ST. JOHN’S, NEWFOUNDLAND AND LABRADOR–(Marketwired – May 2, 2017) – Fortis Inc. (“Fortis” or the “Corporation”) (TSX:FTS)(NYSE:FTS), a leader in the North American regulated electric and gas utility industry, released its first quarter results today. The Corporation’s net earnings attributable to common equity shareholders for the first quarter of 2017 were $294 million, or $0.72 per common share, compared to $162 million, or $0.57 per common share, for the first quarter of 2016. The quarterly results were heavily influenced by the addition of electric transmission company ITC Holdings Corp. (“ITC”), acquired in October 2016.

On an adjusted basis, net earnings attributable to common equity shareholders for the first quarter were $281 million, or $0.69 per common share, an increase of $0.02 per common share over the first quarter of 2016. A reconciliation of adjusted net earnings and adjusted earnings per common share is provided in the Corporation’s Interim Management Discussion and Analysis for the three months ended March 31, 2017.

“We had good first quarter earnings and remain on plan for the year,” said Barry Perry, President and Chief Executive Officer, Fortis. “Increased earnings at UNS, driven by the rate settlement, and accretion from ITC will contribute to strong results for the remainder of 2017.”

“The integration of ITC is going well. The final piece of permanent financing was put in place during the first quarter as we raised $500 million in common equity through a private placement. In addition, we are on track to deliver our capital plan for the year,” said Mr. Perry.

Strong first quarter adjusted earnings per share and cash flow; capital expenditure plan on track

• Adjusted earnings per common share benefited from the impact of the rate case at UNS and the accretion associated with the acquisition of ITC, partially offset by lower earnings at FortisAlberta and unfavourable foreign exchange associated with US dollar-denominated earnings.
• Earnings per common share growth was tempered by a higher weighted average number of common shares due to the sale of 12.2 million common shares, for gross proceeds of $500 million, to an institutional investor in March 2017.
• Cash flow from operating activities totalled $0.5 billion, an increase of 12% over the first quarter of 2016. The increase reflects higher earnings at the regulated utilities, driven by ITC, partially offset by unfavourable changes in working capital. Operating cash flow from ITC was less than the normal run rate due to the payment of the United States Federal Energy Regulatory Commission ordered return on equity refunds.
• Capital expenditures were $0.7 billion, representing almost one quarter of the consolidated capital expenditure forecast of $3.0 billion for 2017.

Execution of growth strategy

The Corporation’s capital program continues to address the infrastructure needs of customers. The Corporation’s five-year consolidated capital expenditures through 2021 are expected to be approximately $13 billion, including more than $3.5 billion of capital expenditures at ITC.

Construction continues on the Tilbury liquefied natural gas (“LNG”) facility expansion in British Columbia, the Corporation’s largest ongoing capital project, at an estimated capital cost of $400 million, before allowance for funds used during construction and development costs. During the quarter the LNG storage tank was commissioned and key components continue to be installed, with an expected in-service date of mid-2017.

The Corporation continues to invest in four Multi-Value Projects (“MVPs”) at ITC, which are regional electric transmission projects that have been identified by the Midcontinent Independent System Operator to address system capacity needs and reliability in various states. Approximately US$119 million was invested in the MVPs from the date of acquisition of ITC and an additional US$159 million is expected to be spent in 2017. Three of the MVPs are expected to be completed by the end of 2018, with the fourth scheduled for completion in 2023.

In addition to the Corporation’s base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. Specifically, the Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including the potential pipeline expansion to the proposed Woodfibre LNG export facility and further expansion of its Tilbury LNG facility.

Two significant electric transmission investment opportunities are being pursued. The Lake Erie Connector project at ITC would connect the Ontario and PJM Interconnection, LLC grids for the first time, and the Wataynikaneyap Power project in Northwestern Ontario involves construction of new transmission lines to connect remote First Nation communities to the electricity grid. During the quarter a significant milestone was achieved with respect to the Wataynikaneyap Power project with the approval by the Ontario Energy Board of a deferral account to recognize development costs incurred between November 2010 and the commencement of construction. Fortis and its utilities are focused on achieving key milestones in 2017 to further advance these opportunities.

Regulatory proceedings

Fortis is focused on maintaining constructive regulatory relationships and outcomes across its utilities.

During the first quarter, Tucson Electric Power Company (“TEP”) received a rate order that approved new rates that took effect February 27, 2017 and included an increase in non-fuel base revenue of US$81.5 million, an allowed rate of return on common shareholder’s equity (“ROE”) of 9.75%, and a common equity component of capital structure of approximately 50%.

Outlook

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

Over the five-year period through 2021, the Corporation’s capital program is expected to be approximately $13 billion, increasing rate base to almost $30 billion in 2021. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends.

Fortis has targeted average annual dividend growth of approximately 6% through 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation’s utilities, the successful execution of the five-year capital expenditure program, and management’s continued confidence in the strength of the Corporation’s diversified portfolio of utilities and record of operational excellence.

“Our diversified portfolio of utilities and highly executable capital plan allow us to deliver low-risk growth,” commented Mr. Perry. “We remain focused on continuing to achieve strong operational and financial performance in 2017 while we continue to execute on our strategy and integrate ITC into our business.”

Teleconference to Discuss First Quarter 2017 Results

A teleconference and webcast will be held on May 2 at 8:30 a.m. (Eastern). Barry Perry, President and Chief Executive Officer and Karl Smith, Executive Vice President, Chief Financial Officer, will discuss the Corporation’s first quarter 2017 results.

Analysts, members of the media and other interested parties in North America are invited to participate by calling 1.877.223.4471. International participants may participate by calling 647.788.4922. Please dial in 10 minutes prior to the start of the call. No pass code is required.

A live and archived audio webcast of the teleconference will be available on the Corporation’s website, http://www.fortisinc.com/. A replay of the conference will be available two hours after the conclusion of the call until June 2, 2017. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 94192862.

Interim Management Discussion and Analysis

For the three months ended March 31, 2017

Dated May 1, 2017

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 interim unaudited consolidated financial statements and notes thereto for the three months ended March 31, 2017 and the MD&A and audited consolidated financial statements for the year ended December 31, 2016 included in the Corporation’s 2016 Annual Report. Financial information contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States (“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 securities laws including the Private Securities Litigation Reform Act of 1995. 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 as of May 1, 2017. Wherever possible, words such as “anticipates”, “believes”, “budgets”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “target”, “will”, “would” and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which include, without limitation: the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the expectation that the Corporation’s 2017 results will continue to benefit from the acquisition of ITC and the impact of Tucson Electric Power Company’s general rate case; the Corporation’s forecast gross consolidated and segmented capital expenditures for 2017 and from 2017 to 2021; the nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas (“LNG”) facility and Multi-Value Projects, and additional opportunities including the pipeline expansion to the Woodfibre LNG site, the Wataynikaneyap Project and the Lake Erie Connector Project; the expectation that the Corporation’s significant capital expenditure program will support continuing growth in earnings and dividends; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that subsidiary operating expenses and interest costs will be paid out of subsidiary operating cash flows; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis;
the expectation that borrowings under credit facilities may be required from time to time to support seasonal working capital requirements; the expectation that cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions will be derived from a combination of borrowings under the Corporation’s committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt and advances from minority investors; the expectation that borrowings under the Corporation’s committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends; the expectation that maintaining the targeted capital structure of the Corporation’s regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; the intent of management to refinance certain borrowings under Corporation’s and subsidiaries’ long-term committed credit facilities with long-term permanent financing; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2017; the expectation that long-term debt will not be settled prior to maturity; the expectation that any liability from current legal proceedings and claims will not have a material adverse effect on the Corporation’s consolidated financial position, results of operations or cash flows; the expectation that the ITC shareholder litigation settlement, if approved, will not have a significant impact on the financial condition or results of operation of ITC Holdings; target average annual dividend growth through 2021; the Corporation’s forecast rate base over the five-year period through 2021; and the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation’s consolidated financial statements.

Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking statements, 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 including natural gas related infrastructure and generation; the Board of Directors exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; no significant changes in tax laws; no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel, coal and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans, environmental laws and regulations that may materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the continued tax deferred treatment of earnings from the Corporation’s Caribbean operations; continued maintenance of information technology infrastructure and no material breach of cyber-security; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital program.

Forward-looking statements involve 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 statements. These factors should be considered carefully and undue reliance should not be placed on the forward-looking statements. Risk factors which could cause results or events to differ from current expectations are detailed under the heading “Business Risk Management” in this MD&A and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2017 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation’s utilities; uncertainty of the impact a continuation of a low interest rate environment may have on the allowed rate of return on common shareholders’ equity at the Corporation’s regulated utilities; the impact of fluctuations in foreign exchange rates; uncertainty related to proposed tax reform in the United States; risk associated with the impacts of less favourable economic conditions on the Corporation’s results of operations; risk that the expected benefits of the acquisition of ITC may fail to materialize, or may not occur within the time periods anticipated; risk associated with the Corporation’s ability to comply with Section 404(a) of the Sarbanes-Oxley Act of 2002 and the related rules of the U.S. Securities and Exchange Commission and the Public Company Accounting Oversight Board; risk associated with the completion of the Corporation’s 2017 capital expenditures plan, including completion of major capital projects in the timelines anticipated and at the expected amounts; and uncertainty in the timing and access to capital markets to arrange sufficient and cost-effective financing to finance, among other things, capital expenditures and the repayment of maturing debt.

All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Fortis disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.

CORPORATE OVERVIEW

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

Year-to-date March 31, 2017, the Corporation’s electricity systems met a combined peak demand of 23,919 megawatts (“MW”) and its gas distribution systems met a peak day demand of 1,567 terajoules. For additional information on the Corporation’s regulated operations and business segments, refer to Note 1 to the Corporation’s interim unaudited consolidated financial statements for the three months ended March 31, 2017 and to the “Corporate Overview” section of the 2016 Annual MD&A.

FINANCIAL HIGHLIGHTS

Fortis has adopted a strategy of long-term profitable growth with the primary measures of financial performance being earnings per common share and total shareholder return. Key financial highlights for the first quarters ended March 31, 2017 and 2016 are provided in the following table.

Consolidated Financial Highlights (Unaudited)		Quarter Ended March 31
($ millions, except for common share data)		2017		2016		Variance
Revenue		2,274		1,772		502
Energy Supply Costs		754		707		47
Operating Expenses		582		474		108
Depreciation and Amortization		297		234		63
Other Income (Expenses), Net		31		16		15
Finance Charges		229		143		86
Income Tax Expense		106		42		64
Net Earnings		337		188		149
Net Earnings Attributable to:
	Non-Controlling Interests	27		7		20
	Preference Equity Shareholders	16		19		(3	)
	Common Equity Shareholders	294		162		132
Net Earnings		337		188		149
Earnings per Common Share
	Basic ($)	0.72		0.57		0.15
	Diluted ($)	0.72		0.57		0.15
Weighted Average Number of Common Shares Outstanding (# millions)		406.2		282.4		123.8
Cash Flow from Operating Activities		541		483		58

Revenue

The increase in revenue was driven by the acquisition of ITC in October 2016, contribution from Aitken Creek, the flow through in customer rates of higher overall energy supply costs, and higher electricity rates at UNS Energy, Central Hudson and FortisBC Electric. The increase was partially offset by unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.

Energy Supply Costs

The increase in energy supply costs was mainly due to higher overall commodity costs, partially offset by favourable foreign exchange associated with the translation of US dollar-denominated energy supply costs.

Operating Expenses

The increase in operating expenses was primarily due to the acquisition of ITC and general inflationary and employee-related cost increases. The increase was partially offset by favourable foreign exchange associated with the translation of US dollar-denominated operating expenses.

Depreciation and Amortization

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

Other Income (Expenses), Net

The increase in other income, net of expenses, was primarily due to the acquisition of ITC and $11 million (US$8 million), or $7 million (US$5 million) after tax, related to the favourable settlement of matters pertaining to the United States Federal Energy Regulatory Commission (“FERC”) ordered transmission refunds in the first quarter of 2017.

Finance Charges

The increase in finance charges was primarily due to the acquisition of ITC, including interest expense on debt issued to complete the financing of the acquisition.

Income Tax Expense

The increase in income tax expense was primarily due to the acquisition of ITC. ITC’s higher federal and state jurisdictional tax rate increased the total effective tax rate of Fortis.

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

Fortis supplements the use of US GAAP financial measures with non-US GAAP financial measures, including adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share. The Corporation refers to these measures as non-US GAAP financial measures since they are not required by, or presented in accordance with, US GAAP.

The Corporation defines: (i) adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes help investors better evaluate results of operations; and (ii) adjusted basic earnings per common share as adjusted net earnings attributable to common equity shareholders divided by the weighted average number of common shares outstanding. The most directly comparable US GAAP measures to adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share are net earnings attributable to common equity shareholders and basic earnings per common share.

The following table provides a reconciliation of the non-US GAAP financial measures and each of the adjusting items are discussed in the segmented results of operations for the respective reporting segments. The adjusting items do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar measures presented by other companies.

Non-US GAAP Reconciliation (Unaudited)		Quarter Ended March 31
($ millions, except for common share data)		2017		2016		Variance
Net Earnings Attributable to Common Equity Shareholders		294		162		132
Adjusting Items:
UNS Energy –
	Settlement of FERC ordered transmission refunds	(7	)	–		(7	)
	FERC ordered transmission refunds	–		11		(11	)
Non-Regulated – Energy Infrastructure –		(6	)	–		(6	)
	Unrealized gain on mark-to-market of derivatives
Corporate and Other –		–		17		(17	)
	Acquisition-related expenses and fees
Adjusted Net Earnings Attributable to Common Equity Shareholders		281		190		91
Adjusted Basic Earnings Per Common Share ($)		0.69		0.67		0.02
Weighted Average Number of Common Shares Outstanding (# millions)		406.2		282.4		123.8

The increase in adjusted net earnings attributable to common equity shareholders was driven by earnings of $91 million at ITC, acquired in October 2016. The increase was also due to: (i) strong performance at UNS Energy, largely due to higher retail rates as approved pursuant to its 2017 general rate case; (ii) contribution from Aitken Creek; and (iii) the timing of quarterly revenue and operating expenses as compared to the same period in 2016 and higher allowance for funds used during construction (“AFUDC”) at FortisBC Energy. The increase was partially offset by: (i) lower contribution from FortisAlberta, mainly due to lower customer rates and higher operating expenses; (ii) higher Corporate and Other expenses, largely due to finance charges associated with the acquisitions of ITC and Aitken Creek; and (iii) unfavourable foreign exchange associated with US dollar-denominated earnings.

Adjusted earnings per common share were $0.02 per common share higher than the first quarter of 2016. The impact of the above-noted items on adjusted net earnings attributable to common equity shareholders were partially offset by an increase in the weighted average number of common shares outstanding associated with the financing of the acquisition of ITC and the Corporation’s dividend reinvestment and share plans.

SEGMENTED RESULTS OF OPERATIONS

Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited)		Quarter Ended March 31
($ millions)		2017		2016		Variance
Regulated Electric & Gas Utilities – United States
	ITC	91		–		91
	UNS Energy	41		12		29
	Central Hudson	23		24		(1	)
		155		36		119
Regulated Gas Utility – Canadian
	FortisBC Energy	97		92		5
Regulated Electric Utilities – Canadian
	FortisAlberta	25		31		(6	)
	FortisBC Electric	15		15		–
	Eastern Canadian	18		18		–
		58		64		(6	)
Regulated Electric Utilities – Caribbean		8		10		(2	)
Non-Regulated – Energy Infrastructure		23		11		12
Corporate and Other		(47	)	(51	)	4
Net Earnings Attributable to Common Equity Shareholders		294		162		132

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

REGULATED ELECTRIC & GAS UTILITIES – UNITED STATES

ITC

Financial Highlights (Unaudited) 1	Quarter Ended March 31, 2017
Average US:CAD Exchange Rate 2	1.32
Revenue ($ millions)	395
Earnings ($ millions)	91

(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

ITC derives the majority of its revenue from providing transmission, scheduling, control and dispatch services over its transmission systems to its customers and other entities that provide electricity to end-use customers. Revenue for the first quarter was US$298 million compared to US$280 million for the same period in 2016. The increase was primarily due to growth in rate base, partially offset by lower return on equity (“ROE”).

Earnings

Earnings contribution from ITC was US$68 million ($91 million) for the first quarter of 2017.

ITC’s operating earnings for the first quarter were US$80 million compared to US$65 million for the same period in 2016. Earnings for the first quarter of 2016 were reduced by US$7 million in after-tax acquisition-related expenses. Excluding the acquisition-related expenses, earnings of ITC increased by US$8 million. The increase was primarily due to growth in rate base and the unfavourable impact in the first quarter of 2016 of bonus depreciation, partially offset by a decrease in ROE.

UNS ENERGY ¹

Financial Highlights (Unaudited)	Quarter Ended March 31
	2017		2016		Variance
Average US:CAD Exchange Rate 2	1.32		1.37		(0.05	)
Electricity Sales (gigawatt hours (“GWh”))	3,384		3,044		340
Gas Volumes (petajoules (“PJ”))	5		5		–
Revenue ($ millions)	458		440		18
Earnings ($ millions)	41		12		29

(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 was primarily due to higher short-term wholesale sales as a result of more favourable commodity prices compared to the same period in 2016. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings. The increase was partially offset by lower residential and commercial retail electricity sales due to warmer temperatures that reduced space heating.

Gas volumes were comparable with the same period in 2016.

Revenue

The increase in revenue was mainly due to approximately $18 million (US$13 million), or $11 million (US$8 million) after tax, in FERC ordered transmission refunds in the first quarter of 2016, an increase in retail electricity rates effective February 27, 2017, and higher short-term wholesale electricity sales. The increase was partially offset by the flow through to customers of lower purchased power and fuel supply costs, and approximately $17 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.

Earnings

The increase in earnings was primarily due to approximately $11 million (US$8 million) in FERC ordered transmission refunds in the first quarter of 2016, approximately $7 million (US$5 million) related to the favourable settlement of matters pertaining to FERC ordered transmission refunds in the first quarter of 2017, and higher retail electricity rates as discussed above. Also contributing to the increase was more favourably priced long-term wholesale sales and lower operating expenses, partially offset by approximately $1 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings.

CENTRAL HUDSON

Financial Highlights (Unaudited)	Quarter Ended March 31
	2017		2016		Variance
Average US:CAD Exchange Rate 1	1.32		1.37		(0.05	)
Electricity Sales (GWh)	1,244		1,255		(11	)
Gas Volumes (PJ)	9		9		–
Revenue ($ millions)	258		249		9
Earnings ($ millions)	23		24		(1	)

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

Electricity Sales & Gas Volumes

The decrease in electricity sales was primarily due to lower average consumption as a result of warmer temperatures. Gas volumes were comparable with the same period in 2016.

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

Revenue

The increase in revenue was due to higher delivery revenue from increases in base electricity rates effective July 1, 2016 and the recovery from customers of higher gas commodity costs, partially offset by approximately $9 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.

Earnings

The decrease in earnings was primarily due to approximately $1 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings and higher-than-expected storm restoration costs incurred in the first quarter of 2017, partially offset by increases in delivery revenue.

REGULATED GAS UTILITY – CANADIAN

FORTISBC ENERGY

Financial Highlights (Unaudited)	Quarter Ended March 31
	2017	2016	Variance
Gas Volumes (PJ)	83	68	15
Revenue ($ millions)	449	406	43
Earnings ($ millions)	97	92	5

Gas Volumes

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

Revenue

The increase in revenue was primarily due to higher gas volumes and a higher commodity cost of natural gas charged to customers.

Earnings

The increase in earnings was primarily due to the timing of quarterly revenue and operating expenses as compared to the same period in 2016. Also contributing to the increase was higher AFUDC.

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

REGULATED ELECTRIC UTILITIES – CANADIAN

FORTISALBERTA

Financial Highlights (Unaudited)	Quarter Ended March 31
	2017	2016	Variance
Energy Deliveries (GWh)	4,551	4,556	(5	)
Revenue ($ millions)	147	142	5
Earnings ($ millions)	25	31	(6	)

Energy Deliveries

The decrease in energy deliveries was primarily due to lower average consumption by oil and gas customers as a result of decreased oil and gas activity in Alberta. The decrease was largely offset by higher average consumption by residential, commercial and farm customers as a result of colder temperatures and growth in the numbers of customers.

Revenue

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

Earnings

The decrease in earnings was primarily due to a decrease in customer rates, as discussed above, and higher operating expenses, partially offset by an increase in capital tracker revenue.

FORTISBC ELECTRIC ¹

Financial Highlights (Unaudited)	Quarter Ended March 31
	2017	2016	Variance
Electricity Sales (GWh)	945	851	94
Revenue ($ millions)	113	104	9
Earnings ($ millions)	15	15	–

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

Electricity Sales

The increase in electricity sales was primarily due to higher average consumption as a result of colder temperatures.

Revenue

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

Earnings

Earnings were comparable with the same period in 2016.

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

EASTERN CANADIAN ELECTRIC UTILITIES ¹

Financial Highlights (Unaudited)	Quarter Ended March 31
	2017	2016	Variance
Electricity Sales (GWh)	2,737	2,706	31
Revenue ($ millions)	332	329	3
Earnings ($ millions)	18	18	–

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

Electricity Sales

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

Revenue

The increase in revenue was due to higher electricity sales and an increase in customer rates effective July 1, 2016 at Newfoundland Power, partially offset by the flow through in customer electricity rates of lower energy supply costs.

Earnings

Earnings were comparable with the same period in 2016.

REGULATED ELECTRIC UTILITIES – CARIBBEAN ¹

Financial Highlights (Unaudited)	Quarter Ended March 31
	2017	2016	Variance
Average US:CAD Exchange Rate 2	1.32	1.37	(0.05	)
Electricity Sales (GWh)	191	190	1
Revenue ($ millions)	70	75	(5	)
Earnings ($ millions)	8	10	(2	)

(1)	Comprised of Caribbean Utilities Company, Ltd. (“Caribbean Utilities”), in which Fortis holds an approximate 60% controlling interest, and two wholly owned utilities, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively “Fortis Turks and Caicos”). Also includes the Corporation’s 33% equity investment in Belize Electricity Limited (“Belize Electricity”).
(2)	The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00.

Electricity Sales

Electricity sales were comparable with the same period in 2016.

Revenue

The decrease in revenue was mainly due to approximately $3 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue and the flow through in customer electricity rates of lower fuel costs.

Earnings

The decrease in earnings was primarily due to a decrease in equity income from Belize Electricity.

NON-REGULATED – ENERGY INFRASTRUCTURE ¹

Financial Highlights (Unaudited)	Quarter Ended March 31
	2017		2016		Variance
Energy Sales (GWh)	82		89		(7	)
Revenue ($ millions)	56		29		27
Earnings ($ millions)	23		11		12

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

Energy Sales

The decrease in energy sales was primarily due to decreased production in Belize due to lower rainfall.

Revenue

The increase in revenue was driven by the acquisition of Aitken Creek in April 2016, with revenue of $26 million recognized in the first quarter of 2017.

Earnings

The increase in earnings was driven by earnings contribution of $13 million from Aitken Creek, which includes an after-tax $6 million unrealized gain on the mark-to-market of derivatives.

CORPORATE AND OTHER ¹

Financial Highlights (Unaudited)	Quarter Ended March 31
($ millions)	2017		2016		Variance
Revenue	–		1		(1	)
Operating Expenses	12		25		(13	)
Other Income (Expenses), Net	–		3		(3	)
Finance Charges	50		28		22
Income Tax Recovery	(31	)	(17	)	(14	)
	(31	)	(32	)	1
Preference Share Dividends	16		19		(3	)
Net Corporate and Other Expenses	(47	)	(51	)	4

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

Net Corporate and Other expenses in the first quarter of 2016 were impacted by acquisition-related expenses associated with ITC totalling $20 million ($17 million after tax). Acquisition-related expenses included: (i) investment banking, legal, consulting and other fees totalling approximately $16 million ($14 million after tax), which were included in operating expenses; and (ii) fees associated with the Corporation’s acquisition credit facilities totalling approximately $4 million ($3 million after tax), which were included in finance charges.

Excluding the above-noted items, net Corporate and Other expenses were $47 million for the first quarter of 2017 compared to $34 million for the same period last year. The increase was primarily due to higher finance charges, a decrease in other income, and higher operating expenses, partially offset by a higher income tax recovery and lower preference share dividends.

The increase in finance charges was mainly due to the acquisitions of ITC and Aitken Creek in October 2016 and April 2016, respectively. The decrease in other income was primarily due to the release of provisions on the wind-up of a partnership in the first quarter of 2016. The increase in operating expenses was mainly due to higher compensation-related expenditures, general inflationary increases and ancillary expenses to support the acquisition of ITC and the Corporation’s listing on the New York Stock Exchange. The higher income tax recovery was mainly related to the increase in Corporate and Other finance charges. The decrease in preference share dividends was due to the redemption of First Preference Shares, Series E in September 2016.

REGULATORY HIGHLIGHTS

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

ITC

ROE Complaints

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

During the first quarter of 2017, ITC provided a refund of US$121 million, including interest, for the Initial Refund Period. This refund is subject to a final true-up pursuant to the refund process which is expected to be finalized during the second quarter of 2017. As at March 31, 2017, the estimated range of refunds for the Second Refund Period was between US$103 million to US$140 million and ITC has recognized an aggregated estimated regulatory liability of US$140 million.

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

UNS Energy

General Rate Application

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

FortisAlberta

Capital Tracker Applications

In January 2017 the Alberta Utilities Commission (“AUC”) issued its decision on FortisAlberta’s 2015 True-Up Application approving the 2015 capital tracker revenue as filed, pending the approval of the Company’s Compliance Filing, filed in February 2017. A decision is expected in the second half of 2017. The Company is required by the AUC to file its 2016 Capital Tracker True-Up Application in June 2017.

Next Generation Performance-Based Rate-Setting Proceeding

In December 2016 the AUC issued its decision outlining the manner in which distribution rates will be determined during the second performance-based rate-setting (“PBR”) term, being the five-year period from 2018 through 2022. The parameters of the second PBR term are generally consistent with the first PBR term except for: (i) the productivity factor, which is set at 0.3% for the second PBR term, as compared to 1.16% for the first PBR term; and (ii) the capital tracker mechanism, which will be replaced by two incremental capital funding mechanisms in the second PBR term. The capital funding mechanisms will include a capital tracker mechanism similar to the first PBR term for incremental capital not previously included in FortisAlberta’s rate base, and a K-bar mechanism, submitted annually through the annual rates application, for all capital included in FortisAlberta’s going-in rate base. FortisAlberta filed a rebasing application in April 2017 to establish the going-in revenue requirement for the second PBR term, which will be used to determine the going-in rates upon which the PBR formula will be applied to establish distribution rates for 2018. A decision on this application is expected in the second half of 2017.

Significant Regulatory Proceedings

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

Regulated Utility	Application/Proceeding	Filing Date	Expected Decision
ITC	Second MISO Base ROE Complaint	Not applicable	To be determined

CONSOLIDATED FINANCIAL POSITION

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

Significant Changes in the Consolidated Balance Sheets between March 31, 2017 and December 31, 2016
Balance Sheet Account		Increase/ (Decrease) ($ millions)	Explanation
Capital assets		261	The increase was mainly due to capital expenditures, partially offset by depreciation and the impact of foreign exchange associated with the translation of US dollar-denominated capital assets.
Goodwill		(103)	The decrease was due to the impact of foreign exchange associated with the translation of US dollar-denominated goodwill.
Short-term borrowings		(610)	The decrease was mainly due to repayment of the Corporation’s equity bridge credit facility, which was used to finance a portion of the acquisition of ITC, and the repayment of short-term borrowings at FortisBC Energy.
Regulatory liabilities – current and long-term		(156)	The decrease was primarily related to a reduction in regulatory liabilities at ITC associated with the payment of US$121 million related to the Initial Refund Period ROE complaint.
Long-term debt (including current portion)		299	The increase was mainly due to the issuance of term loan credit agreements by ITC, partially offset by regularly scheduled debt repayments and the impact of foreign exchange associated with the translation of US dollar-denominated debt.
Shareholders’ equity (before non-controlling interests)		614	The increase primarily related to: (i) the issuance of $500 million of common shares; (ii) net earnings attributable to common shareholders for the three months ended March 31, 2017, less dividends declared on common shares; and (iii) the issuance of common shares under the Corporation’s dividend reinvestment, employee share purchase and stock option plans.

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CONSOLIDATED CASH FLOWS

The table below outlines the Corporation’s sources and uses of cash for the three months ended March 31, 2017 compared to the same period in 2016, followed by a discussion of the nature of the variances in cash flows.

Summary of Consolidated Cash Flows (Unaudited)		Quarter Ended March 31
($ millions)		2017		2016		Variance
Cash, Beginning of Period		269		242		27
Cash Provided by (Used in):
	Operating Activities	541		483		58
	Investing Activities	(719	)	(413	)	(306	)
	Financing Activities	208		(66	)	274
	Effect of Exchange Rate Changes on Cash and Cash Equivalents	(1	)	(14	)	13
Cash, End of Period		298		232		66

Operating Activities: Cash flow provided by operating activities was $58 million higher quarter over quarter. The increase was primarily due to higher earnings, driven by the acquisition of ITC, partially offset by changes in working capital. The net decrease in working capital was mainly due to the payment of US$121 million related to the Initial Refund Period ROE complaint.

Investing Activities: Cash used in investing activities was $306 million higher quarter over quarter. The increase was driven by capital expenditures at ITC. Higher capital spending at FortisAlberta and FortisBC Energy also contributed to the increase.

Financing Activities: Cash provided by financing activities was $274 million higher quarter over quarter. The increase was driven by higher proceeds from the issuance of long-term debt, largely at ITC.

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

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

Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
	Quarter Ended March 31
($ millions)	2017	2016	Variance
ITC 1	334	–	334
Caribbean Electric 2	54	–	54
Total	388	–	388

(1)	In March 2017 ITC entered into 1-year and 2-year unsecured term loan credit agreements at floating interest rates of a one-month LIBOR plus a spread of 0.90% and 0.65%, respectively. As at March 31, 2017, borrowings under the term loan credit agreements were US$200 million and US$50 million, respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes.
(2)	In March 2017 Caribbean Utilities issued 15-year US$40 million 3.90% unsecured notes. The net proceeds from the offering were used to finance capital expenditures and repay short-term borrowings.

Repayments of Long-Term Debt and Capital Lease and Finance Obligations (Unaudited)
	Quarter Ended March 31
($ millions)	2017		2016		Variance
UNS Energy	(13	)	(13	)	–
FortisBC Energy	(2	)	(2	)	–
FortisBC Electric	(1	)	(25	)	24
Total	(16	)	(40	)	24

Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited)
	Quarter Ended March 31
($ millions)	2017		2016	Variance
ITC	(23	)	–	(23	)
UNS Energy	14		46	(32	)
FortisAlberta	35		17	18
Eastern Canadian	28		22	6
Corporate	11		7	4
Total	65		92	(27	)

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

Common share dividends paid in the first quarter of 2017 totalled $98 million, net of $62 million of dividends reinvested, compared to $77 million, net of $29 million of dividends reinvested, paid in the first quarter of 2016. The dividend paid per common share was $0.40 in the first quarter of 2017 compared to $0.375 in the first quarter of 2016. The weighted average number of common shares outstanding for the first quarter of 2017 was 406.2 million compared to 282.4 million for the first quarter of 2016.

CONTRACTUAL OBLIGATIONS

The Corporation’s consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter, as at March 31, 2017, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2016 Annual MD&A. There were no material changes in the nature and amount of the Corporation’s contractual obligations during the three months ended March 31, 2017 from those disclosed in the 2016 MD&A.

Contractual Obligations (Unaudited)		Due within 1 year	Due in year 2	Due in year 3	Due in year 4	Due in year 5	Due after 5 years
As at March 31, 2017
($ millions)	Total
Long-term debt	21,515	1,090	946	450	455	1,762	16,812
Interest obligations on long-term debt	14,359	889	845	830	812	788	10,195
Capital lease and finance obligations	2,475	128	99	81	65	79	2,023
Power purchase obligations	2,285	264	193	116	115	114	1,483
Renewable power purchase obligations	1,588	98	98	98	97	97	1,100
Gas purchase obligations	1,157	348	231	171	140	100	167
Long-term contracts – UNS Energy	1,089	184	159	152	117	76	401
ITC easement agreement	447	14	13	13	13	13	381
Defined benefit pension funding contributions	220	56	28	28	29	32	47
Operating lease obligations	170	13	12	10	8	7	120
Renewable energy credit purchase agreements	151	23	12	12	12	12	80
Other	356	34	25	22	209	2	64
Total	45,812	3,141	2,661	1,983	2,072	3,082	32,873

For a discussion of the nature and amount of the Corporation’s consolidated capital expenditure program not included in the preceding Contractual Obligations table, refer to the “Capital Expenditure Program” section of this MD&A.

CAPITAL STRUCTURE

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

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

Capital Structure (Unaudited)	As at
	March 31, 2017		December 31, 2016
	($ millions)	(%)	($ millions)	(%)
Total debt and capital lease and finance obligations (net of cash) 1	22,141	59.3	22,490	60.6
Preference shares	1,623	4.3	1,623	4.4
Common shareholders’ equity	13,588	36.4	12,974	35.0
Total	37,352	100.0	37,087	100.0

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

Including amounts related to non-controlling interests, the Corporation’s capital structure as at March 31, 2017 was 56.5% total debt and capital lease and finance obligations (net of cash), 4.1% preference shares, 34.7% common shareholders’ equity and 4.7% non-controlling interests (December 31, 2016 – 57.8% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 33.3% common shareholders’ equity and 4.7% non-controlling interests). The change in the Corporation’s capital structure was mainly due to an increase in common equity at the Corporation due to the issuance of $500 million of common shares, used to repay short-term borrowings.

CREDIT RATINGS

As at March 31, 2017, the Corporation’s credit ratings were as follows.

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

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

CAPITAL EXPENDITURE PROGRAM

A breakdown of the $709 million in gross consolidated capital expenditures by segment year-to-date 2017 is provided in the following table.

Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-Date March 31, 2017
($ millions)
	Regulated
	ITC	UNS Energy	Central Hudson	FortisBC Energy	Fortis Alberta	FortisBC Electric	Eastern Canadian	Caribbean Electric	Total Regulated Utilities	Non-Regulated (2)	Total
Total	268	127	50	94	93	21	27	25	705	4	709

(1)	Represents cash payments to construct capital and intangible assets, as reflected on the consolidated statement of cash flows. Excludes the non-cash equity component of AFUDC.
(2)	Includes Energy Infrastructure and Corporate and Other segments

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

Gross consolidated capital expenditures for 2017 are forecast to be approximately $3.0 billion. There have been no material changes in the overall expected level, nature and timing of the Corporation’s significant capital projects from those that were disclosed in the 2016 Annual MD&A.

At ITC approximately US$119 million was invested in the Multi-Value Projects (“MVPs”) from the date of acquisition and an additional US$159 million is expected to be spent in 2017. The MVPs consist of four regional electric transmission projects that have been identified by MISO to address system capacity needs and reliability in various states.

FortisBC Energy’s construction of the Tilbury liquefied natural gas (“LNG”) facility expansion (“Tilbury LNG Facility Expansion”) in British Columbia is ongoing. Approximately $424 million, including AFUDC and development costs, has been invested to the end of the first quarter of 2017. The total cost of the project scope that is currently under construction is estimated at approximately $470 million, including approximately $70 million of AFUDC and development costs, which could be impacted depending on the date the project is considered in service for rate-making purposes. The facility includes a second LNG tank and a new liquefier, both to be in service in mid-2017. Key activities during the first quarter included commissioning of the LNG storage tank and the continued installation of the liquefaction process area piping insulation, electrical and instrumentation cable and terminations.

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

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

ADDITIONAL INVESTMENT OPPORTUNITIES

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

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

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

The Corporation’s Tilbury LNG facility is uniquely positioned to meet customer demand for clean-burning natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment, and is relatively close to international shipping lanes. Fortis continues to have discussions with a number of potential export customers.

In January 2017 ITC received approval of a Presidential Permit from the U.S. Department of Energy for the Lake Erie Connector transmission line, which is a required approval for international border-crossing projects. Also in January, ITC received a report from Canada’s National Energy Board recommending the issuance of a Certificate of Public Convenience and Necessity (“CPCN”) with prescribed conditions for the transmission line. The Lake Erie Connector project at ITC 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 (“PJM”). The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets. The project continues to advance through regulatory, operational, and economic milestones. Key milestones for 2017 include: receiving final approval of the CPCN from Canada’s Governor in Council with a decision expected on or before June 30, 2017; receiving approval from the U.S. Army Corps of Engineers and Pennsylvania Department of Environmental Protection in a joint application; completing project cost refinements; and securing favourable transmission service agreements with prospective counterparties. Pending achievement of key milestones, the expected in-service date for the project is late 2020.

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

The Corporation also has other significant opportunities that have not yet been included in the Corporation’s capital expenditure forecast including, but not limited to: transmission investment opportunities at ITC; investment opportunities in New York Transco, LLC to address electric transmission constraints in New York State at CH Energy; renewable energy alternatives, gas-fired generation and transmission investments at UNS Energy; and further gas infrastructure opportunities at FortisBC Energy.

CASH FLOW REQUIREMENTS

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

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

Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation’s committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt, and advances from minority investors. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation’s committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends.

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 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.

In April 2017 ITC issued 30-year US$200 million 4.16% secured first mortgage bonds. The net proceeds from the issuance was used to repay credit facility borrowings and for general corporate purposes.

As at March 31, 2017, management expects consolidated fixed-term debt maturities and repayments to average approximately $740 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 March 31, 2017 and are expected to remain compliant throughout 2017.

CREDIT FACILITIES

As at March 31, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.4 billion, of which approximately $3.8 billion was unused, including $909 million unused under the Corporation’s committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2017 through 2021.

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

Credit Facilities (Unaudited)						As at
($ millions)		Regulated Utilities		Corporate and Other		March 31, 2017		December 31, 2016
Total credit facilities (1)		4,061		1,385		5,446		5,976
Credit facilities utilized:
	Short-term borrowings (1)	(543	)	(2	)	(545	)	(1,155	)
	Long-term debt (including current portion) (2)	(640	)	(390	)	(1,030	)	(973	)
Letters of credit outstanding		(68	)	(51	)	(119	)	(119	)
Credit facilities unused (1)		2,810		942		3,752		3,729

(1)	Total credit facilities and short-term borrowings as at March 31, 2017 include $179 million (US$135 million) outstanding under ITC’s commercial paper program (December 31, 2016 – $195 million (US$145 million)). Outstanding commercial paper does not reduce available capacity under the Corporation’s consolidated credit facilities.
(2)	As at March 31, 2017, credit facility borrowings classified as long-term debt included $123 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2016 – $61 million).

As at March 31, 2017 and December 31, 2016, certain borrowings under the Corporation’s and subsidiaries’ long-term committed credit facilities were classified as long-term debt. It is management’s intention to refinance these borrowings with long-term permanent financing during future periods. The only significant change in credit facilities from that disclosed in the Corporation’s 2016 Annual MD&A is as follows.

In March 2017 the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares.

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $119 million as at March 31, 2017 (December 31, 2016 – $119 million), the Corporation had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.

BUSINESS RISK MANAGEMENT

Year-to-date 2017, the business risks of the Corporation were generally consistent with those disclosed in the Corporation’s 2016 Annual MD&A, including certain risks, as disclosed below, and an update to those risks, where applicable.

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

Capital Resources and Liquidity Risk – Credit Ratings: In April 2017 S&P upgraded TEP’s unsecured debt rating to ‘A-‘ from ‘BBB+’ with a stable outlook. For a discussion on the Corporation’s credit ratings refer to the “Liquidity and Capital Resources” section of this MD&A.

Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at March 31, 2017, the fair value of the Corporation’s consolidated defined benefit pension and other post-employment benefit plan assets was $2,975 million compared to $2,899 million as at December 31, 2016.

CHANGES IN ACCOUNTING POLICIES

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

Simplifying the Test for Goodwill Impairment

Effective January 1, 2017, the Corporation adopted Accounting Standards Update (“ASU”) No. 2017-04, Simplifying the Test for Goodwill Impairment. The amendments in this update simplify the subsequent measurement of goodwill by eliminating step two in the current two-step goodwill impairment test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. The above-noted ASU was applied prospectively and did not impact the Corporation’s interim unaudited consolidated financial statements for the three months ended March 31, 2017.

FUTURE ACCOUNTING PRONOUNCEMENTS

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

Revenue from Contracts with Customers

ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and can be applied consistently across various transactions, industries and capital markets. In 2016 a number of additional ASUs were issued that clarify implementation guidance in ASC Topic 606. This standard, and all related ASUs, is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted for annual and interim periods beginning after December 15, 2016. The Corporation has elected not to early adopt.

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

The majority of the Corporation’s revenue is generated from energy sales to retail customers based on published tariff rates, as approved by the respective regulators, and from transmission services and is considered to be in the scope of ASU No. 2014-09. Fortis does not expect that the adoption of this standard, and all related ASUs, will have a material impact on the recognition of revenue; however, the Corporation does expect it will impact its required disclosures. Certain specific interpretative issues remain outstanding and the conclusions reached, if different than currently anticipated, could have a material impact on the Corporation’s consolidated financial statements and related disclosures. Fortis continues to closely monitor developments related to the new standard.

Recognition and Measurement of Financial Assets and Financial Liabilities

ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial asset. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

Leases

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

Measurement of Credit Losses on Financial Instruments

ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

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

ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, was issued in March 2017 and the amendments in this update require that an employer disaggregate the current service costs component of net benefit cost and present it in the same statement of earnings line item(s) as other employee compensation costs arising from services rendered. The other components of net benefit cost are required to be presented separately from the service cost component and outside of operating income. Additionally, the amendments allow only the service cost component to be eligible for capitalization when applicable. This update is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted. The amendments in this update should be applied retrospectively for the presentation of the net periodic benefit costs and prospectively, on and after the effective date, for the capitalization in assets of only the service cost component of net periodic benefit costs. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

FINANCIAL INSTRUMENTS

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

Financial Instruments (Unaudited)	As at
	March 31, 2017		December 31, 2016
	Carrying	Estimated	Carrying	Estimated
($ millions)	Value	Fair Value	Value	Fair Value
Long-term debt, including current portion	21,515	23,014	21,219	22,523
Waneta Partnership promissory note	60	62	59	61

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

Derivative Instruments

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

For further details of the Corporation’s derivative instruments refer to Note 14 to the Corporation’s interim unaudited consolidated financial statements for the three months ended March 31, 2017. There were no material changes in the nature and amount of the Corporations’ derivative instruments during the three months ended March 31, 2017 from those disclosed in the 2016 Annual MD&A, except as follows.

In March and April 2017 ITC entered into three additional forward-starting interest rate swaps, all effective December 2017, with notional amounts of US$50 million each and 10-year original terms. The agreements include a mandatory early termination provision and will be terminated no later than the effective date. The interest rate swaps manage the interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the refinancing of maturing US$385 million long-term debt due in January 2018.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Corporation’s interim unaudited consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation’s regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation’s critical accounting estimates during the three months ended March 31, 2017 from those disclosed in the 2016 Annual MD&A.

Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the Corporation’s consolidated financial position, results of operations or cash flows. For complete details of legal proceedings affecting the Corporation, refer to Note 17 to the Corporation’s interim unaudited consolidated financial statements. There were no material changes in the Corporation’s contingencies from those disclosed in the 2016 Annual MD&A, except as described below.

Fortis and ITC

Following announcement of the acquisition of ITC in February 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan (“Superior Court”) and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified damages, and costs, including attorneys’ fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In January 2017 the Superior Court issued a revised scheduling order, which, among other things, requires the parties, including ITC, to complete discovery by May 2017, and set a trial date for September 2017. A hearing on the plaintiff’s motion for class certification was held in February 2017.

In March 2017 the parties reached an agreement in principle to settle the case, subject to formal documentation and court approval. The court stayed the matter, except for settlement-related proceedings, and scheduled a hearing on preliminary settlement approval for May 25, 2017. ITC Holdings does not expect the settlement, if approved, to have a significant impact on its financial condition or results of operations.

RELATED-PARTY AND INTER-COMPANY TRANSACTIONS

Related-party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. There were no material related-party transactions for the three months ended March 31, 2017 and 2016.

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

Related-party and inter-company transactions (Unaudited)	Quarter Ended March 31
($ millions)	2017	2016
Sale of capacity from Waneta Expansion to FortisBC Electric	16	15
Sale of energy from Belize Electric Company Limited to Belize Electricity	7	8
Lease of gas storage capacity from Aitken Creek to FortisBC Energy	8	–

As at March 31, 2017, accounts receivable on the Corporation’s consolidated balance sheet included approximately $9 million due from Belize Electricity (December 31, 2016 – $16 million), in which Fortis holds a 33% equity investment.

From time to time, the Corporation provides short-term financing to certain of its subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements, bearing interest at rates that approximate the Corporation’s cost of short-term borrowing, and provides long-term financing to certain of its subsidiaries, bearing interest at rates that approximate the Corporation’s cost of long-term debt. There were no inter-segment loans outstanding as at March 31, 2017 and December 31, 2016 and there was no interest charged for the three months ended March 31, 2017 (less than $1 million for the three months ended March 31, 2016).

SUMMARY OF QUARTERLY RESULTS

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

Summary of Quarterly Results (Unaudited)	Revenue	Net Earnings Attributable to Common Equity Shareholders	Earnings per	Common Share
Quarter Ended	($ millions)	($ millions)	Basic ($)	Diluted ($)
March 31, 2017	2,274	294	0.72	0.72
December 31, 2016	2,053	189	0.49	0.49
September 30, 2016	1,528	127	0.45	0.45
June 30, 2016	1,485	107	0.38	0.38
March 31, 2016	1,772	162	0.57	0.57
December 31, 2015	1,723	135	0.48	0.48
September 30, 2015	1,579	151	0.54	0.54
June 30, 2015	1,540	244	0.88	0.87

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

March 2017/March 2016: Net earnings attributable to common equity shareholders were $294 million, or $0.72 per common share, for the first quarter of 2017 compared to earnings of $162 million, or $0.57 per common share, for the first quarter of 2016. A discussion of the quarter over quarter variance in financial results is provided in the “Financial Highlights” section of this MD&A.

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

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

June 2016/June 2015: Net earnings attributable to common equity shareholders were $107 million, or $0.38 per common share, for the second quarter of 2016 compared to earnings of $244 million, or $0.88 per common share, for the second quarter of 2015. The decrease in earnings was primarily due to: $22 million in acquisition-related expenses and fees and a $2 million unrealized loss on the mark-to-market of derivatives in the second quarter of 2016, and a net gain of $123 million on the sale of commercial real estate, hotel and non-regulated generation assets in the second quarter of 2015. Excluding these items, the $10 million increase in earnings was mainly due to: (i) strong performance at most of the Corporation’s regulated utilities; (ii) contribution of $4 million from Aitken Creek, which was acquired in early April 2016; (iii) favourable foreign exchange associated with US dollar-denominated earnings; and (iv) the timing of quarterly earnings at FortisBC Electric compared to the second quarter of 2015. The increase was partially offset by lower earnings at FortisAlberta, due to higher operating expenses and lower average energy consumption, and the sale of commercial real estate and hotel assets in 2015.

INTERNAL CONTROLS OVER FINANCIAL REPORTING

As previously reported and as further discussed in the Corporation’s 2016 Annual Report, Fortis acquired ITC in October 2016. As part of our ongoing integration activities, the Corporation continues to augment internal controls to reflect the risks inherent with the acquisition of ITC. Otherwise, there has been no change in internal controls over financial reporting that occurred during the first quarter of 2017 that has, or is reasonably likely to have, a material effect on internal controls over financial reporting.

OUTLOOK

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

Over the five-year period through 2021, the Corporation’s capital program is expected to be approximately $13 billion, increasing rate base to almost $30 billion in 2021. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends.

Fortis has targeted average annual dividend growth of approximately 6% through 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation’s utilities, the successful execution of the five-year capital expenditure program, and management’s continued confidence in the strength of the Corporation’s diversified portfolio of utilities and record of operational excellence.

OUTSTANDING SHARE DATA

As at May 1, 2017, the Corporation had issued and outstanding 416.0 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation’s First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether such dividends have been declared.

The number of common shares of Fortis that would be issued if all outstanding stock options were converted as at May 1, 2017 is approximately 4.3 million.

Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov.

FORTIS INC.

Interim Consolidated Financial Statements

For the three months ended March 31, 2017 and 2016

(Unaudited)

Prepared in accordance with accounting principles generally accepted in the United States

Fortis Inc.

Consolidated Balance Sheets (Unaudited)

As at

(in millions of Canadian dollars)

	March 31,		December 31,
	2017		2016
ASSETS
Current assets
Cash and cash equivalents	$	298	$	269
Accounts receivable and other current assets		1,133		1,127
Prepaid expenses		76		85
Inventories		320		372
Regulatory assets (Note 5)		325		313
		2,152		2,166
Other assets		428		406
Regulatory assets (Note 5)		2,595		2,620
Capital assets		29,598		29,337
Intangible assets		1,015		1,011
Goodwill		12,261		12,364
	$	48,049	$	47,904
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term borrowings (Note 15)	$	545	$	1,155
Accounts payable and other current liabilities		1,966		1,970
Regulatory liabilities (Note 5)		479		492
Current installments of long-term debt (Note 6)		1,090		251
Current installments of capital lease and finance obligations		76		76
		4,156		3,944
Other liabilities		1,232		1,279
Regulatory liabilities (Note 5)		1,548		1,691
Deferred income taxes		3,323		3,263
Long-term debt (Note 6)		20,277		20,817
Capital lease and finance obligations		451		460
		30,987		31,454
Shareholders’ equity
Common shares (1) (Note 7)		11,340		10,762
Preference shares		1,623		1,623
Additional paid-in capital		12		12
Accumulated other comprehensive income		653		745
Retained earnings		1,583		1,455
Total Fortis Inc. shareholders’ equity		15,211		14,597
Non-controlling interests		1,851		1,853
		17,062		16,450
	$	48,049	$	47,904

(1)	No par value. Unlimited authorized shares; 415.6 million and 401.5 million issued and outstanding as at March 31, 2017 and December 31, 2016, respectively

Commitments and Contingencies (Note 17)

See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.

Consolidated Statements of Earnings (Unaudited)

For the three months ended March 31

(in millions of Canadian dollars, except per share amounts)

		Quarter Ended
		2017		2016
Revenue		$	2,274	$	1,772
Expenses
	Energy supply costs		754		707
	Operating		582		474
	Depreciation and amortization		297		234
			1,633		1,415
Operating income			641		357
Other income (expenses), net (Note 10)			31		16
Finance charges (Note 11)			229		143
Earnings before income taxes			443		230
Income tax expense			106		42
Net earnings		$	337	$	188
Net earnings attributable to:
	Non-controlling interests	$	27	$	7
	Preference equity shareholders		16		19
	Common equity shareholders		294		162
		$	337	$	188
Earnings per common share (Note 12)
	Basic	$	0.72	$	0.57
	Diluted	$	0.72	$	0.57
See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.

Consolidated Statements of Comprehensive Income (Unaudited)

For the three months ended March 31

(in millions of Canadian dollars)

		Quarter Ended
		2017			2016
Net earnings		$	337		$	188
Other comprehensive (loss) income
Unrealized foreign currency translation losses, net of hedging activities and tax			(92	)		(269	)
Net change in available-for-sale investment, net of tax			–			3
			(92	)		(266	)
Comprehensive income		$	245		$	(78	)
Comprehensive income attributable to:
	Non-controlling interests	$	27		$	7
	Preference equity shareholders		16			19
	Common equity shareholders		202			(104	)
		$	245		$	(78	)
See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
		Quarter Ended
		2017			2016
Operating activities
Net earnings		$	337		$	188
Adjustments to reconcile net earnings to net cash provided by operating activities:
	Depreciation – capital assets		266			209
	Amortization – intangible assets		24			18
	Amortization – other		7			7
	Deferred income tax expense		72			2
	Accrued employee future benefits		1			13
	Equity component of allowance for funds used during construction (Note 10)		(17	)		(7	)
	Other		22			21
Change in long-term regulatory assets and liabilities			(7	)		2
Change in working capital (Note 13)			(164	)		30
			541			483
Investing activities
Change in other assets and other liabilities			(24	)		(8	)
Capital expenditures – capital assets			(669	)		(409	)
Capital expenditures – intangible assets			(40	)		(17	)
Contributions in aid of construction			13			11
Proceeds on sale of assets			1			10
			(719	)		(413	)
Financing activities
Change in short-term borrowings			(613	)		(32	)
Proceeds from long-term debt, net of issue costs			388			–
Repayments of long-term debt and capital lease and finance obligations			(16	)		(40	)
Net borrowings under committed credit facilities			65			92
Advances from non-controlling interests			1			–
Issue of common shares to an institutional investor (Note 7)			500			–
Issue of common shares, net of costs and dividends reinvested			14			19
Dividends
	Common shares, net of dividends reinvested		(98	)		(77	)
	Preference shares		(16	)		(19	)
	Subsidiary dividends paid to non-controlling interests		(17	)		(9	)
			208			(66	)
Effect of exchange rate changes on cash and cash equivalents			(1	)		(14	)
Change in cash and cash equivalents			29			(10	)
Cash and cash equivalents, beginning of period			269			242
Cash and cash equivalents, end of period		$	298		$	232

Supplementary Information to Consolidated Statements of Cash Flows (Note 13)

See accompanying Notes to Interim Consolidated Financial Statements

Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
		Common Shares		Preference Shares			Additional Paid-In Capital			Accumulated Other Comprehensive Income (Loss)			Retained Earnings			Non-Controlling Interests			Total Equity
		(Note 7)
As at January 1, 2017	$	10,762	$	1,623		$	12		$	745		$	1,455		$	1,853		$	16,450
Net earnings		–		–			–			–			310			27			337
Other comprehensive loss		–		–			–			(92	)		–			–			(92	)
Common share issues		578		–			(1	)		–			–			–			577
Stock-based compensation		–		–			1			–			–			–			1
Advances from non-controlling interests		–		–			–			–			–			1			1
Foreign currency translation impacts		–		–			–			–			–			(13	)		(13	)
Subsidiary dividends paid to non-controlling interests		–		–			–			–			–			(17	)		(17	)
Dividends declared on common shares ($0.40 per share)		–		–			–			–			(166	)		–			(166	)
Dividends declared on preference shares		–		–			–			–			(16	)		–			(16	)
As at March 31, 2017	$	11,340	$	1,623		$	12		$	653		$	1,583		$	1,851		$	17,062
As at January 1, 2016	$	5,867	$	1,820		$	14		$	791		$	1,388		$	473		$	10,353
Net earnings		–		–			–			–			181			7			188
Other comprehensive loss		–		–			–			(266	)		–			–			(266	)
Common share issues		50		–			(2	)		–			–			–			48
Stock-based compensation		–		–			1			–			–			–			1
Foreign currency translation impacts		–		–			–			–			–			(7	)		(7	)
Subsidiary dividends paid to non-controlling interests		–		–			–			–			–			(9	)		(9	)
Dividends declared on common shares ($0.375 per share)		–		–			–			–			(106	)		–			(106	)
Dividends declared on preference shares		–		–			–			–			(19	)		–			(19	)
As at March 31, 2016	$	5,917	$	1,820		$	13		$	525		$	1,444		$	464		$	10,183

See accompanying Notes to Interim Consolidated Financial Statements

FORTIS INC.

FORTIS INC. NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS

For the three months ended March 31, 2017 and 2016 (unless otherwise stated)

(Unaudited)

1. DESCRIPTION OF BUSINESS

NATURE OF OPERATIONS

Fortis Inc. (“Fortis” or the “Corporation”) is principally an international electric and gas utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated energy infrastructure, which is treated as a separate segment. The Corporation’s reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes profit and loss responsibility and is accountable for its own resource allocation.

The Corporation’s reportable segments and basis of segmentation is consistent with the Corporation’s 2016 annual audited consolidated financial statements.

REGULATED UTILITIES

The Corporation’s interests in regulated electric and gas utilities are as follows:

1. Regulated Electric Transmission Utility – United States: Comprised of ITC Holdings Corp. (“ITC Holdings”) and the electric transmission operations of its regulated operating subsidiaries, which include International Transmission Company, Michigan Electric Transmission Company, LLC, ITC Midwest LLC, and ITC Great Plains, LLC, (collectively “ITC”). ITC was acquired by Fortis in October 2016, with Fortis owning 80.1% of ITC and an affiliate of GIC Private Limited owning a 19.9% minority interest.

2. Regulated Electric & Gas Utilities – United States: Comprised of UNS Energy, which primarily includes Tucson Electric Power Company, UNS Electric, Inc. and UNS Gas, Inc. (“UNS Gas”), and Central Hudson Gas & Electric Corporation (“Central Hudson”).

3. Regulated Gas Utility – Canadian: Represents FortisBC Energy Inc. (“FortisBC Energy”).

4. Regulated Electric Utilities – Canadian: Comprised of FortisAlberta Inc. (“FortisAlberta”), FortisBC Inc. (“FortisBC Electric”), and Eastern Canadian Electric Utilities. Eastern Canadian Electric Utilities is comprised of Newfoundland Power Inc., Maritime Electric Company, Limited and FortisOntario Inc.

5. Regulated Electric Utilities – Caribbean: Comprised of Caribbean Utilities Company, Ltd. (“Caribbean Utilities”), in which Fortis holds an approximate 60% controlling interest, two wholly owned utilities in the Turks and Caicos Islands, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively “Fortis Turks and Caicos”), and also includes the Corporation’s 33% equity investment in Belize Electricity Limited (“Belize Electricity”).

NON-REGULATED – ENERGY INFRASTRUCTURE

Non-Regulated – Energy Infrastructure is primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility (“Aitken Creek”) in British Columbia. Aitken Creek was acquired by Fortis in April 2016.

CORPORATE AND OTHER

The Corporate and Other segment captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments.

The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

These interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States (“US GAAP”) for interim financial statements. As a result, these interim consolidated financial statements do not include all of the information and disclosures required in the annual consolidated financial statements and should be read in conjunction with the Corporation’s 2016 annual audited consolidated financial statements. In management’s opinion, the interim consolidated financial statements include all adjustments that are of a recurring nature and necessary to present fairly the consolidated financial position of the Corporation.

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 and purchased power and the cost of natural gas, which are flowed through to customer without markup. Given the diversified nature of the Corporation’s subsidiaries, seasonality may vary. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric utilities in the United States are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.

The preparation of the interim consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances.

Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation’s regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary they are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.

An evaluation of subsequent events through May 1, 2017, the date these interim consolidated financial statements were approved by the Audit Committee of the Board of Directors, was completed to determine whether circumstances warranted recognition and disclosure of events or transactions in the interim consolidated financial statements as at March 31, 2017.

All amounts are presented in Canadian dollars unless otherwise stated.

These interim consolidated financial statements are comprised of the accounts of Fortis and its wholly owned subsidiaries and controlling ownership interests. All significant inter-company balances and transactions have been eliminated on consolidation, except as disclosed in Note 4.

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

New Accounting Policies

Simplifying the Test for Goodwill Impairment

Effective January 1, 2017, the Corporation adopted Accounting Standards Update (“ASU”) No. 2017-04, Simplifying the Test for Goodwill Impairment. The amendments in this update simplify the subsequent measurement of goodwill by eliminating step two in the current two-step goodwill impairment test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit’s carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. The above-noted ASU was applied prospectively and did not impact the Corporation’s interim unaudited consolidated financial statements for the three months ended March 31, 2017.

3. FUTURE ACCOUNTING PRONOUNCEMENTS

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

Revenue from Contracts with Customers

ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and can be applied consistently across various transactions, industries and capital markets. In 2016 a number of additional ASUs were issued that clarify implementation guidance in ASC Topic 606. This standard, and all related ASUs, is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted for annual and interim periods beginning after December 15, 2016. The Corporation has elected not to early adopt.

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

The majority of the Corporation’s revenue is generated from energy sales to retail customers based on published tariff rates, as approved by the respective regulators, and from transmission services and is considered to be in the scope of ASU No. 2014-09. Fortis does not expect that the adoption of this standard, and all related ASUs, will have a material impact on the recognition of revenue; however, the Corporation does expect it will impact its required disclosures. Certain specific interpretative issues remain outstanding and the conclusions reached, if different than currently anticipated, could have a material impact on the Corporation’s consolidated financial statements and related disclosures. Fortis continues to closely monitor developments related to the new standard.

Recognition and Measurement of Financial Assets and Financial Liabilities

ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial asset. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

Leases

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

Measurement of Credit Losses on Financial Instruments

ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

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

ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, was issued in March 2017 and the amendments in this update require that an employer disaggregate the current service costs component of net benefit cost and present it in the same statement of earnings line item(s) as other employee compensation costs arising from services rendered. The other components of net benefit cost are required to be presented separately from the service cost component and outside of operating income. Additionally, the amendments allow only the service cost component to be eligible for capitalization when applicable. This update is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted. The amendments in this update should be applied retrospectively for the presentation of the net periodic benefit costs and prospectively, on and after the effective date, for the capitalization in assets of only the service cost component of net periodic benefit costs. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

4. SEGMENTED INFORMATION

Information by reportable segment is as follows:

	REGULATED									NON-REGULATED
	United States			Canada						Energy Infrastructure	Corporate and Other		Intersegment eliminations		Total
Quarter Ended March 31, 2017 ($ millions)	ITC	UNS Energy	Central Hudson	FortisBC Energy	Fortis Alberta	FortisBC Electric	Eastern Canadian	Caribbean Electric	Total
Revenue	395	458	258	449	147	113	332	70	2,222	56	–		(4	)	2,274
Energy supply costs	–	171	85	182	–	46	236	33	753	1	–		–		754
Operating expenses	112	147	110	72	52	23	35	10	561	13	12		(4	)	582
Depreciation and amortization	54	66	17	50	49	16	23	14	289	8	–		–		297
Operating income (loss)	229	74	46	145	46	28	38	13	619	34	(12	)	–		641
Other income (expenses), net	10	12	2	4	1	–	–	2	31	–	–		–		31
Finance charges	63	26	10	29	22	9	14	5	178	1	50		–		229
Income tax expense (recovery)	65	19	15	23	–	4	6	–	132	5	(31	)	–		106
Net earnings (loss)	111	41	23	97	25	15	18	10	340	28	(31	)	–		337
Non-controlling interests	20	–	–	–	–	–	–	2	22	5	–		–		27
Preference share dividends	–	–	–	–	–	–	–	–	–	–	16		–		16
Net earnings (loss) attributable to common equity shareholders	91	41	23	97	25	15	18	8	318	23	(47	)	–		294
Goodwill	8,167	1,837	600	913	227	235	67	188	12,234	27	–		–		12,261
Identifiable assets	9,923	7,067	2,597	5,263	3,913	1,924	2,358	1,163	34,208	1,532	159		(111	)	35,788
Total assets	18,090	8,904	3,197	6,176	4,140	2,159	2,425	1,351	46,442	1,559	159		(111	)	48,049
Gross capital expenditures	268	127	50	94	93	21	27	25	705	4	–		–		709
Quarter Ended March 31, 2016
($ millions)
Revenue	–	440	249	406	142	104	329	75	1,745	29	1		(3	)	1,772
Energy supply costs	–	180	81	134	–	40	234	37	706	1	–		–		707
Operating expenses	–	153	104	71	48	22	35	12	445	7	25		(3	)	474
Depreciation and amortization	–	67	16	50	45	14	22	13	227	7	–		–		234
Operating income (loss)	–	40	48	151	49	28	38	13	367	14	(24	)	–		357
Other income (expenses), net	–	2	1	3	2	–	–	3	11	2	3		–		16
Finance charges	–	26	10	31	20	10	14	3	114	1	28		–		143
Income tax expense (recovery)	–	4	15	31	–	3	6	–	59	–	(17	)	–		42
Net earnings (loss)	–	12	24	92	31	15	18	13	205	15	(32	)	–		188
Non-controlling interests	–	–	–	–	–	–	–	3	3	4	–		–		7
Preference share dividends	–	–	–	–	–	–	–	–	–	–	19		–		19
Net earnings (loss) attributable to common equity shareholders	–	12	24	92	31	15	18	10	202	11	(51	)	–		162
Goodwill	–	1,794	585	913	227	235	67	184	4,005	–	–		–		4,005
Identifiable assets	–	6,529	2,437	5,066	3,638	1,888	2,265	1,027	22,850	1,052	236		(127	)	24,011
Total assets	–	8,323	3,022	5,979	3,865	2,123	2,332	1,211	26,855	1,052	236		(127	)	28,016
Gross capital expenditures	–	120	58	87	79	19	28	22	413	13	–		–		426

Related-party and inter-company transactions

Related-party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. There were no material related-party transactions for the three months ended March 31, 2017 and 2016.

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

	Quarter Ended
	March 31
($ millions)	2017	2016
Sale of capacity from Waneta Expansion to FortisBC Electric (Note 18)	16	15
Sale of energy from Belize Electric Company Limited to Belize Electricity	7	8
Lease of gas storage capacity from Aitken Creek to FortisBC Energy	8	–

As at March 31, 2017, accounts receivable on the Corporation’s consolidated balance sheet included approximately $9 million due from Belize Electricity (December 31, 2016 – $16 million), in which Fortis holds a 33% equity investment.

From time to time, the Corporation provides short-term financing to certain of its subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements, bearing interest at rates that approximate the Corporation’s cost of short-term borrowing, and provides long-term financing to certain of its subsidiaries, bearing interest at rates that approximate the Corporation’s cost of long-term debt. There were no inter-segment loans outstanding as at March 31, 2017 and December 31, 2016 and there was no interest charged for the three months ended March 31, 2017 (less than $1 million for the three months ended March 31, 2016).

5. REGULATORY ASSETS AND LIABILITIES

A summary of the Corporation’s regulatory assets and liabilities is provided below. For a detailed description of the nature of the Corporation’s regulatory assets and liabilities, refer to Note 8 to the Corporation’s 2016 annual audited consolidated financial statements.

	As at
	March 31,		December 31,
($ millions)	2017		2016
Regulatory assets
Deferred income taxes	1,259		1,260
Employee future benefits	563		576
Deferred energy management costs	187		178
Rate stabilization accounts	180		183
Deferred lease costs	106		97
Manufactured gas plant site remediation deferral	84		107
Deferred operating overhead costs	82		78
Natural gas for transportation incentives	36		40
Other regulatory assets	423		414
Total regulatory assets	2,920		2,933
Less: current portion	(325	)	(313	)
Long-term regulatory assets	2,595		2,620

	As at
	March 31,		December 31,
($ millions)	2017		2016
Regulatory liabilities
Non-asset retirement obligation removal cost provision	1,216		1,194
Rate stabilization accounts	217		230
Return on equity refund liability	187		346
Electric and gas moderator account	65		71
Renewable energy surcharge	56		53
Energy efficiency liability	56		49
Employee future benefits	39		42
Other regulatory liabilities	191		198
Total regulatory liabilities	2,027		2,183
Less: current portion	(479	)	(492	)
Long-term regulatory liabilities	1,548		1,691

6. LONG-TERM DEBT

	As at
	March 31,		December 31,
($ millions)	2017		2016
Long-term debt	20,485		20,246
Long-term classification of credit facility borrowings (Note 15)	1,030		973
Total long-term debt (Note 14)	21,515		21,219
Less: Deferred financing costs and debt discounts	(148	)	(151	)
Less: Current installments of long-term debt	(1,090	)	(251	)
	20,277		20,817

In March 2017 ITC entered into 1-year and 2-year unsecured term loan credit agreements at floating interest rates of a one-month LIBOR plus a spread of 0.90% and 0.65%, respectively. As at March 31, 2017, borrowings under the term loan credit agreements were US$200 million and US$50 million, respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes.

In March 2017 Caribbean Utilities issued 15-year US$40 million 3.90% unsecured notes. The net proceeds from the offering were used to finance capital expenditures and repay short-term borrowings.

In April 2017 ITC issued 30-year US$200 million 4.16% secured first mortgage bonds. The net proceeds from the issuance was used to repay credit facility borrowings and for general corporate purposes.

7. COMMON SHARES

Common shares issued during the period were as follows.

		Quarter Ended
		March 31, 2017
		Number
		of Shares	Amount
		(in thousands)	($ millions)
Balance, beginning of period		401,486	10,762
	Private Offering	12,195	500
	Dividend Reinvestment Plan	1,504	63
	Stock Option Plans	236	8
	Employee Share Purchase Plan	140	6
	Consumer Share Purchase Plan	8	1
	Conversion of Convertible Debentures	2	–
Balance, end of period		415,571	11,340

Private Offering

In March 2017 Fortis issued approximately 12.2 million common shares to an institutional investor, representing share consideration of $500 million at a price of $41.00 per share. The net proceeds were used to repay short-term borrowings (Note 15).

8. STOCK-BASED COMPENSATION PLANS

For the three months ended March 31, 2017, stock-based compensation expense of approximately $12 million was recognized ($9 million for the three months ended March 31, 2016).

Stock Options

In February 2017 the Corporation granted 774,924 options to purchase common shares under its 2012 Stock Option Plan (“2012 Plan”) at the five-day volume weighted average trading price immediately preceding the date of grant of $42.36. The options granted under the 2012 Plan are exercisable for a period not to exceed ten years from the date of grant, expire no later than three years after the termination, death or retirement of the optionee and vest evenly over a four-year period on each anniversary of the date of grant. Directors are not eligible to receive grants of options under the 2012 Plan.

The fair value of each option granted was $3.22 per option. The fair value was estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions:

Dividend yield (%)	3.8
Expected volatility (%)	16.1
Risk-free interest rate (%)	1.2
Weighted average expected life (years)	5.6

Directors’ Deferred Share Unit Plan

In January 2017, 8,351 Deferred Share Units (“DSUs”) were granted to the Corporation’s Board of Directors, representing the first quarter equity component of the Directors’ annual compensation and, where opted, their first quarter component of annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is entitled to accrue notional common share dividends equivalent to those declared by the Corporation’s Board of Directors. The DSUs are fully vested at the date of grant.

Performance Share Unit Plans

In the first quarter of 2017, the Corporation granted 720,316 Performance Share Units (“PSUs”) to senior management of the Corporation and its subsidiaries, with the exception of ITC where PSUs were granted to all employees. The Corporation’s PSU Plans represent a component of long-term compensation. Each PSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting and performance period, at which time a cash payment may be made. Each PSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation’s Board of Directors. As at March 31, 2017, the estimated payout percentages for the grants under the 2013 and 2015 PSU Plans ranged from 90% to 113%.

Restricted Share Unit Plans

In the first quarter of 2017, the Corporation granted 329,468 Restricted Share Units (“RSUs”) to senior management of the Corporation and its subsidiaries, with the exception of ITC where RSUs were granted to all employees. The Corporation’s RSU Plan represents a component of long-term compensation. Each RSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting period, at which time a cash payment may be made. Each RSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation’s Board of Directors.

9. EMPLOYEE FUTURE BENEFITS

The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group Registered Retirement Savings Plans and group 401(k) plans, for employees. The Corporation and certain subsidiaries also offer other post-employment benefit (“OPEB”) plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following tables.

	Quarter Ended March 31
	Defined Benefit Pension Plans				OPEB Plans
($ millions)	2017		2016		2017		2016
Components of net benefit cost:
Service costs	19		16		7		4
Interest costs	29		27		6		6
Expected return on plan assets	(38	)	(36	)	(3	)	(3	)
Amortization of actuarial losses	11		12		–		–
Amortization of past service credits/plan amendments	–		–		(3	)	(3	)
Regulatory adjustments	–		2		1		2
Net benefit cost	21		21		8		6

For the three months ended March 31, 2017, the Corporation expensed $11 million ($8 million for the three months ended March 31, 2016) related to defined contribution pension plans.

10. OTHER INCOME (EXPENSES), NET

	Quarter Ended
	March 31
($ millions)	2017	2016
Equity component of allowance for funds used during construction (“AFUDC”)	17	7
Interest income	4	2
Equity income – Belize Electricity	1	2
Other	9	5
	31	16

11. FINANCE CHARGES

		Quarter Ended
		March 31
($ millions)		2017		2016
Interest:
	Long-term debt and capital lease and finance obligations	233		145
	Short-term borrowings	5		2
Acquisition credit facilities		–		4
Debt component of AFUDC		(9	)	(8	)
		229		143

12. EARNINGS PER COMMON SHARE

The Corporation calculates earnings per common share (“EPS”) on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the “if-converted” method for convertible securities.

EPS was as follows.

		Quarter Ended March 31
		2017				2016
		Net Earnings	Weighted			Net Earnings	Weighted
		to Common	Average			to Common	Average
		Shareholders	Shares			Shareholders	Shares
		($ millions)	(# millions)		EPS	($ millions)	(# millions)		EPS
Basic EPS		294	406.2	$	0.72	162	282.4	$	0.57
Effect of potential dilutive securities:
	Stock Options	–	0.7			–	0.6
	Preference Shares	–	–			2	5.6
Diluted EPS		294	406.9	$	0.72	164	288.6	$	0.57

13. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS

	Quarter Ended
	March 31
($ millions)	2017		2016
Change in working capital:
Accounts receivable and other current assets	(13	)	63
Prepaid expenses	1		(17	)
Inventories	51		51
Regulatory assets – current portion	(23	)	7
Accounts payable and other current liabilities	(6	)	(69	)
Regulatory liabilities – current portion	(174	)	(5	)
	(164	)	30
Non-cash investing and financing activities:
Additions to capital assets and intangible assets included in current and long-term liabilities	260		126
Common share dividends reinvested	62		29
Contributions in aid of construction included in current assets	11		4
Exercise of stock options into common shares	1		2

14. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS

Fair value is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value.

The three levels of the fair value hierarchy are defined as follows:

Level 1:	Fair value determined using unadjusted quoted prices in active markets;
Level 2:	Fair value determined using pricing inputs that are observable; and
Level 3:	Fair value determined using unobservable inputs only when relevant observable inputs are not available.

The fair values of the Corporation’s financial instruments, including derivatives, reflect point-in-time estimates based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation’s future consolidated earnings or cash flows.

The following table presents, by level within the fair value hierarchy, the Corporation’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement and there were no transfers between the levels in the periods presented. For derivative instruments, the Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions.

		As at
	Fair value	March 31,		December 31,
($ millions)	hierarchy	2017		2016
Assets
Energy contracts subject to regulatory deferral (1) (2) (3)	Levels 1/2/3	11		19
Energy contracts not subject to regulatory deferral (1) (2)	Level 3	2		3
Interest rate swaps – cash flow hedges (4)	Level 2	11		11
Other investments (5)	Level 1	71		69
Total gross assets		95		102
Less: Counterparty netting not offset on the balance sheet (6)		(8	)	(9	)
Total net assets		87		93
Liabilities
Energy contracts subject to regulatory deferral (1) (2) (7)	Levels 2/3	43		26
Energy contracts not subject to regulatory deferral (1)	Level 2	1		9
Interest rate swaps – cash flow hedges (4)	Level 2	4		3
Total gross liabilities		48		38
Less: Counterparty netting not offset on the balance sheet (6)		(8	)	(9	)
Total net liabilities		40		29

(1)	The fair value of the Corporation’s energy contracts is recognized in accounts receivable and other current assets, long-term other assets, accounts payable and other current liabilities and long-term other liabilities. Unrealized gains and losses arising from changes in fair value of these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates as permitted by the regulators, with the exception of long-term wholesale trading contracts and certain gas swap contracts.
(2)	Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude and direction of the change for each input. The impacts of changes in fair value are subject to regulatory recovery, with the exception of long-term wholesale trading contracts and certain gas swap contracts.
(3)	As at March 31, 2017, includes – $8 million – level 2 and $3 million – level 3 (December 31, 2016 – $1 million -level 1, $13 million – level 2 and $5 million – level 3)
(4)	The fair value of the Corporation’s interest rate swaps is recognized in accounts receivable and other current assets, accounts payable and other current liabilities and long-term other liabilities.
(5)	Included in long-term other assets on the consolidated balance sheet.
(6)	Certain energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk and are netted by counterparty where the intent and legal right to offset exists.
(7)	As at March 31, 2017, includes $29 million – level 2 and $14 million – level 3 (December 31, 2016 – $21 million – level 2 and $5 million – level 3).

Derivative Instruments

The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments is the estimate of the amounts that the Corporation would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates.

Energy Contracts Subject to Regulatory Deferral

UNS Energy holds electricity power purchase contracts and gas swap contracts to reduce its exposure to energy price risk associated with purchased power and gas requirements. UNS Energy primarily applies the market approach for fair value measurements using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission and line losses. UNS Energy also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.

Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price for the defined commodities. The fair value of the swap contracts was calculated using forward pricing provided by independent third parties.

FortisBC Energy holds gas supply contracts and fixed price financial swaps to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The fair value of the natural gas derivatives was calculated using the present value of cash flows based on published market prices and forward curves for natural gas.

As at March 31, 2017, these energy contract derivatives were not designated as hedges; however, any unrealized gains or losses associated with changes in the fair value of the derivatives are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. These unrealized losses and gains would otherwise be recognized in earnings. As at March 31, 2017, unrealized losses of $33 million (December 31, 2016 – $19 million) were recognized in regulatory assets and unrealized gains of $1 million (December 31, 2016 – $12 million) were recognized in regulatory liabilities (Note 5).

Energy Contracts Not Subject to Regulatory Deferral

UNS Energy holds long-term wholesale trading contracts that qualify as derivative instruments. The unrealized gains and losses on these derivative instruments are recognized in earnings, as they do not qualify for regulatory deferral. Ten percent of any realized gains on these contracts are shared with customers through UNS Energy’s rate stabilization accounts.

Aitken Creek holds gas swap contracts to manage its exposure to changes in natural gas prices, to capture natural gas price spreads, and to manage the financial risk posed by physical transactions. The fair value of the gas swap contracts was calculated using forward pricing provided by third parties. The unrealized gains and losses on these derivative instruments are recognized in earnings.

Interest Rate Swaps – Cash Flow Hedges

As at March 31, 2017, ITC held forward-starting interest rate swaps, effective December 2017 and January 2018, with notional amounts totalling US$200 million and 10-year original terms. The agreements include a mandatory early termination provision and will be terminated no later than the effective dates. The interest rate swaps manage the interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the refinancing of maturing US$385 million long-term debt due in January 2018.

UNS Energy holds an interest rate swap, expiring in 2020, to mitigate its exposure to volatility in variable interest rates on capital lease obligations.

The unrealized gains and losses on cash flow hedges are recognized in other comprehensive income and reclassified to earnings as a component of interest expense over the life of the hedged debt. The loss expected to be reclassified to earnings within the next twelve months is estimated to be approximately $5 million. Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation’s consolidated statement of cash flows.

Volume of Derivative Activity

As at March 31, 2017, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.

	Maturity	Contracts
Volume(1)	(year)	(#)	2017	2018	2019	2020	2021	There-after
Energy contracts subject to regulatory deferral:
Electricity swap contracts (GWh)	2019	5	712	687	438	–	–	–
Electricity power purchase contracts (GWh)	2018	43	1,246	62	–	–	–	–
Gas swap contracts (PJ)	2020	109	27	21	9	1	–	–
Gas supply contract premiums (PJ)	2024	173	80	45	31	28	22	43
Energy contracts not subject to regulatory deferral:
Long-term wholesale trading contracts (GWh)	2018	20	1,177	108	–	–	–	–
Gas swap contracts (PJ)	2017	67	6	–	–	–	–	–

(1)	GWh means gigawatt hours and PJ means petajoules

Financial Instruments Not Carried At Fair Value

The following table discloses the estimated fair value measurements of the Corporation’s financial instruments not carried at fair value. The fair values were measured using Level 2 pricing inputs, except as noted. The carrying values of the Corporation’s consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows.

	As at
	March 31, 2017		December 31, 2016
($ millions)	Carrying Value	Estimated Fair Value	Carrying Value	Estimated Fair Value
Long-term debt, including current portion (Note 6) (1)	21,515	23,014	21,219	22,523
Waneta Partnership promissory note (2)	60	62	59	61

1.	The Corporation’s $200 million unsecured debentures due 2039, $500 million unsecured senior notes due 2023, and consolidated borrowings under credit facilities classified as long-term debt of $1,030 million (December 31, 2016 – $973 million) are valued using Level 1 inputs. All other long-term debt is valued using Level 2 inputs.
2.	Included in long-term other liabilities on the consolidated balance sheet.

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

15. FINANCIAL RISK MANAGEMENT

The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.

Credit risk	Risk that a counterparty to a financial instrument might fail to meet its obligations under the terms of the financial instrument.
Liquidity risk	Risk that an entity will encounter difficulty in raising funds to meet commitments associated with financial instruments.
Market risk	Risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices. The Corporation is exposed to foreign exchange risk, interest rate risk and commodity price risk.

Credit Risk

For cash equivalents, trade and other accounts receivable, and long-term other receivables, the Corporation’s credit risk is generally limited to the carrying value on the consolidated balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk, which include requiring customer deposits, prepayments and/or credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts.

ITC has a concentration of credit risk as a result of approximately 70% of its revenue being derived from three primary customers. Credit risk is limited as such customers have investment-grade credit ratings. ITC also reduces its exposure to credit risk by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors.

FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at March 31, 2017, FortisAlberta’s gross credit risk exposure was approximately $127 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $2 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.

UNS Energy, Central Hudson, FortisBC Energy and Aitken Creek may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The Companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist. They also limit credit risk by mostly dealing with counterparties that have investment-grade credit ratings. At UNS Energy, contractual arrangements also contain certain provisions requiring counterparties to derivative instruments to post collateral under certain circumstances.

Liquidity Risk

The Corporation’s consolidated financial position could be adversely affected if it, or one of its subsidiaries, fails to arrange sufficient and cost-effective financing to fund, among other things, capital expenditures, acquisitions and the repayment of maturing debt. The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the consolidated results of operations and financial position of the Corporation and its subsidiaries, conditions in capital and bank credit markets, ratings assigned by rating agencies and general economic conditions.

To help mitigate liquidity risk, the Corporation and its regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures, seasonal working capital requirements, and for general corporate purposes. In addition to its credit facilities, ITC uses commercial paper to finance its short-term cash requirements, and may use credit facility borrowings, from time to time, to repay borrowings under its commercial paper program.

The Corporation’s committed corporate credit facility is used for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from 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. As at March 31, 2017, over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $740 million. The combination of available credit facilities and reasonable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.

As at March 31, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.4 billion, of which approximately $3.8 billion was unused, including $909 million unused under the Corporation’s committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2017 through 2021.

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

						As at
		Regulated		Corporate		March 31,		December 31,
($ millions)		Utilities		and Other		2017		2016
Total credit facilities (1)		4,061		1,385		5,446		5,976
Credit facilities utilized:
	Short-term borrowings (1) (2)	(543	)	(2	)	(545	)	(1,155	)
	Long-term debt (Note 6) (3)	(640	)	(390	)	(1,030	)	(973	)
Letters of credit outstanding		(68	)	(51	)	(119	)	(119	)
Credit facilities unused (1)		2,810		942		3,752		3,729

(1)	Total credit facilities and short-term borrowings as at March 31, 2017 include $179 million (US$135 million) outstanding under ITC’s commercial paper program (December 31, 2016 – $195 million (US$145 million)). Outstanding commercial paper does not reduce available capacity under the Corporation’s consolidated credit facilities.
(2)	The weighted average interest rate on short-term borrowings was approximately 1.4% as at March 31, 2017 (December 31, 2016 – 1.7%).
(3)	As at March 31, 2017, credit facility borrowings classified as long-term debt included $123 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2016 – $61 million). The weighted average interest rate on credit facility borrowings classified as long-term debt was approximately 2.0% as at March 31, 2017 (December 31, 2016 – 1.8%).

As at March 31, 2017 and December 31, 2016, certain borrowings under the Corporation’s and subsidiaries’ long-term committed credit facilities were classified as long-term debt. It is management’s intention to refinance these borrowings with long-term permanent financing during future periods. The only significant change in credit facilities from that disclosed in the Corporation’s 2016 annual audited consolidated financial statements is as follows.

In March 2017 the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares (Note 7).

The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at March 31, 2017, the Corporation’s credit ratings were as follows.

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

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

Market Risk

Foreign Exchange Risk

The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, Fortis Turks and Caicos and BECOL is the US dollar. The Corporation’s earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of the Corporation’s foreign subsidiaries’ earnings.

As at March 31, 2017, the Corporation’s corporately issued US$3,496 million (December 31, 2016 – US$3,511 million) long-term debt had been designated as an effective hedge of a portion of the Corporation’s foreign net investments. As at March 31, 2017, the Corporation had approximately US$7,386 million (December 31, 2016 – US$7,250 million) in foreign net investments that were unhedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation’s corporately issued US dollar-denominated borrowings designated as effective hedges are recorded on the consolidated balance sheet in accumulated other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which gains and losses are also recorded on the consolidated balance sheet in accumulated other comprehensive income.

As a result of the acquisition of ITC, consolidated earnings and cash flows of Fortis are impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, it is estimated that a 5 cent increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.33 as at March 31, 2017 would increase or decrease earnings per common share of Fortis by approximately 7 cents. Management will continue to hedge future exchange rate fluctuations related to the Corporation’s foreign net investments and US dollar-denominated earnings streams, where appropriate, through future US dollar-denominated borrowings, and will continue to monitor the Corporation’s exposure to foreign currency fluctuations on a regular basis.

Interest Rate Risk

The Corporation and most of its subsidiaries are exposed to interest rate risk associated with borrowings under variable-rate credit facilities, variable-rate long-term debt and the refinancing of long-term debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk (Note 14).

Commodity Price Risk

UNS Energy is exposed to commodity price risk associated with changes in the market price of gas, purchased power and coal. Central Hudson is exposed to commodity price risk associated with changes in the market price of electricity and gas. FortisBC Energy is exposed to commodity price risk associated with changes in the market price of gas. The risks have been reduced by entering into derivative contracts that effectively fix the price of natural gas, power and electricity purchases. Aitken Creek is exposed to commodity price risk associated with changes in the market price of gas and enters into derivative contracts to manage the financial risk posed by physical transactions. These derivative instruments are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, as permitted by the regulators, for recovery from, or refund to, customers in future rates, except at Aitken Creek where the changes in fair value are recorded in earnings (Note 14).

16. BUSINESS ACQUISITIONS

As at March 31, 2017, the purchase price allocation related to ITC, acquired on October 14, 2016, remains preliminary pending final assessment of fair value estimates, income taxes, consideration transferred, and identification of assets and liabilities.

During the first quarter of 2017, the purchase price allocation related to Aitken Creek, acquired on April 1, 2016, was finalized with no material adjustments.

17. COMMITMENTS AND CONTINGENCIES

There were no material changes in the nature and amount of the Corporation’s commitments from those disclosed in the Corporation’s 2016 annual audited consolidated financial statements.

The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. The following describes the nature of the Corporation’s contingencies.

Central Hudson

Prior to and after its acquisition by Fortis, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,364 asbestos cases have been raised, 1,175 remained pending as at March 31, 2017. Of the cases no longer pending against Central Hudson, 2,033 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 156 cases. The Company is presently unable to assess the validity of the outstanding asbestos lawsuits; however, based on information known to Central Hudson at this time, including the Company’s experience in the settlement and/or dismissal of asbestos cases, Central Hudson believes that the costs that may be incurred in connection with the remaining lawsuits will not have a material effect on its financial position, results of operations or cash flows and, accordingly, no amount has been accrued in the consolidated financial statements.

FHI

In April 2013 FHI and Fortis were named as defendants in an action in the B.C. Supreme Court by the Coldwater Indian Band (“Band”). The claim is in regard to interests in a pipeline right of way on reserve lands. The pipeline on the right of way was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of way and claims damages for wrongful interference with the Band’s use and enjoyment of reserve lands. In May 2016 the Federal Court entered a decision dismissing the Coldwater Band’s application for judicial review of the ministerial consent. The Band has appealed that decision. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.

Fortis and ITC

Following announcement of the acquisition of ITC in February 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan (“Superior Court”) and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified damages, and costs, including attorneys’ fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In January 2017 the Superior Court issued a revised scheduling order, which, among other things, requires the parties, including ITC, to complete discovery by May 2017, and set a trial date for September 2017. A hearing on the plaintiff’s motion for class certification was held in February 2017.

In March 2017 the parties reached an agreement in principle to settle the case, subject to formal documentation and court approval. The court stayed the matter, except for settlement-related proceedings, and scheduled a hearing on preliminary settlement approval for May 25, 2017. ITC Holdings does not expect the settlement, if approved, to have a significant impact on its financial condition or results of operations.

18. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to comply with current period presentation. Acquisition-related expenses of $20 million were previously included in other income, net of expenses, on the consolidated statement of earnings and have been reclassified to operating expenses and finance charges totalling $16 million and $4 million, respectively. Related-party transactions for the sale of energy from the Waneta Expansion to FortisBC Electric totalling $15 million in the first quarter of 2016 were previously eliminated on consolidation. Fortis no longer eliminates related-party transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities and, as a result, revenue and energy supply costs each increased by $15 million (Note 4).

Ms. Janet Craig
Vice President, Investor Relations
Fortis Inc.
709.737.2900

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