earnings growth in the first quarter of 2019 was driven by: (i) strong performance at the regulated utilities due primarily to rate base growth; (ii) increased earnings at Central Hudson associated with its rate order effective July 1, 2018; (iii) higher electricity and gas sales at UNS Energy due largely to weather; and (iv) favourable foreign exchange of $9 million. Growth was tempered by: (i) lower earnings contribution from the Energy Infrastructure segment due to lower realized margins and higher unrealized losses on the mark-to-market accounting of natural gas derivatives at Aitken Creek, along with lower hydroelectric production in Belize; and (ii) a lower ROE incentive adder at ITC.

December 2018/December 2017: Common Equity Earnings were $261 million, or $0.61 per common share, for the fourth quarter of 2018 compared to $134 million, or $0.32 per common share, for the fourth quarter of 2017. The increase in earnings was due primarily to: (i) a $146 million increase in 2017 income tax expense associated with deferred tax remeasurements under U.S. tax reform; and (ii) a $14 million decrease in 2018 income tax expense associated with deferred tax remeasurements related to assets held for sale, partially offset by; (iii) a $21 million unrealized foreign exchange gain on a US-dollar denominated affiliate loan in 2017.

MANAGEMENT DISCUSSION AND ANALYSIS
18
September 30, 2019

CRITICAL ACCOUNTING ESTIMATES

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

There were no material changes to the nature of the Corporation's critical accounting estimates or contingencies from that disclosed in the 2018 annual MD&A.

ACCOUNTING POLICY CHANGES

Leases

Effective January 1, 2019, the Corporation adopted Accounting Standards Update ("ASU") 2016-02, Leases, that requires lessees to recognize a right-of-use asset and lease liability for all leases with a lease term greater than 12 months, along with additional disclosures. Fortis applied the transition provisions of the new standard as of the adoption date and did not retrospectively adjust prior periods in accordance with the modified retrospective approach. Fortis elected a package of implementation options, referred to as practical expedients, that allowed it to not reassess: (i) whether existing contracts, including land easements, are or contain a lease; (ii) the classification of existing leases; or (iii) the initial direct costs for existing leases. Fortis also utilized the hindsight practical expedient to determine the lease term. Upon adoption, Fortis did not identify or record an adjustment to the opening balance of retained earnings, and there was no impact on net earnings or cash flows. Refer to Note 8 to the Interim Financial Statements for more detail.

Hedging

Effective January 1, 2019, the Corporation adopted ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, which better aligns risk management activities and financial reporting for hedging relationships through changes to designation, measurement, presentation and disclosure guidance. Adoption did not have a material impact on the Interim Financial Statements and related disclosures.

Fair Value Measurement Disclosures

Effective January 1, 2019, the Corporation adopted elements of ASU No. 2018-13, Changes to the Disclosure Requirements for Fair Value Measurement, that are allowed to be early adopted. This ASU improves the effectiveness of financial statement note disclosures by clarifying what is required and important to users of the financial statements. The partial adoption of this ASU removed the following disclosures: (a) the amount of, and reasons for, transfers between level 2 and level 3 of the fair value hierarchy; (b) the policy for timing of transfers between levels; and (c) the valuation processes for level 3 fair value measurements.

FUTURE ACCOUNTING PRONOUNCEMENTS

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. Adoption is not expected to have a material impact on the consolidated financial statements and related disclosures.

Pensions and Other Post-Retirement Plan Disclosures

ASU No. 2018-14, Changes to the Disclosure Requirements for Defined Benefit Plans, issued in August 2018, is effective for Fortis January 1, 2021 and is to be applied on a retrospective basis for all periods presented. Principally, it modifies the disclosure requirements for employers with defined pension or other post-retirement plans and clarifies disclosure requirements. In particular, it removes the following disclosures: (a) the amounts in accumulated other comprehensive income expected to be recognized as components of net period benefit costs over the next fiscal period; (b) the amount and timing of plan assets expected to be returned to the employer; and (c) the effects of a one-percentage-point change on the assumed health care costs and the change in rates on service cost, interest cost and the benefit obligation for post-retirement health care benefits. Fortis plans to early adopt this update in the 2019 annual audited consolidated financial statements.

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OUTLOOK

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

The Corporation's $18.3 billion five-year capital plan is expected to increase rate base from $28.0 billion in 2019 to $34.5 billion in 2022 and $38.4 billion in 2024, translating into three- and five-year compound average growth rates of 7.2% and 6.5%, respectively. The five-year capital plan reflects the continuation of key industry trends including grid modernization and the delivery of cleaner energy. Beyond the base capital plan, Fortis continues to pursue additional energy infrastructure opportunities. Key opportunities not yet included in the five-year capital plan include: further expansion of liquefied natural gas infrastructure in British Columbia; the fully permitted, cross-border, Lake Erie connector electric transmission project in Ontario; and the acceleration of cleaner energy goals in Arizona.

Fortis expects long-term growth in rate base to support continuing growth in earnings and dividends. Fortis is targeting average annual dividend growth of approximately 6% through 2024. 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 plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence.

FORWARD-LOOKING INFORMATION

Fortis includes forward-looking information and statements in the MD&A within the meaning of applicable Canadian securities laws and the U.S. Private Securities Litigation Reform Act of 1995, collectively referred to as "forward-looking information", which reflects 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 includes, without limitation: targeted average annual dividend growth through 2024; forecast capital expenditures for 2019 and the period 2020 through 2024 and potential funding sources for the capital plan; expected timing, outcome and impact of regulatory decisions; expected or potential funding sources for operating expenses, interest costs and capital expenditure plans; the expectation that maintaining the targeted capital structure of the regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2019; the nature, timing, benefits, funding sources and expected costs of certain capital projects including the Oso Grande Wind Project, Wataynikaneyap Transmission Power Project, Eagle Mountain Woodfibre Gas Line Project, and Tilbury 1B; the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements and the anticipated timing for adoption; forecast rate base for 2022 and 2024; and the expectation that capital investment will support growth in earnings and dividends.

Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: reasonable regulatory decisions and the expectation of regulatory stability; the implementation of the five-year capital expenditure plan; no material capital project and financing cost overruns; sufficient human resources to deliver service and execute the capital expenditure plan; the realization of additional opportunities; the Board exercising its discretion to declare dividends, taking into account the financial performance and condition of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability or upset; the continued ability to maintain the performance of the electricity and gas systems; no severe and prolonged economic downturn; sufficient liquidity and capital resources; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; the continued availability of natural gas, fuel, coal and electricity supply; continuation of power supply and capacity purchase contracts; no significant changes in government energy plans, environmental laws and regulations that could have a material negative impact; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; no significant changes in tax laws and 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 Indigenous Peoples; and favourable labour relations.

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 those 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 the 2018 annual MD&A and in other continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission.

All forward-looking information herein is given as of October 31, 2019. 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.

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