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Fortis Reports Third Quarter Earnings of $278 million

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwired) -- 11/03/17 -- Fortis Inc. ("Fortis" or the "Corporation") (TSX: FTS)(NYSE: FTS), a leader in the North American regulated electric and gas utility industry, released its third quarter results today.

"Strong third quarter results continue to demonstrate the benefit of the acquisition of electric transmission company, ITC Holdings Corp., and the reasonable outcome in our first rate case in Arizona," said Barry Perry, President and Chief Executive Officer, Fortis.

Reported Net Earnings

The Corporation reported third quarter net earnings attributable to common equity shareholders of $278 million, or $0.66 per common share, compared to $127 million, or $0.45 per common share, for the same period in 2016. On a year-to-date basis, net earnings attributable to common equity shareholders were $829 million, or $2.00 per common share, compared to $396 million, or $1.40 per common share, for the same period in 2016.

--  Earnings per common share ("EPS") for the quarter was favourably
    impacted by earnings associated with the acquisition of ITC, the receipt
    of a $24 million break fee, net of transaction costs and tax, associated
    with the termination of the Waneta Dam acquisition, and higher earnings
    from the Aitken Creek natural gas storage facility, driven by unrealized
    gains on mark-to-market of derivatives.
--  Also contributing to the increase in the third quarter results compared
    to last year was the impact of the rate case settlement at UNS Energy,
    lower Corporate and Other expenses, primarily due to acquisition-related
    transaction costs associated with ITC recognized in the third quarter of
    2016, and higher earnings from FortisAlberta, partially offset by the
    favourable impact of the settlement of Springerville Unit 1 matters at
    UNS Energy recognized in the third quarter of 2016.

Adjusted Net Earnings(1)

On an adjusted basis, third quarter net earnings attributable to common equity shareholders were $254 million, or $0.61 per common share, an increase of $0.07 per common share over the same period in 2016. On a year-to-date basis, adjusted net earnings attributable to common equity shareholders were $794 million, or $1.92 per common share, an increase of $0.26 per common share over the same period in 2016.

--  ITC continues to perform consistent with expectations, delivering
    segmented net earnings of $89 million for the quarter. After considering
    the issuance of common shares and finance charges related to the
    acquisition, ITC had a $0.03 accretive impact on adjusted EPS for the
    quarter.
--  Aitken Creek contributed an additional $0.03 to adjusted EPS quarter
    over quarter, driven by unrealized gains on the mark-to-market of
    derivatives.
--  Also contributing to the increase in adjusted EPS quarter over quarter
    was the impact of the rate case settlement at UNS Energy and higher
    earnings from FortisAlberta, partially offset by the higher number of
    common shares outstanding associated with the Corporation's dividend
    reinvestment and share plans and unfavourable foreign exchange
    associated with the translation of US dollar-denominated earnings.

Hurricane Irma

In September Hurricane Irma damaged the transmission and distribution systems on the Turks and Caicos Islands. The Corporation responded quickly and currently 99% of electricity service has been restored to customers who can receive it. The local workforce of Fortis Turks and Caicos, along with crews from the Corporation's other utilities and contracted employees, continue to work hard to finish the task of reconnecting customers.

(1)Non-US GAAP Measures
   Fortis uses financial measures that do not have a standardized meaning
   under generally accepted accounting principles in the United States of
   America ("US GAAP") and may not be comparable to similar measures
   presented by other entities. Fortis calculated the non-US GAAP measures
   by adjusting certain US GAAP measures for specific items that impact
   comparability but which the Corporation does not consider part of normal,
   ongoing operations. Refer to the Financial Highlights section of the
   Corporation's Management Discussion and Analysis for further discussion
   of these items.

Capital expenditure plan on track and supported by strong cash flow

Capital expenditures for the nine months ended September 30, 2017 were $2.1 billion and the Corporation's consolidated capital expenditure plan of approximately $3.1 billion for 2017 remains on track.

Cash flow from operating activities totalled $2.0 billion for the nine months ended September 30, 2017, an increase of 41% over the same period in 2016. The increase reflects higher earnings, driven by ITC and UNS Energy, partially offset by timing differences in working capital.

Execution of growth strategy

The Corporation's capital expenditure program continues to address the energy infrastructure needs of customers, while modernizing energy networks to address the changes occurring in the utility industry. The Corporation's five-year capital expenditure program from 2018 through 2022 is expected to be approximately $14.5 billion, up $1.5 billion from the prior year's plan.

The five-year capital expenditure program now includes a natural gas pipeline expansion ("Eagle Mountain Woodfibre Gas Pipeline Project") and a multi-year Pipeline Integrity Management Program at FortisBC Energy, and the expected addition of 200 megawatts ("MW") of flexible generation resources and the 550 MW Gila River Generating Unit 2 at UNS Energy.

The Eagle Mountain Woodfibre Gas Pipeline Project, estimated at approximately $350 million, includes a pipeline expansion to a proposed liquefied natural gas ("LNG") site in Squamish, British Columbia. The project has received a number of approvals and remains contingent on Woodfibre LNG Limited proceeding with its LNG export facility. The multi-year Pipeline Integrity Management Program, estimated at approximately $300 million, is focused on improving pipeline safety and the integrity of the high-pressure transmission system, including pipeline modifications and looping.

The 200 MW of flexible generation resources, which will consist of 10 natural gas-fired reciprocating engines, is estimated at $230 million (US$180 million) with expected in-service dates between 2019 and 2020. The engines will provide ramping and peaking capabilities, replace aging, less efficient steam turbines and will facilitate the addition of renewable generating sources to the grid. The expected addition of the 550 MW natural gas-fired Gila River Generating Unit 2, estimated at $210 million (US$165 million), will assist with the replacement of retiring coal-fired generation facilities. This project will include an initial tolling agreement with a purchase option expected to be exercised in late 2019.

The Corporation continues to pursue additional investment opportunities within existing service territories. One such opportunity at ITC, not included in the five-year capital expenditure program, is the Lake Erie Connector project, which is a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line that would provide the first direct link between the markets of the Ontario Independent Electricity System Operator and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets. In October ITC received permits from the U.S. Army Corps of Engineers, which completes the project's major application process in the United States and Canada. Pending achievement of remaining milestones, the expected in-service date for the project is late 2021.

"After a very strategic and successful expansion into the United States, the Corporation is now focused on sustainable investment in its existing utilities. The opportunities that we are pursuing will enhance our ability to serve customers safely and reliably, grow our rate base, and support our 6% average annual dividend growth target," concluded Mr. Perry.

Outlook

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

Over the five-year period from 2018 through 2022, the Corporation's capital expenditure program is expected to total approximately $14.5 billion, up $1.5 billion from the prior year's plan and increasing rate base to almost $32 billion by 2022. The five-year capital expenditure program is driven by projects that improve the transmission grid, address natural gas system capacity and gas line network integrity, increase cyber protection and allow the grid to deliver cleaner energy. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends.

In October the Corporation announced a quarterly dividend increase of 6.25%, effective with the December 1 payment, translating into an annualized dividend of $1.70. This marks 44 consecutive years of annual common share dividend increases. Fortis has extended its guidance for targeted average annual dividend growth of approximately 6% through to 2022.

About Fortis

Fortis is a leader in the North American regulated electric and gas utility industry with total assets of approximately $47 billion as of September 30, 2017. More than 8,000 of the Corporation's employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.

Fortis shares are listed on the TSX and NYSE and trade under the symbol FTS. Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov.

Forward-Looking Information

Fortis includes "forward-looking information" in this media release within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995 (collectively referred to as "forward-looking information"). Forward-looking information included in this media release reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which includes, without limitation: the Corporation's forecast consolidated capital spending for 2017 and the five-year period from 2018 through 2022; the nature, timing and expected costs of certain capital projects including, without limitation, the FortisBC Eagle Mountain Woodfibre Gas Pipeline Project and UNS Energy flexible generation resource investment and combined cycle generation purchase; additional opportunities beyond the base capital plan including the Lake Erie Connector; the expectation that the Corporation's 2017 results will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy; the Corporation's consolidated forecast rate base for 2022; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; and targeted average annual dividend growth through 2022.

Forward-looking information involves significant risk, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information. These factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations generally, including those identified from time to time in the forward-looking information. Such risk factors or assumptions include, but are not limited to: reasonable decisions by utility regulators and the expectation of regulatory stability; the implementation of the Corporation's five-year capital plan; no material capital project and financing cost overrun related to any of the Corporation's capital projects; sufficient human resources to deliver service and execute the capital program; the realization of additional opportunities; fluctuating foreign exchange; and the Board exercising its discretion to declare dividends, taking into account the business performance and financial condition of the Corporation. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. For additional information with respect to certain of these risks or factors, reference should be made to the continuous disclosure materials filed from time to time by the Corporation with Canadian securities regulatory authorities and the Securities and Exchange Commission. Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.

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            Teleconference to Discuss Third Quarter 2017 Results

A teleconference and webcast will be held on November 3 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 third 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 December 3, 2017. Please call 1.800.585.8367 or
416.621.4642 and enter pass code 92431300.
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Interim Management Discussion and Analysis

For the three and nine months ended September 30, 2017

Dated November 2, 2017

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                              TABLE OF CONTENTS
Forward-Looking Information       1    Summary of Consolidated Cash Flows 17
Corporate Overview                3    Contractual Obligations            19
Significant Items                 3    Capital Structure                  19
Financial Highlights              4    Credit Ratings                     19
Segmented Results of Operations   7    Capital Expenditure Program        20
Regulated Electric & Gas               Additional Investment
Utilities - United States         8    Opportunities                      21
  ITC                             8    Cash Flow Requirements             22
  UNS Energy                      8    Credit Facilities                  23
  Central Hudson                  9  Off-Balance Sheet Arrangements       24
Regulated Gas Utility - Canadian 10  Business Risk Management             24
  FortisBC Energy                10  Changes in Accounting Policies       24
Regulated Electric Utilities -       Future Accounting Pronouncements
Canadian                         10                                       24
  FortisAlberta                  10  Financial Instruments                26
  FortisBC Electric              11  Critical Accounting Estimates        27
  Eastern Canadian Electric          Related-Party and Inter-Company
  Utilities                      11  Transactions                         28
Regulated Electric Utilities -       Summary of Quarterly Results
Caribbean                        12                                       29
Non-Regulated - Energy               Outlook
Infrastructure                   13                                       30
Corporate and Other              13  Outstanding Share Data               30
Regulatory Highlights                Condensed Consolidated Interim
                                 14  Financial Statements (Unaudited)    F-1
Consolidated Financial Position  16
Liquidity and Capital Resources  17

FORWARD-LOOKING INFORMATION

The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. The MD&A should be read in conjunction with the unaudited condensed consolidated interim financial statements and notes thereto for the three and nine months ended September 30, 2017 and the MD&A and audited consolidated financial statements for the year ended December 31, 2016 included in the Corporation's 2016 Annual Report. Financial information contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") and is presented in Canadian dollars unless otherwise specified.

Fortis includes "forward-looking information" in the MD&A within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, collectively referred to as "forward-looking information". Forward-looking information included in the MD&A reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which include, without limitation: the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions;

the Corporation's forecast gross consolidated and segmented capital expenditures for 2017 and for the period from 2018 through 2022; the nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas ("LNG") facility and the Eagle Mountain Woodfibre Gas Pipeline Project at FortisBC, flexible generation resource investment and combined cycle generation purchase at UNS Energy and additional opportunities beyond the base capital expenditure program including the Lake Erie Connector Project and the Wataynikaneyap Project; the expectation that subsidiary operating expenses and interest costs will be paid out of subsidiary operating cash flows; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis; the expectation that maintaining the targeted capital structure of the Corporation's regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; the expectation that cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions will be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2017; the intent of management to refinance certain borrowings under Corporation's and subsidiaries' long-term committed credit facilities with long-term permanent financing; the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements; 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 Corporation's 2017 results will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy; the Corporation's consolidated forecast rate base for 2022; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends, and targeted average annual dividend growth through 2022.

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

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

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

CORPORATE OVERVIEW

Fortis is a leader in the North American regulated electric and gas utility business, with total assets of approximately $47 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 September 30, 2017, the Corporation's electricity systems met a combined peak demand of 31,917 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,567 terajoules. For additional information on the Corporation's operations and business segments, refer to Note 1 to the Corporation's unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2017 and to the "Corporate Overview" section of the 2016 Annual MD&A.

SIGNIFICANT ITEMS

Terminated Acquisition of Interest in Waneta Dam: In May 2017 Fortis had entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia. In August 2017 BC Hydro exercised its right of first offer to acquire Teck's two-thirds interest in the Waneta Dam and the purchase agreement between Fortis and Teck was terminated, resulting in the payment of a $28 million break fee ($24 million net of related transaction costs and tax) to Fortis.

FINANCIAL HIGHLIGHTS

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

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Consolidated Financial Highlights
Periods Ended September 30                   Quarter            Year-to-Date
($ millions, except for
 common share data)            2017    2016 Variance   2017    2016 Variance
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Revenue                       1,901   1,528     373   6,190   4,785   1,405
Energy Supply Costs             478     503     (25)  1,756   1,698      58
Operating Expenses              504     439      65   1,657   1,367     290
Depreciation and
 Amortization                   290     234      56     885     700     185
Other Income, Net                23      10      13      78      35      43
Finance Charges                 225     164      61     686     457     229
Income Tax Expense              106      40      66     314     110     204
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Net Earnings                    321     158     163     970     488     482
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Net Earnings Attributable
 to:
  Non-Controlling Interests      27       9      18      92      33      59
  Preference Equity
   Shareholders                  16      22      (6)     49      59     (10)
  Common Equity Shareholders    278     127     151     829     396     433
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Net Earnings                    321     158     163     970     488     482
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Earnings per Common Share
  Basic ($)                    0.66    0.45    0.21    2.00    1.40    0.60
  Diluted ($)                  0.66    0.45    0.21    2.00    1.39    0.61
Weighted Average Number of
 Common Shares Outstanding
 (# millions)                 418.6   285.0   133.6   413.9   283.7   130.2
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Cash Flow from Operating
 Activities                     800     478     322   1,990   1,409     581
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Revenue

The increase in revenue for the quarter and year to date was driven by the acquisition of ITC in October 2016, higher revenue at UNS Energy, and the flow through in customer rates of higher overall energy supply costs, partially offset by unfavourable foreign exchange associated with the translation of US dollar-denominated revenue. The increase in revenue at UNS Energy was mainly due to the impact of the rate case settlement, United States Federal Energy Regulatory Commission ("FERC") ordered transmission refunds recognized in the third quarter and year-to-date 2016 of $11 million ($7 million after tax) and $29 million ($18 million after tax), respectively, and higher short-term wholesale sales. The increase in revenue at UNS Energy was partially offset by $17 million ($10 million after tax) in revenue related to the settlement of Springerville Unit 1 matters recognized in the third quarter of 2016.

Energy Supply Costs

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

The increase in energy supply costs year to date was primarily 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 for the quarter and year to date was primarily due to the acquisition of ITC, and general inflationary and employee-related cost increases. The increase was partially offset by the receipt of a $28 million break fee ($24 million net of related transaction costs and tax) associated with the termination of the Waneta Dam purchase agreement in the third quarter of 2017, acquisition-related transaction costs of $4 million ($3 million after tax) and $39 million ($32 million after tax) for the third quarter and year-to-date 2016, respectively, associated with ITC, and favourable foreign exchange associated with the translation of US dollar-denominated operating expenses.

Depreciation and Amortization

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

Other Income, Net

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

Finance Charges

The increase in finance charges for the quarter and year to date was primarily due to the acquisition of ITC, including interest expense on debt issued to complete the financing of the acquisition. The increase was partially offset by acquisition-related transaction costs of $21 million ($16 million after tax) and $35 million ($26 million after tax) for the third quarter and year-to-date 2016, respectively, associated with ITC.

Income Tax Expense

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

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

The increase in net earnings attributable to common equity shareholders for the quarter was driven by earnings of $89 million at ITC, which was acquired in October 2016. The increase for the quarter was also due to: (i) lower Corporate and Other expenses, primarily due to the receipt of a break fee, net of related transaction costs, of $24 million associated with the termination of the Waneta Dam purchase agreement recognized in the third quarter of 2017, and $19 million in acquisition-related transactions costs associated with ITC recognized in the third quarter of 2016; (ii) higher earnings from the Aitken Creek natural gas storage facility ("Aitken Creek") related to the unrealized gain on the mark-to-market of derivatives quarter over quarter; (iii) strong performance at UNS Energy, largely due to the impact of the rate case settlement in 2017 and FERC-ordered refunds of $7 million in the third quarter of 2016; (iv) higher earnings at FortisAlberta due to an increase in capital tracker revenue; and (v) a lower loss at FortisBC Energy due to higher allowance for funds used during construction ("AFUDC") and lower operating expenses. The increase was partially offset by: (i) higher finance charges associated with the acquisition of ITC; (ii) the favourable settlement of Springerville Unit 1 matters at UNS Energy in the third quarter of 2016; (iii) unfavourable foreign exchange associated with the translation of US dollar-denominated earnings; (iv) lower contribution from the Caribbean, mainly due to the impact of Hurricane Irma and lower equity income from Belize Electricity Limited ("Belize Electricity"); and (v) business development costs related to the Wataynikaneyap Power Project.

The increase in net earnings attributable to common equity shareholders year to date was driven by earnings of $273 million at ITC. The year-to-date increase was also due to: (i) lower Corporate and Other expenses, primarily due to the receipt of a break fee, as discussed above for the quarter, and $58 million in acquisition-related transactions costs associated with ITC recognized year-to-date 2016; (ii) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives period over period and contribution from the first quarter of 2017; (iii) strong performance at UNS Energy, as discussed above for the quarter, as well as the overall favourable impact of $29 million associated with FERC-ordered refunds; and (iv) higher earnings from FortisBC Energy due to higher AFUDC. The increase was partially offset by: (i) higher finance charges associated with the acquisitions of ITC and Aitken Creek; (ii) the favourable settlement of Springerville Unit 1 matters, as discussed above for the quarter; (iii) lower contribution from the Caribbean, as discussed above for the quarter; (iv) unfavourable foreign exchange associated with the translation of US dollar-denominated earnings; and (v) business development costs related to the Wataynikaneyap Power Project.

Earnings per common share for the quarter and year to date were $0.21 and $0.60 higher, respectively, compared to the same periods in 2016. The impact of the above-noted items on net earnings attributable to common equity shareholders was 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.

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

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

The Corporation calculates adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes are not reflective of the normal, ongoing operations of the business. For the quarter and year-to-date periods ended September 30, 2017 and 2016, the Corporation adjusted net earnings attributable to common equity shareholders for: (i) an acquisition break fee; (ii) acquisition-related transactions costs; and (iii) cumulative adjustments for regulatory decisions pertaining to prior periods considered to be outside the normal course of business for the periods presented. The Corporation no longer excludes mark-to-market adjustments related to derivative instruments at Aitken Creek, which occur in the normal course of Aitken Creek's business, in its calculation of adjusted net earnings attributable to common equity shareholders as comparative information is now presented in reported net earnings.

The adjusting items described above do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar adjustments presented by other companies.

The Corporation calculates adjusted basic earnings per common share by dividing adjusted net earnings attributable to common equity shareholders by the weighted average number of common shares outstanding.

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

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Non-US GAAP Reconciliation
Periods Ended September 30                   Quarter            Year-to-Date
($ millions, except for
 common share data)            2017    2016 Variance   2017    2016 Variance
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Net Earnings Attributable to
 Common Equity Shareholders     278     127     151     829     396     433
Adjusting Items:
UNS Energy -
  Settlement of FERC-ordered
   transmission refunds           -       -       -     (11)      -     (11)
  FERC-ordered transmission
   refunds                        -       7      (7)      -      18     (18)
Corporate and Other -
  Acquisition break fee         (24)      -     (24)    (24)      -     (24)
  Acquisition-related
   transaction costs              -      19     (19)      -      58     (58)
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Adjusted Net Earnings
 Attributable to Common
 Equity Shareholders            254     153     101     794     472     322
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Adjusted Basic Earnings Per
 Common Share ($)              0.61    0.54    0.07    1.92    1.66    0.26
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Weighted Average Number of
 Common Shares Outstanding
 (# millions)                 418.6   285.0   133.6   413.9   283.7   130.2
----------------------------------------------------------------------------

SEGMENTED RESULTS OF OPERATIONS

----------------------------------------------------------------------------
Segmented Net Earnings Attributable to Common Equity Shareholders
Periods Ended September 30                   Quarter            Year-to-Date
($ millions)                   2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Regulated Electric & Gas
 Utilities- United States
  ITC                            89       -      89     273       -     273
  UNS Energy                    112     102      10     242     170      72
  Central Hudson                 15      14       1      48      50      (2)
Regulated Gas Utility -
 Canadian
  FortisBC Energy               (15)    (19)      4      88      81       7
Regulated Electric Utilities
 - Canadian
  FortisAlberta                  35      30       5      91      91       -
  FortisBC Electric              11      11       -      42      41       1
  Eastern Canadian               12      14      (2)     48      48       -
Regulated Electric Utilities
 - Caribbean                      8      13      (5)     25      34      (9)
Non-Regulated - Energy
 Infrastructure                  21      15       6      69      45      24
Corporate and Other             (10)    (53)     43     (97)   (164)     67
----------------------------------------------------------------------------
Net Earnings Attributable to
 Common Equity Shareholders     278     127     151     829     396     433
----------------------------------------------------------------------------

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

REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES

ITC

----------------------------------------------------------------------------
Financial Highlights (1)
Periods Ended September 30, 2017                      Quarter   Year-to-Date
----------------------------------------------------------------------------
Average US:CAD Exchange Rate (2)                         1.25           1.31
----------------------------------------------------------------------------
Revenue ($ millions)                                      376          1,179
Earnings ($ millions)                                      89            273
----------------------------------------------------------------------------
(1) Revenue represents 100% of ITC, while earnings represent the
    Corporation's 80.1% controlling ownership interest in ITC and reflects
    consolidated purchase price accounting adjustments.
(2) The reporting currency of ITC is the US dollar.

Revenue and Earnings

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

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

UNS ENERGY (1)

----------------------------------------------------------------------------
Financial Highlights                         Quarter            Year-to-Date
Periods Ended September 30     2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Average US:CAD Exchange
 Rate(2)                       1.25    1.31   (0.06)   1.31    1.32   (0.01)
----------------------------------------------------------------------------
Electricity Sales (gigawatt
 hours ("GWh"))               4,416   4,379      37  11,418  11,031     387
Gas Volumes (petajoules
 ("PJ"))                          1       1       -       9       9       -
Revenue ($ millions)            599     604      (5)  1,609   1,534      75
Earnings ($ millions)           112     102      10     242     170      72
----------------------------------------------------------------------------
(1) Includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. and
    UNS Gas, Inc.
(2) The reporting currency of UNS Energy is the US dollar.

Electricity Sales & Gas Volumes

The increase in electricity sales for the quarter was primarily due to higher long-term wholesale sales due to the commencement of a new contract in 2017, partially offset by lower short-term wholesale sales. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings.

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

Gas volumes were comparable with the same periods in 2016.

Revenue

The decrease in revenue for the quarter was due to: (i) approximately $25 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue; (ii) $17 million (US$13 million), or $10 million (US$8 million) after tax, in revenue related to the settlement of Springerville Unit 1 matters in the third quarter of 2016; and (iii) lower revenue related to a decrease in fuel cost recovery rates, which has no impact on earnings. The decrease was partially offset by the impact of the rate case settlement effective February 27, 2017, approximately $11 million (US$9 million), or $7 million (US$5 million) after tax, in FERC-ordered transmission refunds recognized in the third quarter of 2016, and higher long-term wholesale sales as discussed above.

The increase in revenue year to date was due to: (i) the impact of the rate case settlement; (ii) approximately $29 million (US$22 million), or $18 million (US$13 million) after tax, in FERC-ordered transmission refunds recognized year-to-date 2016; (iii) higher short-term wholesale sales; and (iv) the reversal of $7 million (US$5 million), or $4 million (US$3 million) after-tax, in transmission refund accruals in the second quarter of 2017. The increase was partially offset by approximately $20 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue, revenue related to the settlement of Springerville Unit 1 matters, as discussed above, and lower revenue related to a decrease in fuel cost recovery rates.

Earnings

The increase in earnings for the quarter was primarily due to the impact of the rate case settlement and $7 million (US$5 million) in FERC-ordered transmission refunds in the third quarter of 2016. The increase was partially offset by $10 million (US$8 million) related to the favourable settlement of Springerville Unit 1 matters recognized in the third quarter of 2016, and approximately $2 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings.

The increase in earnings year to date was due to: (i) the impact of the rate case settlement; (ii) $18 million (US$13 million) in FERC-ordered transmission refunds year-to-date 2016; (iii) more favorably priced long-term wholesale sales; and (iv) approximately $11 million (US$8 million) related to the favourable settlement of FERC-ordered transmission refunds year-to-date 2017. The increase was partially offset by the favourable settlement of Springerville Unit 1 matters, as discussed above, and approximately $1 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings.

CENTRAL HUDSON

----------------------------------------------------------------------------
Financial Highlights                         Quarter            Year-to-Date
Periods Ended September 30     2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Average US:CAD Exchange
 Rate( 1)                      1.25    1.31   (0.06)   1.31    1.32   (0.01)
----------------------------------------------------------------------------
Electricity Sales (GWh)       1,318   1,513    (195)  3,696   3,917    (221)
Gas Volumes (PJ)                  3       5      (2)     16      18      (2)
Revenue ($ millions)            197     208     (11)    661     642      19
Earnings ($ millions)            15      14       1      48      50      (2)
----------------------------------------------------------------------------
(1) The reporting currency of Central Hudson is the US dollar.

Electricity Sales & Gas Volumes

The decrease in electricity sales for the quarter and year to date was primarily due to lower average consumption as a result of cooler temperatures. Also contributing to the year-to-date decrease was lower average consumption in the first quarter of 2017, as a result of warmer temperatures. The decrease in gas volumes for the quarter and year to date was due to reduced demand as a result of cooler temperatures.

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

Revenue

The decrease in revenue for the quarter was mainly due to lower electricity sales and approximately $8 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue. The decrease was partially offset by higher delivery revenue due to the increase in base electricity rates effective July 1, 2017.

The increase in revenue year to date was mainly due to higher delivery revenue from increases in base electricity rates effective July 1, 2017 and 2016 and the recovery from customers of higher commodity costs. The increase was partially offset by lower electricity sales and approximately $9 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.

Earnings

The increase in earnings for the quarter was primarily due to the increase in delivery revenue discussed above, partially offset by higher operating costs. The decrease in earnings year to date was due to higher operating expenses and the timing of unbilled revenue, which is not subject to the operation of the decoupling mechanism, partially offset by increases in delivery revenue. Earnings for the quarter and year to date were also impacted by approximately $1 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings.

REGULATED GAS UTILITY - CANADIAN

FORTISBC ENERGY

----------------------------------------------------------------------------
Financial Highlights                         Quarter            Year-to-Date
Periods Ended September 30     2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Gas Volumes (PJ)                 27      28      (1)    152     130      22
Revenue ($ millions)            156     151       5     832     758      74
(Loss) Earnings ($ millions)    (15)    (19)      4      88      81       7
----------------------------------------------------------------------------

Gas Volumes

Gas volumes for the quarter were comparable with the same period in 2016. The increase in gas volumes year to date was primarily due to growth in the number of customers and higher average consumption by residential and commercial customers as a result of colder temperatures in the first half of 2017. Also contributing to the increase was higher volumes for transportation customers due to additional customers switching to natural gas compared to alternative fuel sources.

Revenue

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

Earnings

The lower loss for the quarter was primarily due to higher AFUDC and lower operating expenses, partially offset by the timing of quarterly revenue and operating expenses compared to the same period in 2016.

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

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

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

----------------------------------------------------------------------------
Financial Highlights                         Quarter            Year-to-Date
Periods Ended September 30     2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Energy Deliveries (GWh)       4,156   4,081      75  12,690  12,436     254
Revenue ($ millions)            153     143      10     448     429      19
Earnings ($ millions)            35      30       5      91      91       -
----------------------------------------------------------------------------

Energy Deliveries

The increase in energy deliveries for the quarter and year to date was primarily due to higher average consumption by residential, commercial and irrigation customers, mainly due to warmer temperatures in the third quarter of 2017, partially offset by lower oil and gas activity. Growth in the number of residential and commercial customers also contributed to the year-to-date increase.

Revenue

The increase in revenue for the quarter and year to date was primarily due to an increase in capital tracker revenue, higher energy deliveries due to higher average consumption, 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. Growth in the number of residential and commercial customers also contributed to the year-to-date increase.

Earnings

The increase in earnings for the quarter was primarily due to higher capital tracker revenue, partially offset by lower customer rates, as discussed above, and higher finance charges.

Earnings year to date were comparable with the same period in 2016. The increase in earnings due to higher capital tracker revenue and customer growth was offset by higher finance charges and operating costs and lower customer rates.

FORTISBC ELECTRIC (1)

----------------------------------------------------------------------------
Financial Highlights                         Quarter            Year-to-Date
Periods Ended September 30     2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Electricity Sales (GWh)         779     728      51   2,436   2,263     173
Revenue ($ millions)             93      88       5     291     275      16
Earnings ($ millions)            11      11       -      42      41       1
----------------------------------------------------------------------------
(1) Includes the regulated operations of FortisBC Inc. and operating,
    maintenance and management services related to the Waneta, Brilliant and
    Arrow Lakes hydroelectric generating plants.

Electricity Sales

The increase in electricity sales for the quarter and year to date was primarily due to higher average consumption as a result of weather conditions.

Revenue

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

Earnings

Earnings for the quarter were comparable with the same period in 2016. The increase in earnings year to date was due to lower-than-anticipated operating expenses and higher AFUDC.

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

EASTERN CANADIAN ELECTRIC UTILITIES (1)

----------------------------------------------------------------------------
Financial Highlights                         Quarter            Year-to-Date
Periods Ended September 30     2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Electricity Sales (GWh)       1,507   1,540     (33)  6,178   6,167      11
Revenue ($ millions)            206     211      (5)    789     785       4
Earnings ($ millions)            12      14      (2)     48      48       -
----------------------------------------------------------------------------

(1) Comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime Electric Company, Limited and FortisOntario Inc. ("FortisOntario"). Also includes the Corporation's 49% equity investment in Wataynikaneyap Power Limited Partnership.

Electricity Sales

The decrease in electricity sales for the quarter was due to lower average consumption, partially offset by growth in the number of customers.

The increase in electricity sales year to date was primarily due to growth in the number of customers, partially offset by an overall decrease in consumption.

Revenue

The decrease in revenue for the quarter was primarily due to lower electricity sales and the flow through in customer electricity rates of lower energy supply costs, partially offset by an increase in customer electricity rates.

The increase in revenue year to date was due to higher electricity sales and an increase in customer electricity rates, partially offset by the flow through in customer electricity rates of lower energy supply costs.

Earnings

The decrease in earnings for the quarter was due to approximately $2 million in business development costs related to the Wataynikaneyap Power Project. For details on the Wataynikaneyap Power Project refer to the "Additional Investment Opportunities" section of this MD&A.

Earnings year to date were comparable with the same period in 2016. Lower-than-anticipated finance costs, an increase in customer electricity rates and higher electricity sales were offset by business development costs, as discussed above.

REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)

----------------------------------------------------------------------------
Financial Highlights                         Quarter            Year-to-Date
Periods Ended September 30     2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Average US:CAD Exchange
 Rate(2)                       1.25    1.31   (0.06)   1.31    1.32   (0.01)
----------------------------------------------------------------------------
Electricity Sales (GWh)         231     227       4     642     632      10
Revenue ($ millions)             77      79      (2)    227     225       2
Earnings ($ millions)             8      13      (5)     25      34      (9)
----------------------------------------------------------------------------
(1) Comprised of Caribbean Utilities Company, Ltd. ("Caribbean Utilities"),
    in which Fortis holds an approximate 60% controlling interest, and two
    wholly owned utilities, FortisTCI Limited and Turks and Caicos Utilities
    Limited (collectively "Fortis Turks and Caicos"). Also includes the
    Corporation's 33% equity investment in Belize Electricity.
(2) The reporting currency of Caribbean Utilities and Fortis Turks and
    Caicos is the US dollar. The reporting currency of Belize Electricity is
    the Belizean dollar, which is pegged to the US dollar at
    BZ$2.00=US$1.00.

Electricity Sales

The increase in electricity sales for the quarter and year to date was due to higher average consumption, partially offset by the impact of Hurricane Irma on Fortis Turks and Caicos.

Revenue

The decrease in revenue for the quarter was due to lower electricity sales as a result of the impact of Hurricane Irma and approximately $3 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue. The decrease was partially offset by the flow through in customer electricity rates of higher fuel costs.

The increase in revenue year to date was mainly due to the flow through in customer electricity rates of higher fuel costs and higher base electricity rates. The increase was partially offset by lower electricity sales as a result of the impact of Hurricane Irma and approximately $3 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.

Earnings

The decrease in earnings for the quarter and year to date was due to lower revenue as a result of the impact of Hurricane Irma and lower equity income from Belize Electricity. Also contributing to the decrease year to date was higher finance costs, primarily due to lower capitalized interest.

NON-REGULATED - ENERGY INFRASTRUCTURE (1)

----------------------------------------------------------------------------
Financial Highlights                         Quarter            Year-to-Date
Periods Ended September 30     2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Energy Sales (GWh)              180     181      (1)    781     786      (5)
Revenue ($ millions)             47      44       3     162     139      23
Earnings ($ millions)            21      15       6      69      45      24
----------------------------------------------------------------------------
(1) Primarily comprised of long-term contracted generation assets in British
    Columbia and Belize, with a combined generating capacity of 391 MW, and
    the Aitken Creek natural gas storage facility in British Columbia, with
    a total working gas capacity of 77 billion cubic feet.

Energy Sales

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

Revenue

The increase in revenue for the quarter and year to date was driven by Aitken Creek. Also reflected in the year-to-date increase was the contribution from Aitken Creek in the first quarter of 2017, due to its acquisition occurring in April 2016.

Earnings

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

CORPORATE AND OTHER (1)

----------------------------------------------------------------------------
Financial Highlights
Periods Ended September 30                   Quarter            Year-to-date
($ millions)                   2017    2016 Variance   2017    2016 Variance
----------------------------------------------------------------------------
Revenue                           -       2      (2)      1       7      (6)
Operating Expenses              (23)      8     (31)     (1)     61     (62)
Depreciation and
 Amortization                     -       1      (1)      1       3      (2)
Other Income, Net                 2       1       1       4       5      (1)
Finance Charges                  47      47       -     144     109      35
Income Tax Recovery             (28)    (22)     (6)    (91)    (56)    (35)
----------------------------------------------------------------------------
                                  6     (31)     37     (48)   (105)     57
Preference Share Dividends       16      22      (6)     49      59     (10)
----------------------------------------------------------------------------
Corporate and Other             (10)    (53)     43     (97)   (164)     67
----------------------------------------------------------------------------
(1) Includes Fortis net Corporate expenses and non-regulated holding company
    expenses

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

The decrease in operating expenses for the quarter and year to date was primarily due to the receipt of a $28 million break fee ($24 million net of related transaction costs and tax) associated with the termination of the Waneta Dam purchase agreement in the third quarter of 2017, and acquisition-related transaction costs associated with ITC totalling approximately $4 million ($3 million after tax) and $39 million ($32 million after tax) for the third quarter and year-to-date 2016, respectively. The year-to-date decrease was partially offset by higher compensation-related expenditures, general inflationary increases and ancillary expenses to support the Corporation's listing on the New York Stock Exchange.

Finance charges for the quarter were comparable with the same period last year. Finance charges in the third quarter of 2017 reflect the financing of the ITC acquisition, which were offset by acquisition-related transaction costs incurred in the third quarter of 2016 totalling approximately $21 million ($16 million after tax) associated with ITC.

The increase in year-to-date finance charges was mainly due to the financing of the ITC acquisition since October 2016, partially offset by acquisition-related transaction costs discussed above totalling approximately $35 million ($26 million after tax) year-to-date 2016. Finance charges associated with the acquisition of Aitken Creek in April 2016 also contributed to the year-to-date increase.

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

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

REGULATORY HIGHLIGHTS

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

ITC

Return on Equity Complaints

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

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

An order has not yet been issued by FERC in connection with the Second Complaint and in September 2017 the MISO transmission owners filed a motion for FERC to dismiss the Second Complaint. If the Second Complaint is not dismissed, it is expected that FERC will establish a new base ROE and range of reasonableness to calculate the refund liability for the Second Refund Period and future ROEs for ITC's operating subsidiaries. As at September 30, 2017, the estimated range of refunds for the Second Refund Period was between US$105 million to US$143 million and ITC has recognized an aggregated estimated regulatory liability of $178 million (US$143 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 $108 million (US$81.5 million), including $20 million (US$15 million) of operating costs related to the 50.5% undivided interest in Unit 1 of Springerville Generating Station purchased by TEP in September 2016; (ii) a 7.04% return on original cost rate base, including a cost of equity of 9.75% and an embedded cost of long-term debt of 4.32%; (iii) a common equity component of capital structure of approximately 50%; and (iv) the adoption of proposed depreciation rates which reflect a reduction in the depreciable life for Unit 1 of San Juan Generating Station. Certain aspects of the general rate application, including net metering and rate design for new distributed generation customers, have been deferred to a second phase of TEP's rate case, which is currently expected to be completed in the first quarter of 2018. TEP cannot predict the outcome of these proceedings.

FERC Order

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

Central Hudson

General Rate Application

In July 2017 Central Hudson filed a rate case with the New York Public Service Commission ("PSC") requesting an increase in electric and nature gas rates of $55 million (US$43 million) and $23 million (US$18 million), respectively. Included in the rate case was a request to increase the allowed ROE to 9.5% from 9.0% and the equity component of the capital structure to 50% from 48%. An order from the PSC is expected in June 2018 with the new rates to become effective no later than July 1, 2018.

FortisAlberta

Capital Tracker Applications

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

Generic Cost of Capital

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

Next Generation Performance-Based Rate-Setting Proceeding

In December 2016 the AUC issued its decision outlining the manner in which distribution rates will be determined during the second performance-based rate-setting ("PBR") term, being the five-year period from 2018 through 2022. FortisAlberta filed a rebasing application in April 2017 to establish the going-in revenue requirement for the second PBR term, which will be used to determine the going-in rates upon which the PBR formula will be applied to establish distribution rates for 2018. A decision on this application is expected in the first quarter of 2018. The AUC has directed FortisAlberta to use the approved 2017 PBR rates on a continuing interim basis, and 2018 PBR rates will be determined in a separate proceeding following a decision on the Company's rebasing application.

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        Not          To be determined
                  Complaint                   applicable
----------------------------------------------------------------------------
Central Hudson    General Rate Application    July 2017    July 2018
----------------------------------------------------------------------------

CONSOLIDATED FINANCIAL POSITION

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

Significant Changes in the Consolidated Balance Sheets between September 30,
 2017 and December 31, 2016
----------------------------------------------------------------------------
                Increase/
Balance Sheet   (Decrease)
 Account        ($ millions)  Explanation
----------------------------------------------------------------------------
Capital assets, (270)         The decrease was mainly due to the impact of
 net                          foreign exchange associated with the
                              translation of US dollar-denominated capital
                              assets, depreciation, the reclassification of
                              a reserve from regulatory liabilities at UNS
                              Energy, and the reclassification of the net
                              book value of assets planned for early
                              retirement to regulatory assets at UNS Energy,
                              partially offset by capital expenditures.
----------------------------------------------------------------------------
Goodwill        (776)         The decrease was due to the impact of foreign
                              exchange associated with the translation of US
                              dollar-denominated goodwill.
----------------------------------------------------------------------------
Short-term      (487)         The decrease was mainly due to the repayment
 borrowings                   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 FortisAlberta
                              using proceeds from the issuance of long-term
                              debt. The decrease was partially offset by
                              higher short-term borrowings at ITC and
                              FortisBC Energy.
----------------------------------------------------------------------------
Accounts        (201)         The decrease was primarily due to the timing
 payable and                  of the declaration of the Corporation's common
 other current                share dividends, lower amounts owing for
 liabilities                  energy supply costs at FortisBC Energy and
                              Newfoundland Power associated with the
                              seasonality of operations, and the impact of
                              foreign-exchange associated with the
                              translation of US dollar-denominated accounts
                              payable. The decrease was partially offset by
                              an increase in capital accruals at ITC and an
                              increase in transmission costs payable at
                              FortisAlberta.
----------------------------------------------------------------------------
Regulatory      (258)         The decrease was primarily due to a reduction
 liabilities -                in regulatory liabilities at ITC associated
 current and                  with the refund payment associated with the
 long-term                    Initial Complaint, the reclassification of a
                              reserve to capital assets at UNS Energy, and
                              the translation of US dollar-denominated
                              regulatory liabilities. The decrease was
                              partially offset by an increase in FortisBC
                              Energy's deferral adjustments owing to
                              customers.
----------------------------------------------------------------------------
Long-term debt  (576)         The decrease was mainly due to the impact of
 (including                   foreign exchange associated with the
 current                      translation of US dollar-denominated debt and
 portion)                     regularly scheduled debt repayments. The
                              decrease was partially offset by the issuance
                              of term loan credit agreements and first
                              mortgage bonds by ITC, and debt issued at
                              other of the regulated utilities.
----------------------------------------------------------------------------
Deferred income 141           The increase was mainly due to timing
 tax                          differences associated with capital
 liabilities                  expenditures at the regulated utilities,
                              partially offset by taxable losses at the
                              Corporation and the impact of foreign exchange
                              on the translation of US dollar-denominated
                              deferred income tax liabilities.
----------------------------------------------------------------------------
Shareholders'   527           The increase was primarily due to: (i) the
 equity                       issuance of $500 million of common shares;
                              (ii) net earnings attributable to common
                              equity shareholders for the nine months ended
                              September 30, 2017, less dividends declared on
                              common shares; and (iii) the issuance of
                              common shares under the Corporation's dividend
                              reinvestment, employee share purchase and
                              stock option plans. The increase was partially
                              offset by a decrease in accumulated other
                              comprehensive income associated with the
                              translation of the Corporation's US dollar-
                              denominated investments in subsidiaries, net
                              of hedging activities and tax.
----------------------------------------------------------------------------

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CONSOLIDATED CASH FLOWS

The table below outlines the Corporation's sources and uses of cash for the third quarter and year-to-date periods ended September 30, 2017 compared to the same periods in 2016, followed by a discussion of the nature of the variances in cash flows.

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Summary of Consolidated Cash Flows
Periods Ended September 30                   Quarter            Year-to-Date
($ millions)                   2017    2016 Variance   2017    2016 Variance
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Cash, Beginning of Period       231     296     (65)    269     242      27
Cash Provided by (Used in):
  Operating Activities          800     478     322   1,990   1,409     581
  Investing Activities         (683)   (529)   (154) (2,143) (1,704)   (439)
  Financing Activities          (87)     51    (138)    148     365    (217)
  Effect of Exchange Rate
   Changes on Cash and Cash
   Equivalents                   (9)      5     (14)    (12)    (11)     (1)
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Cash, End of Period             252     301     (49)    252     301     (49)
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Operating Activities: Cash flow provided by operating activities was $322 million higher quarter over quarter and $581 million higher year to date compared to the same periods in 2016. The increase was primarily due to higher cash earnings, driven by ITC and UNS Energy, and favourable changes in long-term regulatory deferrals. The year-to-date increase was partially offset by timing differences in working capital, mainly due to the payment of the Initial Complaint refund at ITC in the first quarter of 2017.

Investing Activities: Cash used in investing activities was $154 million higher quarter over quarter and $439 million higher year to date compared to the same periods in 2016. The increase was driven by capital spending at ITC. The year-to-date increase was partially offset by the acquisition of Aitken Creek in the second quarter of 2016 for a net cash purchase price of $318 million.

Financing Activities: Cash provided by financing activities was $138 million lower quarter over quarter and $217 million lower year to date compared to the same periods in 2016. The decrease was primarily due to higher net repayments under committed credit facilities and short-term borrowings, partially offset by lower repayments of long-term debt and higher proceeds from the issuance of long-term debt.

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.

In September 2016 the Corporation redeemed all of the First Preference Shares, Series E for $200 million.

Proceeds from long-term debt, net of issue costs, for the quarter and year to date compared to the same periods last year are summarized in the following table.

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Proceeds from Long-Term Debt, Net of Issue Costs
Periods Ended September 30                   Quarter            Year-to-Date
($ millions)                   2017    2016 Variance   2017    2016 Variance
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ITC (1)                           -       -       -     601       -     601
Central Hudson (2)               75       -      75      75      29      46
FortisBC Energy (3)               -       -       -       -     298    (298)
FortisAlberta (4)               199     149      50     199     149      50
Eastern Canadian (5)(6)           -      40     (40)     75      40      35
Caribbean Electric (7)(8)         -      36     (36)     80      65      15
Corporate                         -      (2)      2       -      (2)      2
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Total                           274     223      51   1,030     579     451
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(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. During 2017 borrowings under
    the term loan credit agreements were US$200 million ($250 million) and
    US$50 million ($62 million), respectively, representing the maximum
    amounts available under the agreements. The net proceeds from these
    borrowings were used to repay credit facility borrowings and for general
    corporate purposes. In April 2017 ITC issued 30-year US$200 million
    ($250 million) 4.16% secured first mortgage bonds. The net proceeds from
    the issuance were used to repay credit facility borrowings and for
    general corporate purposes.
(2) In August 2017 Central Hudson issued 30-year US$30 million ($37 million)
    unsecured notes at 4.05% and 40-year US$30 million ($37 million)
    unsecured notes at 4.20%. The net proceeds from the issuances were used
    to repay long-term debt and for general corporate purposes. In June 2016
    Central Hudson issued 5-year US$24 million ($29 million) unsecured notes
    at 2.16%. The net proceeds were used to finance capital expenditures and
    for general corporate purposes.
(3) In April 2016 FortisBC Energy issued $300 million of unsecured
    debentures in a dual tranche of 10-year $150 million unsecured
    debentures at 2.58% and 30-year $150 million unsecured debentures at
    3.67%. The net proceeds were used to repay short-term borrowings and to
    finance capital expenditures.
(4) In September 2017 FortisAlberta issued 30-year $200 million unsecured
    debentures at 3.67%. The net proceeds from the issuance were used to
    repay credit facility borrowings, to finance capital expenditures and
    for general corporate purposes. In September 2016 FortisAlberta issued
    30-year $150 million unsecured debentures at 3.34%. The net proceeds
    were used to repay credit facility borrowings and for general corporate
    purposes.
(5) In June 2017 Newfoundland Power issued 40-year $75 million first
    mortgage sinking fund bonds at 3.815%. The net proceeds from the
    issuance were used to repay credit facility borrowings and for general
    corporate purposes.
(6) In August 2016 Maritime Electric issued 40-year $40 million secured
    first mortgage bonds at 3.657%. The net proceeds were primarily used to
    repay long-term debt and short-term borrowings.
(7) In March and May 2017, Caribbean Utilities issued US$60 million ($75
    million) of unsecured notes in a dual tranche of 15-year US$40 million
    ($50 million) at 3.90% and 30-year US$20 million ($25 million) at 4.64%,
    respectively. The net proceeds from the issuances were used to finance
    capital expenditures and repay short-term borrowings.
 (8)In May and September 2016 Fortis Turks and Caicos issued 15-year US$45
    million ($65 million) unsecured notes, in a dual tranche of US$22.5
    million ($29 million) at 5.14% and US$22.5 million ($36 million) at
    5.29%, respectively. The net proceeds were used to finance capital
    expenditures and for general corporate purposes.

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

Common share dividends paid in the third quarter of 2017 were $106 million, net of $61 million of dividends reinvested, compared to $69 million, net of $37 million of dividends reinvested, paid in the third quarter of 2016. Common share dividends paid year-to-date 2017 were $308 million, net of $186 million of dividends reinvested, compared to $216 million, net of $102 million of dividends reinvested, paid year-to-date 2016. The dividend paid per common share for each of the first, second and third quarters of 2017 was $0.40 compared to $0.375 for each of the same quarters of 2016. The weighted average number of common shares outstanding for the third quarter and year-to-date 2017 was 418.6 million and 413.9 million, respectively, compared to 285.0 million and 283.7 million for each of the same periods in 2016.

CONTRACTUAL OBLIGATIONS

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

CAPITAL STRUCTURE

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

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

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Capital Structure                                   As at
                                    September 30, 2017     December 31, 2016
                                ($ millions)       (%)($ millions)       (%)
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Total debt and capital lease and
 financeobligations (net of
 cash)(1)                             21,420      58.6      22,490      60.6
Preference shares                      1,623       4.4       1,623       4.4
Common shareholders' equity           13,501      37.0      12,974      35.0
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Total                                 36,544     100.0      37,087     100.0
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(1) Includes long-term debt and capital lease and finance obligations,
    including current portion, and short-term borrowings, net of cash

Including amounts related to non-controlling interests, the Corporation's capital structure as at September 30, 2017 was 55.9% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 35.3% common shareholders' equity and 4.6% 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 improvement in the Corporation's capital structure was primarily due the issuance of $500 million of common shares in March 2017, for which the net proceeds were used to repay short-term borrowings.

CREDIT RATINGS

The Corporation's credit ratings are as follows.

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

The above-noted credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company. In May 2017 S&P and DBRS affirmed the Corporation's long-term corporate and unsecured debt credit ratings, and in September 2017 Moody's affirmed the Corporation's long-term issuer and unsecured debt credit ratings.

CAPITAL EXPENDITURE PROGRAM

A breakdown of the $2.1 billion in gross consolidated capital expenditures by segment year-to-date 2017 is provided in the following table.

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Gross Consolidated Capital Expenditures (1)
Year-to-date September 30, 2017
($ millions)
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                               Regulated
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            UNS    Central  FortisBC Fortis  FortisBC Eastern  Caribbean
       ITC  Energy Hudson   Energy   Alberta Electric Canadian Electric
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Total  725  347    156      329      304     72       102      86
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----------------------------------------------------
Gross Consolidated Capital Expenditures (1)
Year-to-date September 30, 2017
($ millions)
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       Total
       Regulated      Non-
       Utilities      Regulated(2)   Total
----------------------------------------------------
Total  2,121          13             2,134
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(1) Represents cash payments to construct capital and intangible assets, as
    reflected on the condensed consolidated interim statement of cash flows.
    Excludes the non-cash equity component of AFUDC.
(2) Includes Energy Infrastructure and Corporate and Other segments

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

Gross consolidated capital expenditures for 2017 are forecast to be approximately $3.1 billion. There have been no material changes in the overall expected level, nature and timing of the Corporation's capital expenditures from those that were disclosed in the 2016 Annual MD&A, with the exception of capital expenditures for UNS Energy. Capital expenditures at UNS Energy are expected to be higher than the original forecast, primarily due to capital expenditures related to investment in natural gas-fired facilities and distribution modernization projects.

At ITC approximately $300 million (US$231 million) was invested in the Multi-Value Projects ("MVPs") from the date of acquisition. 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.

Approximately $448 million, including AFUDC and development costs, has been invested in the Tilbury Liquefied Natural Gas ("LNG") facility expansion ("Tilbury LNG Facility Expansion"), in British Columbia, to the end of the third quarter of 2017. The total cost of the project is estimated at approximately $470 million, including approximately $70 million of AFUDC and development costs, which could be impacted depending on the date the project is considered in service for rate-making purposes. The facility includes a second LNG tank and a new liquefier, both expected to be in service in the fourth quarter of 2017 or the first quarter of 2018.

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

Over the five-year period from 2018 through 2022 ("five-year capital program"), gross consolidated capital expenditures are expected to be approximately $14.5 billion, $1.5 billion higher than $13 billion previously forecast for the period from 2017 through 2021. The improvement in the five-year capital program is the result of the Corporation's sustainable organic growth platform and reflects increased investment mainly at FortisBC Energy and UNS Energy. The low-risk, highly executable five-year capital program contains only a small number of major projects.

The five-year capital program includes approximately $350 million at FortisBC Energy related to a natural gas pipeline expansion ("Eagle Mountain Woodfibre Gas Pipeline Project") at a proposed LNG site in Squamish, British Columbia. The current estimate of FortisBC Energy's investment in the project may be updated for final scoping, detailed construction estimates and scheduling, and final determination of customer capital contributions. FortisBC Energy received an OIC from the Government of British Columbia effectively exempting this project from further regulatory approval by the British Columbia Utilities Commission. Woodfibre LNG has obtained an export license from the National Energy Board ("NEB"), which was recently extended from 25 to 40 years, and received environmental assessment approvals from the Squamish First Nation, the British Columbia Environmental Assessment Office and the Canadian Environmental Assessment Agency. FortisBC Energy also received environmental assessment approval from the Squamish First Nation and provincial environmental assessment approval in 2016. 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 proceed with the project. Given the increased certainty with the number of project approvals received and the level of planning, engineering and expenditures completed by Woodfibre LNG to date, the Eagle Mountain Woodfibre Gas Pipeline Project has been included in the five-year capital program, and is not expected to be in service before 2021. The project remains contingent on Woodfibre LNG making a final investment decision.

Also included in the five-year capital program is approximately $300 million associated with a multi-year Pipeline Integrity Management Program at FortisBC Energy. The program is focused on improving pipeline safety and the integrity of the high-pressure transmission system, including pipeline modifications and looping.

The five-year capital program includes the expected addition of 200 MW of flexible generation resources at UNS Energy, which will consist of 10 natural gas-fired reciprocating engines. The engines will provide ramping and peaking capabilities, replace aging, less efficient steam turbines and will facilitate the addition of renewable generating sources to the grid. The total cost of the program is estimated at $230 million (US$180 million) with expected in-service dates between 2019 and 2020. Also included in the capital program is the expected addition of the 550 MW natural gas-fired Gila River Generating Unit 2 by UNS Energy, estimated at $210 million (US$165 million), which will assist with the replacement of retiring coal-fired generation facilities. This project includes an initial tolling agreement with a purchase option expected to be exercised in late 2019.

ADDITIONAL INVESTMENT OPPORTUNITIES

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

FortisOntario - Wataynikaneyap Power Project

The Wataynikaneyap Power Project continues to advance in Ontario. Consisting of a partnership between 22 First Nation communities and Fortis, the project's mandate is to connect remote First Nation communities to the electricity grid in Ontario through the development of new transmission lines. In 2016 the Government of Ontario designated Wataynikaneyap Power as the licensed transmission company to complete this project. Fortis 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, Fortis' ownership interest in the Wataynikaneyap Partnership has increased to 49%, with the remaining 51% ownership interest held by the 22 First Nation 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 Nation 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 recover development costs incurred between November 2010 and the commencement of construction. In August 2017 the federal government announced it will fully fund, up to $60 million, to connect the Pikangikum First Nation to Ontario's power grid, a component of the larger Wataynikaneyap Power Project. In addition to environmental assessments underway, other regulatory approvals are currently being sought and the next regulatory milestone will be the preparation and filing of the leave to construct with the OEB, which is expected in the fourth quarter of 2017. Construction of the larger Wataynikaneyap Power Project will commence pending the receipt of permits, approvals and a cost-sharing agreement between the federal and provincial governments.

ITC - Lake Erie Connector

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

In January 2017 ITC received approval of a Presidential Permit from the U.S. Department of Energy for the Lake Erie Connector transmission line, which is a required approval for international border-crossing projects. Also in January, ITC received a report from Canada's NEB recommending the issuance of a Certificate of Public Convenience and Necessity ("CPCN") with prescribed conditions for the transmission line. In May 2017 ITC completed the major permit process in Pennsylvania upon receipt of two required permits from the Pennsylvania Department of Environmental Protection. In June 2017 ITC received approval from Canada's Governor in Council and the CPCN was issued by the NEB. In October 2017 ITC received permits from the U.S. Army Corps of Engineers, which completes the project's major application process in the United States and Canada. The project continues to advance through regulatory, operational, and economic milestones. Ongoing activities include completing project cost refinement and securing favourable transmission service agreements with prospective counterparties. Pending achievement of key milestones, the expected in-service date for the project is late 2021.

FortisBC - LNG

The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including further expansion of Tilbury. The 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.

Other Opportunities

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

CASH FLOW REQUIREMENTS

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

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 are 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. 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 October 2017 FortisBC Energy filed a short-form base shelf prospectus, under which the Company may issue debentures in an aggregate principal amount of up to $650 million during the 25-month life of the base shelf prospectus. Also in October, the Company issued $175 million of unsecured debentures at 3.69% under the base shelf prospectus. The net proceeds from the issuance were used to repay short-term borrowings.

In November 2016 Fortis filed a short-form base shelf prospectus, under which the Corporation may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $5 billion during the 25-month life of the base shelf prospectus. In July 2017 Fortis exchanged its US$2.0 billion ($2.6 billion) unregistered senior unsecured notes for US$2.0 billion ($2.6 billion) registered senior unsecured notes under the base shelf prospectus. In March 2017 Fortis issued $500 million common equity and in December 2016 issued $500 million unsecured notes at 2.85%, both under the base shelf prospectus. A principal amount of approximately $1.5 billion remains under the base shelf prospectus.

As at September 30, 2017, management expects consolidated fixed-term debt maturities and repayments to average approximately $721 million annually over the next five years. The combination of available credit facilities and manageable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.

Fortis and its subsidiaries were in compliance with debt covenants as at September 30, 2017 and are expected to remain compliant throughout 2017.

CREDIT FACILITIES

As at September 30, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.3 billion, of which approximately $4.0 billion was unused, including $1.0 billion unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $4.8 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2022.

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

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Credit Facilities                                              As at
                                                                   December
                                 Regulated  Corporate  September        31,
                                 Utilities  and Other   30, 2017       2016

($ millions)
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Total credit facilities(1)           3,950      1,385      5,335      5,976
Credit facilities utilized:
  Short-term borrowings(1)            (668)         -       (668)    (1,155)
  Long-term debt
   (includingcurrent portion)(2)      (266)      (272)      (538)      (973)
Letters of credit outstanding          (73)       (55)      (128)      (119)
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Credit facilities unused             2,943      1,058      4,001      3,729
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(1) Total credit facilities and short-term borrowings as at September 30,
    2017 include $286 million outstanding under ITC's commercial paper
    program (December 31, 2016 - $195 million). Outstanding commercial paper
    does not reduce available capacity under the Corporation's consolidated
    credit facilities.
(2) As at September 30, 2017, none of the credit facility borrowings were
    classified as current installments of long-term debt on the consolidated
    balance sheet (December 31, 2016 - $61 million).

As at September 30, 2017 and December 31, 2016, certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods. There were no material changes in credit facilities from that disclosed in the Corporation's 2016 Annual MD&A, except as follows.

In March 2017 the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares. In July 2017 the Corporation amended its $1.3 billion unsecured committed revolving credit facility, resulting in an extension of the maturity date to July 2022. The Corporation has the option to increase the facility by $0.5 billion to $1.8 billion and, as at September 30, 2017, that option had not been exercised.

In September 2017 FortisAlberta repaid its $90 million bilateral credit facility using the proceeds from the issuance of long-term debt. The bilateral credit facility was terminated upon repayment.

In October 2017 ITC replaced its US$1.0 billion ($1.2 billion) credit facility agreements with US$900 million ($1.1 billion) unsecured committed revolving credit facility agreements, maturing in October 2022.

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $128 million as at September 30, 2017 (December 31, 2016 - $119 million), the Corporation had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.

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: Year-to-date 2017 the following changes occurred to the debt credit ratings of the Corporations' utilities: In April 2017 S&P upgraded TEP's unsecured debt rating to 'A-' from 'BBB+', with a stable outlook and in September 2017 S&P upgraded ITC's unsecured debt rating to 'A-' from 'BBB+'. 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 September 30, 2017, the fair value of the Corporation's consolidated defined benefit pension and other post-employment benefit plan assets was $2,994 million compared to $2,898 million as at December 31, 2016.

CHANGES IN ACCOUNTING POLICIES

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

Simplifying the Test for Goodwill Impairment

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

FUTURE ACCOUNTING PRONOUNCEMENTS

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

Revenue from Contracts with Customers

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

The new guidance permits two methods of adoption: (i) the full retrospective method; and (ii) the modified retrospective method. The Corporation expects to adopt the guidance using 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.

More than 90% of the Corporation's revenue is generated from energy sales to retail and wholesale customers based on published tariff rates, as approved by the respective regulators. Fortis has assessed retail and wholesale tariff revenue and expects that the adoption of this standard will not change the Corporation's accounting policy for recognizing retail and wholesale tariff revenue and, therefore, will not have an impact on earnings. Fortis is finalizing its assessment on whether this standard will have an impact on its remaining revenue streams. The Corporation has not disclosed the expected impact of adoption on its consolidated financial statements as it is not expected to be material.

Alternative revenue programs of rate regulated utilities are outside the scope of this standard as they are not considered contracts with customers. Revenues arising from alternative revenue programs will be presented separately from revenues in scope of the new guidance. The Corporation also expects to add additional disclosures to address the requirements to provide more information regarding the nature, amount, timing and uncertainty of revenue and cash flows. Fortis is in the process of drafting these required disclosures.

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

Recognition and Measurement of Financial Assets and Financial Liabilities

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

Targeted Improvements to Accounting for Hedging Activities

ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, was issued in August 2017 and the amendments in this update better align risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and presentation of hedge results. This update is effective for annual and interim periods beginning after December 15, 2018. Early adoption is permitted. The amendments in this update should be reflected as of the beginning of the fiscal year of adoption. For cash flow and net investment hedges existing at the date of adoption, the amendments should be applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to the opening balance of retained earnings. Amended presentation and disclosure guidance is required only prospectively. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.

FINANCIAL INSTRUMENTS

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

----------------------------------------------------------------------------
Financial Instruments                             As at
                                  September 30, 2017       December 31, 2016
                                Carrying   Estimated    Carrying   Estimated
($ millions)                       Value  Fair Value       Value  Fair Value
----------------------------------------------------------------------------
Long-term debt, including
 current portion                  20,634      22,147      21,219      22,523
Waneta Partnership
 promissory note                      62          62          59          61
----------------------------------------------------------------------------

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

Derivative Instruments

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

For further details of the Corporation's derivative instruments as at September 30, 2017 refer to Note 15 to the Corporation's unaudited condensed consolidated interim financial statements. There were no material changes in the nature and amount of the Corporations' derivative instruments from those disclosed in the 2016 Annual MD&A, except as follows.

In 2017 ITC entered into additional forward-starting interest rate swaps, all effective December 2017, with a combined notional amount of $811 million and with 5-year 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 and amounts outstanding under the revolving credit agreement and commercial paper program.

In August 2017 the Corporation entered into three total return swaps with a combined notional amount of $33 million and terms ranging from one to three years terminating in January 2018, 2019 and 2020. The total return swaps manage the cash flow risk associated with forecasted future cash settlements of certain stock-based compensation.

In October 2017 the Corporation entered into forward sales contracts with notional amounts totalling US$125 million to manage its exposure to foreign currency fluctuations.

CRITICAL ACCOUNTING ESTIMATES

The preparation of the Corporation's condensed consolidated interim financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, 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.

Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates from those disclosed in the 2016 Annual MD&A, except as follows.

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 18 to the Corporation's unaudited condensed consolidated interim financial statements. There were no material changes in the Corporation's contingencies from those disclosed in the 2016 Annual MD&A, except as described below.

Fortis and ITC

Following announcement of the acquisition of ITC in February 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan ("Superior Court") and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified damages and costs, including attorneys' fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In March 2017 an agreement in principle was reached to settle the case, subject to formal documentation and court approval. In September 2017 a final settlement approval hearing was held after which the court entered an order and final judgment approving the settlement. Pursuant to the order and final judgment, the shareholder class action litigation against ITC has been dismissed.

Fortis Turks and Caicos

In September 2017 the Turks and Caicos Islands were struck by Hurricane Irma, resulting in significant damage to Fortis Turks and Caicos' transmission and distribution system. Damaged energy infrastructure interrupted the Company's ability to provide electricity service to its customers, and restoration efforts continue. The Company is currently assessing the total cost of restoration. The possibility exists that the impact of Hurricane Irma could adversely affect future earnings of Fortis Turks and Caicos as well as impair its capital assets and goodwill. The outcome cannot be reasonably determined or estimated at this time and, accordingly, no amount has been accrued in the condensed consolidated interim financial statements.

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 and nine months ended September 30, 2017 and 2016.

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

----------------------------------------------------------------------------
Related-party and inter-company transactions
Periods Ended September 30                           Quarter    Year-to-Date
($ millions)                                    2017    2016    2017    2016
----------------------------------------------------------------------------
Sale of capacity from Waneta Expansion to
 FortisBC Electric                                11      14      30      32
Sale of energy from Belize Electric Company
 Limited toBelize Electricity                     11      12      25      26
Lease of gas storage capacity and gas sales
 from Aitken Creek to FortisBC Energy              5       4      18       9
----------------------------------------------------------------------------

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

SUMMARY OF QUARTERLY RESULTS

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

----------------------------------------------------------------------------
Summary of Quarterly
 Results                              Net Earnings
                                   Attributable to
                                     Common Equity
                            Revenue   Shareholders Earnings per Common Share
Quarter Ended          ($ millions)   ($ millions)   Basic ($)   Diluted ($)
----------------------------------------------------------------------------
September 30, 2017            1,901            278        0.66          0.66
June 30, 2017                 2,015            257        0.62          0.62
March 31, 2017                2,274            294        0.72          0.72
December 31, 2016             2,053            189        0.49          0.49
September 30, 2016            1,528            127        0.45          0.45
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
----------------------------------------------------------------------------

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

September 2017/September 2016: Net earnings attributable to common equity shareholders were $278 million, or $0.66 per common share, for the third quarter of 2017 compared to earnings of $127 million or $0.45 per common share, for the third quarter of 2016. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.

June 2017/June 2016: Net earnings attributable to common equity shareholders were $257 million, or $0.62 per common share, for the second quarter of 2017 compared to earnings of $107 million, or $0.38 per common share, for the second quarter of 2016. The increase was driven by earnings of $93 million at ITC, acquired in October 2016. The increase for the quarter was also due to: (i) strong performance at UNS Energy, largely due to the impact of the rate case settlement and higher electricity sales; (ii) lower Corporate and Other expenses, primarily due to $22 million in acquisition-related transaction costs associated with ITC recognized in the second quarter of 2016; (iii) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives quarter over quarter; and (iv) favourable foreign exchange associated with the translation of US dollar-denominated earnings. The increase was partially offset by higher finance charges associated with the acquisition of ITC.

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

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

OUTLOOK

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

Over the five-year period from 2018 through 2022, the Corporation's capital expenditure program is expected to total approximately $14.5 billion, up $1.5 billion from the prior year's plan and increasing rate base to almost $32 billion by 2022. The five-year capital expenditure program is driven by projects that improve the transmission grid, address natural gas system capacity and gas line network integrity, increase cyber protection and allow the grid to deliver cleaner energy. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends.

Fortis has extended its targeted average annual dividend growth of approximately 6% through to 2022. This dividend guidance takes into account many factors, including continued good performance of the Corporation's utilities and growth in their service territories, the expectation of reasonable outcomes for regulatory proceedings, and the successful execution of the five-year capital expenditure program.

OUTSTANDING SHARE DATA

As at November 2, 2017, the Corporation had issued and outstanding 419.5 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation's First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether such dividends have been declared.

The number of common shares of Fortis that would be issued if all outstanding stock options were converted as at November 2, 2017 is approximately 4.0 million.

Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov. The information contained on, or accessible through, any of these websites is not incorporated by reference into this document.

FORTIS INC.

Condensed Consolidated Interim Financial Statements
For the three and nine months ended September 30, 2017 and 2016
(Unaudited)

                                 Fortis Inc.
          Condensed Consolidated Interim Balance Sheets (Unaudited)
                                    As at
                      (in millions of Canadian dollars)

                                                September 30,   December 31,
                                                         2017           2016
----------------------------------------------------------------------------

ASSETS

Current assets
Cash and cash equivalents                      $          252 $          269
Accounts receivable and other current assets            1,047          1,127
Prepaid expenses                                          124             85
Inventories                                               382            372
Regulatory assets (Note 5)                                270            313
----------------------------------------------------------------------------
Total current assets                                    2,075          2,166
Other assets                                              444            406
Regulatory assets (Note 5)                              2,620          2,620
Capital assets, net                                    29,067         29,337
Intangible assets, net                                  1,051          1,011
Goodwill                                               11,588         12,364
----------------------------------------------------------------------------
Total assets                                   $       46,845 $       47,904
----------------------------------------------------------------------------

LIABILITIES AND EQUITY

Current liabilities
Short-term borrowings (Note 16)                $          668 $        1,155
Accounts payable and other current liabilities          1,769          1,970
Regulatory liabilities (Note 5)                           463            492
Current installments of long-term debt (Note
 6)                                                       997            251
Current installments of capital lease and
 finance obligations                                       65             76
----------------------------------------------------------------------------
Total current liabilities                               3,962          3,944
Other liabilities                                       1,184          1,279
Regulatory liabilities (Note 5)                         1,462          1,691
Deferred income taxes                                   3,404          3,263
Long-term debt (Note 6)                                19,495         20,817
Capital lease and finance obligations                     447            460
----------------------------------------------------------------------------
Total liabilities                                      29,954         31,454
----------------------------------------------------------------------------
Commitments and Contingencies (Note 18)
Equity
Common shares (1) (Note 7)                             11,505         10,762
Preference shares (Note 8)                              1,623          1,623
Additional paid-in capital                                 10             12
Accumulated other comprehensive income                     35            745
Retained earnings                                       1,951          1,455
----------------------------------------------------------------------------
Shareholders' equity                                   15,124         14,597
Non-controlling interests                               1,767          1,853
----------------------------------------------------------------------------
Total equity                                           16,891         16,450
----------------------------------------------------------------------------
Total liabilities and equity                   $       46,845 $       47,904
----------------------------------------------------------------------------

(1) No par value. Unlimited authorized shares; 419.4 million and 401.5
    million issued and outstanding as at September 30, 2017 and December 31,
    2016, respectively

See accompanying Notes to Condensed Consolidated Interim Financial Statements

                                 Fortis Inc.
      Condensed Consolidated Interim Statements of Earnings (Unaudited)
                     For the periods ended September 30
         (in millions of Canadian dollars, except per share amounts)

                                         Quarter Ended          Year-to-Date
                                       2017       2016       2017       2016
----------------------------------------------------------------------------

Revenue                          $    1,901 $    1,528 $    6,190 $    4,785
                                --------------------------------------------

Expenses
  Energy supply costs                   478        503      1,756      1,698
  Operating                             504        439      1,657      1,367
  Depreciation and amortization         290        234        885        700
----------------------------------------------------------------------------
Total expenses                        1,272      1,176      4,298      3,765
----------------------------------------------------------------------------
Operating income                        629        352      1,892      1,020
Other income, net (Note 11)              23         10         78         35
Finance charges (Note 12)               225        164        686        457
----------------------------------------------------------------------------
Earnings before income taxes            427        198      1,284        598
Income tax expense                      106         40        314        110
----------------------------------------------------------------------------
Net earnings                     $      321 $      158 $      970 $      488
----------------------------------------------------------------------------

Net earnings attributable to:
  Non-controlling interests      $       27 $        9 $       92 $       33
  Preference equity shareholders         16         22         49         59
  Common equity shareholders            278        127        829        396
                                --------------------------------------------
                                 $      321 $      158 $      970 $      488
                                --------------------------------------------
Earnings per common share (Note
 13)
  Basic                          $     0.66 $     0.45 $     2.00 $     1.40
  Diluted                        $     0.66 $     0.45 $     2.00 $     1.39
----------------------------------------------------------------------------

See accompanying Notes to Condensed Consolidated Interim Financial Statements

                                Fortis Inc.
  Condensed Consolidated Interim Statements of Comprehensive (Loss) Income
                                 (Unaudited)
                     For the periods ended September 30
                     (in millions of Canadian dollars)

                                        Quarter Ended          Year-to-Date
                                      2017       2016       2017       2016
----------------------------------------------------------------------------

Net earnings                     $     321  $     158  $     970  $     488
                                --------------------------------------------

Other comprehensive (loss)
 income
Unrealized foreign currency
 translation (losses) gains, net
 of hedging activities and tax        (375)        58       (711)      (229)
Net change in available-for-sale
 investment, net of tax                  -          4          -          6
Net change in fair value of cash
 flow hedges, net of tax                 3         (3)         1         (3)
                                --------------------------------------------
                                      (372)        59       (710)      (226)
----------------------------------------------------------------------------
Comprehensive (loss) income      $     (51) $     217  $     260  $     262
----------------------------------------------------------------------------
Comprehensive income (loss)
 attributable to:
  Non-controlling interests      $      27  $       9  $      92  $      33
  Preference equity shareholders        16         22         49         59
  Common equity shareholders           (94)       186        119        170
                                --------------------------------------------
                                 $     (51) $     217  $     260  $     262
----------------------------------------------------------------------------

See accompanying Notes to Condensed Consolidated Interim Financial Statements

                                Fortis Inc.
    Condensed Consolidated Interim Statements of Cash Flows (Unaudited)
                     For the periods ended September 30
                     (in millions of Canadian dollars)

                                        Quarter Ended          Year-to-Date
                                      2017       2016       2017       2016
----------------------------------------------------------------------------

Operating activities
Net earnings                     $     321  $     158  $     970  $     488
Adjustments to reconcile net
 earnings to net cash provided
 by operating activities:
  Depreciation - capital assets        261        210        794        626
  Amortization - intangible
   assets                               23         17         71         52
  Amortization - other                   6          7         20         22
  Deferred income tax expense          110         29        284         59
  Accrued employee future
   benefits                              -          1         10         23
  Equity component of allowance
   for funds used during
   construction (Note 11)              (19)        (7)       (55)       (20)
  Other                                 16          6          5         60
 Change in long-term regulatory
 assets and liabilities                102         (6)        93        (38)
 Change in working capital (Note
 14)                                   (20)        63       (202)       137
----------------------------------------------------------------------------
Cash from operating activities         800        478      1,990      1,409
----------------------------------------------------------------------------
Investing activities
Capital expenditures - capital
 assets                               (644)      (498)    (1,967)    (1,315)
Capital expenditures -
 intangible assets                     (62)       (24)      (167)       (66)
Contributions in aid of
 construction                           39         15         76         33
Proceeds on sale of assets               1          1          4         11
Business acquisitions, net of
 cash acquired (Note 17)                 -          -          -       (318)
Other                                  (17)       (23)       (89)       (49)
----------------------------------------------------------------------------
Cash used in investing
 activities                           (683)      (529)    (2,143)    (1,704)
----------------------------------------------------------------------------
Financing activities
Proceeds from long-term debt,
 net of issue costs                    274        223      1,030        579
Repayments of long-term debt and
 capital lease and finance
 obligations                          (105)      (215)      (140)      (324)
Net (repayments) borrowings
 under committed credit
 facilities                           (221)        83       (397)       596
Change in short-term borrowings,
 net                                   109        252       (478)       (23)
Advances from non-controlling
 interests                               1          1          4          2
Issue of common shares to an
 institutional investor (Note 7)         -          -        500          -
Issue of common shares, net of
 costs and dividends reinvested          8         13         52         40
Redemption of preference shares
 (Note 8)                                -       (200)         -       (200)
Dividends
  Common shares, net of
   dividends reinvested               (106)       (69)      (308)      (216)
  Preference shares                    (16)       (19)       (49)       (56)
  Subsidiary dividends paid to
   non-controlling interests           (34)       (18)       (73)       (33)
Other                                    3          -          7          -
----------------------------------------------------------------------------
Cash (used in) from financing
 activities                            (87)        51        148        365
----------------------------------------------------------------------------
Effect of exchange rate changes
 on cash and cash equivalents           (9)         5        (12)       (11)
----------------------------------------------------------------------------
Change in cash and cash
 equivalents                            21          5        (17)        59
Cash and cash equivalents,
 beginning of period                   231        296        269        242
----------------------------------------------------------------------------
Cash and cash equivalents, end
 of period                       $     252  $     301  $     252  $     301
----------------------------------------------------------------------------

Supplementary Information to Condensed Consolidated Interim Statements of Cash Flows (Note 14)

See accompanying Notes to Condensed Consolidated Interim Financial Statements

                                 Fortis Inc.
 Condensed Consolidated Interim Statements of Changes in Equity (Unaudited)
                     For the periods ended September 30
                      (in millions of Canadian dollars)

                                                  Common         Preference
                                                  Shares             Shares
----------------------------------------------------------------------------
                                                (Note 7)           (Note 8)

As at January 1, 2017                 $           10,762 $            1,623
Net earnings                                           -                  -
Other comprehensive loss                               -                  -
Common share issues                                  743                  -
Stock-based compensation                               -                  -
Advances from non-controlling
 interests                                             -                  -
Foreign currency translation impacts                   -                  -
Subsidiary dividends paid to non-
 controlling interests                                 -                  -
Dividends declared on common shares
 ($0.80 per share)                                     -                  -
Dividends declared on preference
 shares                                                -                  -
----------------------------------------------------------------------------
As at September 30, 2017              $           11,505 $            1,623
----------------------------------------------------------------------------

As at January 1, 2016                 $            5,867 $            1,820
Net earnings                                           -                  -
Other comprehensive loss                               -                  -
Common share issues                                  145                  -
Stock-based compensation                               -                  -
Advances from non-controlling
 interests                                             -                  -
Foreign currency translation impacts                   -                  -
Subsidiary dividends paid to non-
 controlling interests                                 -                  -
Redemption of preference shares                        -               (197)
Dividends declared on common shares
 ($1.15 per share)                                     -                  -
Dividends declared on preference
 shares                                                -                  -
Adoption of new accounting policy                      -                  -
----------------------------------------------------------------------------
As at September 30, 2016              $            6,012 $            1,623
----------------------------------------------------------------------------

                                                                Accumulated
                                             Additional               Other
                                                Paid-In       Comprehensive
                                                Capital       Income (Loss)
----------------------------------------------------------------------------


As at January 1, 2017                 $              12  $              745
Net earnings                                          -                   -
Other comprehensive loss                              -                (710)
Common share issues                                  (4)                  -
Stock-based compensation                              2                   -
Advances from non-controlling
 interests                                            -                   -
Foreign currency translation impacts                  -                   -
Subsidiary dividends paid to non-
 controlling interests                                -                   -
Dividends declared on common shares
 ($0.80 per share)                                    -                   -
Dividends declared on preference
 shares                                               -                   -
----------------------------------------------------------------------------
As at September 30, 2017              $              10  $               35
----------------------------------------------------------------------------

As at January 1, 2016                 $              14  $              791
Net earnings                                          -                   -
Other comprehensive loss                              -                (226)
Common share issues                                  (4)                  -
Stock-based compensation                              2                   -
Advances from non-controlling
 interests                                            -                   -
Foreign currency translation impacts                  -                   -
Subsidiary dividends paid to non-
 controlling interests                                -                   -
Redemption of preference shares                       -                   -
Dividends declared on common shares
 ($1.15 per share)                                    -                   -
Dividends declared on preference
 shares                                               -                   -
Adoption of new accounting policy                     -                   -
----------------------------------------------------------------------------
As at September 30, 2016              $              12  $              565
----------------------------------------------------------------------------

                                                          Non-
                                         Retained  Controlling        Total
                                         Earnings    Interests       Equity
----------------------------------------------------------------------------


As at January 1, 2017                 $     1,455  $     1,853  $    16,450
Net earnings                                  878           92          970
Other comprehensive loss                        -            -         (710)
Common share issues                             -            -          739
Stock-based compensation                        -            -            2
Advances from non-controlling
 interests                                      -            4            4
Foreign currency translation impacts            -         (109)        (109)
Subsidiary dividends paid to non-
 controlling interests                          -          (73)         (73)
Dividends declared on common shares
 ($0.80 per share)                           (333)           -         (333)
Dividends declared on preference
 shares                                       (49)           -          (49)
----------------------------------------------------------------------------
As at September 30, 2017              $     1,951  $     1,767  $    16,891
----------------------------------------------------------------------------

As at January 1, 2016                 $     1,388  $       473  $    10,353
Net earnings                                  455           33          488
Other comprehensive loss                        -            -         (226)
Common share issues                             -            -          141
Stock-based compensation                        -            -            2
Advances from non-controlling
 interests                                      -            2            2
Foreign currency translation impacts            -           (7)          (7)
Subsidiary dividends paid to non-
 controlling interests                          -          (33)         (33)
Redemption of preference shares                 -            -         (197)
Dividends declared on common shares
 ($1.15 per share)                           (328)           -         (328)
Dividends declared on preference
 shares                                       (59)           -          (59)
Adoption of new accounting policy              16            -           16
----------------------------------------------------------------------------
As at September 30, 2016              $     1,472  $       468  $    10,152
----------------------------------------------------------------------------

See accompanying Notes to Condensed Consolidated Interim Financial Statements

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 are consistent with those disclosed in the Corporation's 2016 annual audited consolidated financial statements.

REGULATED UTILITIES

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

a.  Regulated Electric Transmission Utility - United States: Comprised of
    ITC Holdings Corp. 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 ("GIC") owning a 19.9% minority
    interest (Note 17).

b.  Regulated Electric & Gas Utilities - United States: Comprised of UNS
    Energy, which primarily includes Tucson Electric Power Company, UNS
    Electric, Inc. and UNS Gas, Inc., and Central Hudson Gas & Electric
    Corporation ("Central Hudson").

c.  Regulated Gas Utility - Canadian: Represents FortisBC Energy Inc.
    ("FortisBC Energy").

d.  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., and the Corporation's 49% equity investment in
    Wataynikaneyap Power Limited Partnership.

e.  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 (Note 17).

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 condensed consolidated interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for interim financial statements. As a result, these condensed consolidated interim 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 condensed consolidated interim financial statements include all adjustments that are of a normal 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, purchased power and natural gas, which are flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric utilities in the United States are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.

The preparation of the condensed consolidated interim financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the 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.

All amounts are presented in Canadian dollars unless otherwise stated.

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

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

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 condensed consolidated interim financial statements for the three and nine months ended September 30, 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; and (ii) the modified retrospective method. The Corporation expects to adopt the guidance using 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.

More than 90% of the Corporation's revenue is generated from energy sales to retail and wholesale customers based on published tariff rates, as approved by the respective regulators. Fortis has assessed retail and wholesale tariff revenue and expects that the adoption of this standard will not change the Corporation's accounting policy for recognizing retail and wholesale tariff revenue and, therefore, will not have an impact on earnings. Fortis is finalizing its assessment on whether this standard will have an impact on its remaining revenue streams. The Corporation has not disclosed the expected impact of adoption on its consolidated financial statements as it is not expected to be material.

Alternative revenue programs of rate regulated utilities are outside the scope of this standard as they are not considered contracts with customers. Revenues arising from alternative revenue programs will be presented separately from revenues in scope of the new guidance. The Corporation also expects to add additional disclosures to address the requirements to provide more information regarding the nature, amount, timing and uncertainty of revenue and cash flows. Fortis is in the process of drafting these required disclosures.

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

Recognition and Measurement of Financial Assets and Financial Liabilities

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

Targeted Improvements to Accounting for Hedging Activities

ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, was issued in August 2017 and the amendments in this update better align risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and presentation of hedge results. This update is effective for annual and interim periods beginning after December 15, 2018. Early adoption is permitted. The amendments in this update should be reflected as of the beginning of the fiscal year of adoption. For cash flow and net investment hedges existing at the date of adoption, the amendments should be applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to the opening balance of retained earnings. Amended presentation and disclosure guidance is required only prospectively. 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
                                        ------------------------------------
Quarter Ended                                       United States
                                        ------------------------------------
September 30, 2017                                           UNS     Central
($ millions)                                     ITC      Energy      Hudson
----------------------------------------------------------------------------
Revenue                                          376         599         197
Energy supply costs                                -         199          54
Operating expenses                               103         145          95
Depreciation and amortization                     54          62          16
----------------------------------------------------------------------------
Operating income                                 219         193          32
Other income (expenses), net                      10           2           3
Finance charges                                   63          24          10
Income tax expense (recovery)                     58          59          10
----------------------------------------------------------------------------
Net earnings (loss)                              108         112          15
Non-controlling interests                         19           -           -
Preference share dividends                         -           -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                       89         112          15
----------------------------------------------------------------------------
Goodwill                                       7,655       1,724         563
Identifiable assets                            9,694       6,739       2,470
----------------------------------------------------------------------------
Total assets                                  17,349       8,463       3,033
----------------------------------------------------------------------------
Gross capital expenditures                       213          99          53
----------------------------------------------------------------------------

Quarter Ended
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                            -         604         208
Energy supply costs                                -         214          66
Operating expenses                                 -         148          96
Depreciation and amortization                      -          65          15
----------------------------------------------------------------------------
Operating income (loss)                            -         177          31
Other income (expenses), net                       -           2           1
Finance charges                                    -          24          10
Income tax expense (recovery)                      -          53           8
----------------------------------------------------------------------------
Net earnings (loss)                                -         102          14
Non-controlling interests                          -           -           -
Preference share dividends                         -           -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                        -         102          14
----------------------------------------------------------------------------
Goodwill                                           -       1,812         591
Identifiable assets                                -       6,826       2,479
----------------------------------------------------------------------------
Total assets                                       -       8,638       3,070
----------------------------------------------------------------------------
Gross capital expenditures                         -         198          59
----------------------------------------------------------------------------


                                                      REGULATED
                                        ------------------------------------
Quarter Ended                                          Canada
                                        ------------------------------------
September 30, 2017                         FortisBC      Fortis     FortisBC
($ millions)                                 Energy     Alberta     Electric
----------------------------------------------------------------------------
Revenue                                         156         153           93
Energy supply costs                              38           -           33
Operating expenses                               64          47           21
Depreciation and amortization                    49          47           16
----------------------------------------------------------------------------
Operating income                                  5          59           23
Other income (expenses), net                      5          (1)           1
Finance charges                                  28          23           10
Income tax expense (recovery)                    (4)          -            3
----------------------------------------------------------------------------
Net earnings (loss)                             (14)         35           11
Non-controlling interests                         1           -            -
Preference share dividends                        -           -            -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                     (15)         35           11
----------------------------------------------------------------------------
Goodwill                                        913         227          235
Identifiable assets                           5,353       4,061        1,942
----------------------------------------------------------------------------
Total assets                                  6,266       4,288        2,177
----------------------------------------------------------------------------
Gross capital expenditures                      132         109           26
----------------------------------------------------------------------------

Quarter Ended
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                         151         143           88
Energy supply costs                              29           -           32
Operating expenses                               69          46           20
Depreciation and amortization                    49          45           15
----------------------------------------------------------------------------
Operating income (loss)                           4          52           21
Other income (expenses), net                      4           -            1
Finance charges                                  33          21            9
Income tax expense (recovery)                    (6)          1            2
----------------------------------------------------------------------------
Net earnings (loss)                             (19)         30           11
Non-controlling interests                         -           -            -
Preference share dividends                        -           -            -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                     (19)         30           11
----------------------------------------------------------------------------
Goodwill                                        913         227          235
Identifiable assets                           5,089       3,789        1,899
----------------------------------------------------------------------------
Total assets                                  6,002       4,016        2,134
----------------------------------------------------------------------------
Gross capital expenditures                       86          94           15
----------------------------------------------------------------------------


                                                      REGULATED
                                        ------------------------------------
Quarter Ended                              Canada
                                        ------------
September 30, 2017                          Eastern    Caribbean
($ millions)                               Canadian     Electric       Total
----------------------------------------------------------------------------
Revenue                                         206           77       1,857
Energy supply costs                             117           37         478
Operating expenses                               32           11         518
Depreciation and amortization                    24           14         282
----------------------------------------------------------------------------
Operating income                                 33           15         579
Other income (expenses), net                     (1)           1          20
Finance charges                                  14            4         176
Income tax expense (recovery)                     6            -         132
----------------------------------------------------------------------------
Net earnings (loss)                              12           12         291
Non-controlling interests                         -            4          24
Preference share dividends                        -            -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                      12            8         267
----------------------------------------------------------------------------
Goodwill                                         67          177      11,561
Identifiable assets                           2,334        1,113      33,706
----------------------------------------------------------------------------
Total assets                                  2,401        1,290      45,267
----------------------------------------------------------------------------
Gross capital expenditures                       39           29         700
----------------------------------------------------------------------------

Quarter Ended
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                         211           79       1,484
Energy supply costs                             123           35         499
Operating expenses                               32           11         422
Depreciation and amortization                    23           13         225
----------------------------------------------------------------------------
Operating income (loss)                          33           20         338
Other income (expenses), net                      -            1           9
Finance charges                                  15            4         116
Income tax expense (recovery)                     4            -          62
----------------------------------------------------------------------------
Net earnings (loss)                              14           17         169
Non-controlling interests                         -            4           4
Preference share dividends                        -            -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                      14           13         165
----------------------------------------------------------------------------
Goodwill                                         67          186       4,031
Identifiable assets                           2,255        1,137      23,474
----------------------------------------------------------------------------
Total assets                                  2,322        1,323      27,505
----------------------------------------------------------------------------
Gross capital expenditures                       50           19         521
----------------------------------------------------------------------------


                                                   NON-REGULATED
                                        ------------------------------------
Quarter Ended

                                                    Energy
September 30, 2017                                  Infra-        Corporate
($ millions)                                     structure        and Other
----------------------------------------------------------------------------
Revenue                                                 47                -
Energy supply costs                                      -                -
Operating expenses                                      12              (23)
Depreciation and amortization                            8                -
----------------------------------------------------------------------------
Operating income                                        27               23
Other income (expenses), net                             1                2
Finance charges                                          2               47
Income tax expense (recovery)                            2              (28)
----------------------------------------------------------------------------
Net earnings (loss)                                     24                6
Non-controlling interests                                3                -
Preference share dividends                               -               16
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                             21              (10)
----------------------------------------------------------------------------
Goodwill                                                27                -
Identifiable assets                                  1,551               72
----------------------------------------------------------------------------
Total assets                                         1,578               72
----------------------------------------------------------------------------
Gross capital expenditures                               6                -
----------------------------------------------------------------------------

Quarter Ended
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                                 44                2
Energy supply costs                                      3                -
Operating expenses                                      12                8
Depreciation and amortization                            8                1
----------------------------------------------------------------------------
Operating income (loss)                                 21               (7)
Other income (expenses), net                             -                1
Finance charges                                          1               47
Income tax expense (recovery)                            -              (22)
----------------------------------------------------------------------------
Net earnings (loss)                                     20              (31)
Non-controlling interests                                5                -
Preference share dividends                               -               22
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                             15              (53)
----------------------------------------------------------------------------
Goodwill                                                27                -
Identifiable assets                                  1,465              280
----------------------------------------------------------------------------
Total assets                                         1,492              280
----------------------------------------------------------------------------
Gross capital expenditures                               1                -
----------------------------------------------------------------------------




Quarter Ended

September 30, 2017                          Inter-segment
($ millions)                                 eliminations              Total
----------------------------------------------------------------------------
Revenue                                                (3)             1,901
Energy supply costs                                     -                478
Operating expenses                                     (3)               504
Depreciation and amortization                           -                290
----------------------------------------------------------------------------
Operating income                                        -                629
Other income (expenses), net                            -                 23
Finance charges                                         -                225
Income tax expense (recovery)                           -                106
----------------------------------------------------------------------------
Net earnings (loss)                                     -                321
Non-controlling interests                               -                 27
Preference share dividends                              -                 16
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                             -                278
----------------------------------------------------------------------------
Goodwill                                                -             11,588
Identifiable assets                                   (72)            35,257
----------------------------------------------------------------------------
Total assets                                          (72)            46,845
----------------------------------------------------------------------------
Gross capital expenditures                              -                706
----------------------------------------------------------------------------

Quarter Ended
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                                (2)             1,528
Energy supply costs                                     1                503
Operating expenses                                     (3)               439
Depreciation and amortization                           -                234
----------------------------------------------------------------------------
Operating income (loss)                                 -                352
Other income (expenses), net                            -                 10
Finance charges                                         -                164
Income tax expense (recovery)                           -                 40
----------------------------------------------------------------------------
Net earnings (loss)                                     -                158
Non-controlling interests                               -                  9
Preference share dividends                              -                 22
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                             -                127
----------------------------------------------------------------------------
Goodwill                                                -              4,058
Identifiable assets                                   (86)            25,133
----------------------------------------------------------------------------
Total assets                                          (86)            29,191
----------------------------------------------------------------------------
Gross capital expenditures                              -                522
----------------------------------------------------------------------------

                                                      REGULATED
                                        ------------------------------------
Year-to-Date                                        United States
                                        ------------------------------------
September 30, 2017                                           UNS     Central
($ millions)                                     ITC      Energy      Hudson
----------------------------------------------------------------------------
Revenue                                        1,179       1,609         661
Energy supply costs                                -         545         203
Operating expenses                               330         442         305
Depreciation and amortization                    164         195          50
----------------------------------------------------------------------------
Operating income                                 685         427         103
Other income (expenses), net                      31          17           7
Finance charges                                  193          76          31
Income tax expense (recovery)                    190         126          31
----------------------------------------------------------------------------
Net earnings (loss)                              333         242          48
Non-controlling interests                         60           -           -
Preference share dividends                         -           -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                      273         242          48
----------------------------------------------------------------------------
Goodwill                                       7,655       1,724         563
Identifiable assets                            9,694       6,739       2,470
----------------------------------------------------------------------------
Total assets                                  17,349       8,463       3,033
----------------------------------------------------------------------------
Gross capital expenditures                       725         347         156
----------------------------------------------------------------------------

Year-to-Date
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                            -       1,534         642
Energy supply costs                                -         570         199
Operating expenses                                 -         447         289
Depreciation and amortization                      -         197          46
----------------------------------------------------------------------------
Operating income (loss)                            -         320         108
Other income (expenses), net                       -           6           3
Finance charges                                    -          75          30
Income tax expense (recovery)                      -          81          31
----------------------------------------------------------------------------
Net earnings (loss)                                -         170          50
Non-controlling interests                          -           -           -
Preference share dividends                         -           -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                        -         170          50
----------------------------------------------------------------------------
Goodwill                                           -       1,812         591
Identifiable assets                                -       6,826       2,479
----------------------------------------------------------------------------
Total assets                                       -       8,638       3,070
----------------------------------------------------------------------------
Gross capital expenditures                         -         416         177
----------------------------------------------------------------------------


                                                      REGULATED
                                        ------------------------------------
Year-to-Date                                           Canada
                                        ------------------------------------
September 30, 2017                          FortisBC      Fortis    FortisBC
($ millions)                                  Energy     Alberta    Electric
----------------------------------------------------------------------------
Revenue                                          832         448         291
Energy supply costs                              292           -         100
Operating expenses                               208         147          65
Depreciation and amortization                    149         142          47
----------------------------------------------------------------------------
Operating income                                 183         159          79
Other income (expenses), net                      14           1           1
Finance charges                                   86          69          28
Income tax expense (recovery)                     22           -          10
----------------------------------------------------------------------------
Net earnings (loss)                               89          91          42
Non-controlling interests                          1           -           -
Preference share dividends                         -           -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                       88          91          42
----------------------------------------------------------------------------
Goodwill                                         913         227         235
Identifiable assets                            5,353       4,061       1,942
----------------------------------------------------------------------------
Total assets                                   6,266       4,288       2,177
----------------------------------------------------------------------------
Gross capital expenditures                       329         304          72
----------------------------------------------------------------------------

Year-to-Date
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                          758         429         275
Energy supply costs                              204           -          93
Operating expenses                               209         142          63
Depreciation and amortization                    149         134          43
----------------------------------------------------------------------------
Operating income (loss)                          196         153          76
Other income (expenses), net                      11           2           1
Finance charges                                   97          63          28
Income tax expense (recovery)                     29           1           8
----------------------------------------------------------------------------
Net earnings (loss)                               81          91          41
Non-controlling interests                          -           -           -
Preference share dividends                         -           -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                       81          91          41
----------------------------------------------------------------------------
Goodwill                                         913         227         235
Identifiable assets                            5,089       3,789       1,899
----------------------------------------------------------------------------
Total assets                                   6,002       4,016       2,134
----------------------------------------------------------------------------
Gross capital expenditures                       252         260          53
----------------------------------------------------------------------------


                                                      REGULATED
                                        ------------------------------------
Year-to-Date                               Canada
                                        ------------
September 30, 2017                           Eastern   Caribbean
($ millions)                                Canadian    Electric       Total
----------------------------------------------------------------------------
Revenue                                          789         227       6,036
Energy supply costs                              511         105       1,756
Operating expenses                               100          34       1,631
Depreciation and amortization                     71          42         860
----------------------------------------------------------------------------
Operating income                                 107          46       1,789
Other income (expenses), net                       -           3          74
Finance charges                                   42          14         539
Income tax expense (recovery)                     17           -         396
----------------------------------------------------------------------------
Net earnings (loss)                               48          35         928
Non-controlling interests                          -          10          71
Preference share dividends                         -           -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                       48          25         857
----------------------------------------------------------------------------
Goodwill                                          67         177      11,561
Identifiable assets                            2,334       1,113      33,706
----------------------------------------------------------------------------
Total assets                                   2,401       1,290      45,267
----------------------------------------------------------------------------
Gross capital expenditures                       102          86       2,121
----------------------------------------------------------------------------

Year-to-Date
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                          785         225       4,648
Energy supply costs                              511         101       1,678
Operating expenses                               101          35       1,286
Depreciation and amortization                     68          39         676
----------------------------------------------------------------------------
Operating income (loss)                          105          50       1,008
Other income (expenses), net                       1           5          29
Finance charges                                   43          10         346
Income tax expense (recovery)                     15           -         165
----------------------------------------------------------------------------
Net earnings (loss)                               48          45         526
Non-controlling interests                          -          11          11
Preference share dividends                         -           -           -
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                       48          34         515
----------------------------------------------------------------------------
Goodwill                                          67         186       4,031
Identifiable assets                            2,255       1,137      23,474
----------------------------------------------------------------------------
Total assets                                   2,322       1,323      27,505
----------------------------------------------------------------------------
Gross capital expenditures                       113          83       1,354
----------------------------------------------------------------------------


                                                   NON-REGULATED
                                        ------------------------------------
Year-to-Date

September 30, 2017                           Energy Infra-        Corporate
($ millions)                                     structure        and Other
----------------------------------------------------------------------------
Revenue                                                162                1
Energy supply costs                                      1                -
Operating expenses                                      35               (1)
Depreciation and amortization                           24                1
----------------------------------------------------------------------------
Operating income                                       102                1
Other income (expenses), net                             1                4
Finance charges                                          4              144
Income tax expense (recovery)                            9              (91)
----------------------------------------------------------------------------
Net earnings (loss)                                     90              (48)
Non-controlling interests                               21                -
Preference share dividends                               -               49
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                             69              (97)
----------------------------------------------------------------------------
Goodwill                                                27                -
Identifiable assets                                  1,551               72
----------------------------------------------------------------------------
Total assets                                         1,578               72
----------------------------------------------------------------------------
Gross capital expenditures                              13                -
----------------------------------------------------------------------------

Year-to-Date
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                                139                7
Energy supply costs                                     20                -
Operating expenses                                      28               61
Depreciation and amortization                           21                3
----------------------------------------------------------------------------
Operating income (loss)                                 70              (57)
Other income (expenses), net                             1                5
Finance charges                                          3              109
Income tax expense (recovery)                            1              (56)
----------------------------------------------------------------------------
Net earnings (loss)                                     67             (105)
Non-controlling interests                               22                -
Preference share dividends                               -               59
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                             45             (164)
----------------------------------------------------------------------------
Goodwill                                                27                -
Identifiable assets                                  1,465              280
----------------------------------------------------------------------------
Total assets                                         1,492              280
----------------------------------------------------------------------------
Gross capital expenditures                              17               10
----------------------------------------------------------------------------




Year-to-Date

September 30, 2017                          Inter-segment
($ millions)                                 eliminations              Total
----------------------------------------------------------------------------
Revenue                                                (9)             6,190
Energy supply costs                                    (1)             1,756
Operating expenses                                     (8)             1,657
Depreciation and amortization                           -                885
----------------------------------------------------------------------------
Operating income                                        -              1,892
Other income (expenses), net                           (1)                78
Finance charges                                        (1)               686
Income tax expense (recovery)                           -                314
----------------------------------------------------------------------------
Net earnings (loss)                                     -                970
Non-controlling interests                               -                 92
Preference share dividends                              -                 49
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                             -                829
----------------------------------------------------------------------------
Goodwill                                                -             11,588
Identifiable assets                                   (72)            35,257
----------------------------------------------------------------------------
Total assets                                          (72)            46,845
----------------------------------------------------------------------------
Gross capital expenditures                              -              2,134
----------------------------------------------------------------------------

Year-to-Date
September 30, 2016
($ millions)
----------------------------------------------------------------------------
Revenue                                                (9)             4,785
Energy supply costs                                     -              1,698
Operating expenses                                     (8)             1,367
Depreciation and amortization                           -                700
----------------------------------------------------------------------------
Operating income (loss)                                (1)             1,020
Other income (expenses), net                            -                 35
Finance charges                                        (1)               457
Income tax expense (recovery)                           -                110
----------------------------------------------------------------------------
Net earnings (loss)                                     -                488
Non-controlling interests                               -                 33
Preference share dividends                              -                 59
----------------------------------------------------------------------------
Net earnings (loss) attributable to
 common equity shareholders                             -                396
----------------------------------------------------------------------------
Goodwill                                                -              4,058
Identifiable assets                                   (86)            25,133
----------------------------------------------------------------------------
Total assets                                          (86)            29,191
----------------------------------------------------------------------------
Gross capital expenditures                              -              1,381
----------------------------------------------------------------------------

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 and nine months ended September 30, 2017 and 2016.

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

                                               Quarter Ended    Year-to-Date
                                                September 30    September 30
($ millions)                                    2017    2016    2017    2016
----------------------------------------------------------------------------
Sale of capacity from Waneta Expansion to
 FortisBC Electric (Note 19)                      11      14      30      32
Sale of energy from Belize Electric Company
 Limited to Belize Electricity                    11      12      25      26
Lease of gas storage capacity and gas sales
 from Aitken Creek to FortisBC Energy (Note
 19)                                               5       4      18       9
----------------------------------------------------------------------------

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

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
                                                September 30,  December 31,
($ millions)                                             2017          2016
----------------------------------------------------------------------------
Regulatory assets
Deferred income taxes                                   1,271         1,260
Employee future benefits                                  523           576
Deferred energy management costs                          192           178
Deferred lease costs                                      109            97
Generation early retirement costs (1)                     103             -
Rate stabilization accounts                               100           183
Deferred operating overhead costs                          88            78
Manufactured gas plant site remediation deferral           75           107
Natural gas for transportation incentives                  36            40
Other regulatory assets                                   393           414
----------------------------------------------------------------------------
Total regulatory assets                                 2,890         2,933
Less: current portion                                    (270)         (313)
----------------------------------------------------------------------------
Long-term regulatory assets                             2,620         2,620
----------------------------------------------------------------------------

                                                           As at
                                                September 30,  December 31,
($ millions)                                             2017          2016
----------------------------------------------------------------------------
Regulatory liabilities
Non-asset retirement obligation removal cost
 provision                                              1,081         1,194
Rate stabilization accounts                               245           230
Return on equity refund liability                         179           346
Energy efficiency liability                                74            49
Renewable energy surcharge                                 63            53
Electric and gas moderator account                         58            71
Employee future benefits                                   44            42
Other regulatory liabilities                              181           198
----------------------------------------------------------------------------
Total regulatory liabilities                            1,925         2,183
Less: current portion                                    (463)         (492)
----------------------------------------------------------------------------
Long-term regulatory liabilities                        1,462         1,691
----------------------------------------------------------------------------

(1) Generation early retirement costs

    UNS Energy holds an undivided interest in the jointly owned Navajo
    Generating Station ("Navajo"), located on a site leased from the Navajo
    Nation with an initial lease term through December 2019. In June 2017
    the Navajo Nation approved a land-lease extension that allows TEP and
    the co-owners of Navajo to continue operations through December 2019 and
    begin decommissioning activities thereafter. Retirement costs related to
    Navajo are currently being recovered through to 2030.

    UNS Energy owns the Sundt Generating Facility ("Sundt") and in August
    2017 TEP submitted an application related to a generation modernization
    project at the facility, which will add generation capacity in the form
    of gas-fired reciprocating engines. As part of the application, TEP
    plans to early retire Sundt Units 1 and 2 by the end of 2020. Capital
    and operating costs related to Sundt Units 1 and 2 are currently being
    recovered through to 2028 and 2030, respectively.

    As a result of the planned early retirement of Navajo and Sundt Units 1
    and 2, the net book value and other related retirement costs were
    reclassified from capital assets to regulatory assets, and as at
    September 30, 2017 the net book value of these assets was $103 million
    (US$83 million).

6. LONG-TERM DEBT

                                                           As at
                                                September 30,  December 31,
($ millions)                                             2017          2016
----------------------------------------------------------------------------
Long-term debt                                         20,096        20,246
Long-term classification of credit facility
 borrowings (Note 16)                                     538           973
----------------------------------------------------------------------------
Total long-term debt (Note 15)                         20,634        21,219
Less: Deferred financing costs and debt
 discounts                                               (142)         (151)
Less: Current installments of long-term debt             (997)         (251)
----------------------------------------------------------------------------
                                                       19,495        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 September 30, 2017, borrowings under the term loan credit agreements were US$200 million ($250 million) and US$50 million ($62 million), respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes.

In April 2017 ITC issued 30-year US$200 million ($250 million) secured first mortgage bonds at 4.16%. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.

In March and May 2017, Caribbean Utilities issued US$60 million ($75 million) of unsecured notes in a dual tranche of 15-year US$40 million ($50 million) at 3.90% and 30-year US$20 million ($25 million) at 4.64%, respectively. The net proceeds from the issuances were used to finance capital expenditures and repay short-term borrowings.

In June 2017 Newfoundland Power issued 40-year $75 million first mortgage sinking fund bonds at 3.815%. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.

In August 2017 Central Hudson issued 30-year US$30 million ($37 million) unsecured notes at 4.05% and 40-year US$30 million ($37 million) unsecured notes at 4.20%. The net proceeds from the issuances were used to repay maturing long-term debt and for general corporate purposes.

In September 2017 FortisAlberta issued 30-year $200 million unsecured debentures at 3.67%. The net proceeds from the issuance were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes.

In October 2017 FortisBC Energy issued $175 million of unsecured debentures at 3.69%. The net proceeds from the issuance were used to repay short-term borrowings.

7. COMMON SHARES

Common shares issued during the period were as follows.

                                 Quarter Ended                  Year-to-Date
                            September 30, 2017            September 30, 2017
                ------------------------------------------------------------
                          Number                        Number
                       of Shares        Amount       of Shares        Amount
                  (in thousands)  ($ millions)  (in thousands)  ($ millions)
----------------------------------------------------------------------------
Balance,
 beginning of
 period                  417,885        11,435         401,486        10,762
  Private
   Offering                    -             -          12,195           500
  Dividend
   Reinvestment
   Plan                    1,368            61           4,323           187
  Stock Option
   Plans                     107             5           1,062            39
  Employee Share
   Purchase Plan              83             4             360            16
  Consumer Share
   Purchase Plan               6             -              21             1
  Conversion of
   Convertible
   Debentures                  -             -               2             -
----------------------------------------------------------------------------
Balance, end of
 period                  419,449        11,505         419,449        11,505
----------------------------------------------------------------------------

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 16).

8. PREFERENCE SHARES

In September 2016 the Corporation redeemed all of the issued and outstanding $200 million 4.9% First Preference Shares, Series E at a redemption price of $25.3063 per share, being equal to $25.00 plus the amount of accrued and unpaid dividends per share. Upon redemption, approximately $3 million of after-tax issuance costs associated with the First Preference Shares, Series E were recognized in net earnings attributable to preference equity shareholders.

9. STOCK-BASED COMPENSATION PLANS

For the three and nine months ended September 30, 2017, stock-based compensation expense of approximately $4 million and $28 million, respectively, was recognized ($3 million and $18 million for the three and nine months ended September 30, 2016, respectively).

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 10 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 accounting fair value of each option granted was $3.22 per option. The accounting 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.

In April 2017, 7,846 DSUs were granted to the Corporation's Board of Directors, representing the second quarter equity component of the Directors' annual compensation and, where opted, their second quarter component of annual retainers in lieu of cash.

In July 2017, 7,491 DSUs were granted to the Corporation's Board of Directors, representing the third quarter equity component of the Directors' annual compensation and, where opted, their third quarter component of annual retainers in lieu of cash.

Performance Share Unit Plans

Year-to-date 2017, the Corporation granted 728,552 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 consistent with past practice. 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 September 30, 2017, the estimated weighted average payout percentages ranged from 74% to 103%.

In the second quarter of 2017, the Corporation paid out 281,794 PSUs at $41.46 per PSU, for a total of approximately $13 million. The payout was made in respect of the PSUs granted in 2014. The payout percentage ranged from 106% to 113% and was based on the Corporation's and subsidiaries' performance over the three-year period, as determined by the respective Human Resources Committees.

Restricted Share Unit Plans

Year-to-date 2017, the Corporation granted 330,686 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 consistent with past practice. 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.

10. 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 September 30

                                        Defined Benefit
                                          Pension Plans          OPEB Plans
($ millions)                             2017      2016      2017      2016
----------------------------------------------------------------------------
Components of net benefit cost:
Service costs                              19        16         6         5
Interest costs                             27        28         6         5
Expected return on plan assets            (37)      (36)       (4)       (4)
Amortization of actuarial losses           11        12         -         -
Amortization of past service
 credits/plan amendments                    -         -        (3)       (3)
Regulatory adjustments                      1         2         2         2
----------------------------------------------------------------------------
Net benefit cost                           21        22         7         5
----------------------------------------------------------------------------

                                           Year-to-Date September 30

                                        Defined Benefit
                                          Pension Plans          OPEB Plans
($ millions)                             2017      2016      2017      2016
----------------------------------------------------------------------------
Components of net benefit cost:
Service costs                              58        48        20        12
Interest costs                             85        83        19        16
Expected return on plan assets           (113)     (107)      (11)      (10)
Amortization of actuarial losses           34        35         1         1
Amortization of past service
 credits/plan amendments                    -         1        (9)       (9)
Regulatory adjustments                      1         5         4         7
----------------------------------------------------------------------------
Net benefit cost                           65        65        24        17
----------------------------------------------------------------------------

For the three and nine months ended September 30, 2017, the Corporation expensed $8 million and $28 million, respectively, ($7 million and $22 million for the three and nine months ended September 30, 2016, respectively) related to defined contribution pension plans.

11. OTHER INCOME, NET

                                           Quarter Ended        Year-to-Date
                                            September 30        September 30
($ millions)                             2017       2016      2017      2016
----------------------------------------------------------------------------
Equity component of allowance for
 funds used during construction
 ("AFUDC")                                 19          7        55        20
Interest income                             4          1        11         5
Equity income - Belize Electricity          1          1         2         4
Other                                      (1)         1        10         6
----------------------------------------------------------------------------
                                           23         10        78        35
----------------------------------------------------------------------------

12. FINANCE CHARGES

                                          Quarter Ended        Year-to-Date
                                           September 30        September 30
($ millions)                             2017      2016      2017      2016
----------------------------------------------------------------------------
Interest:
  Long-term debt and capital lease
   and finance obligations                231       147       702       436
  Short-term borrowings                     4         1        12         5
Acquisition credit facilities               -        21         -        35
Debt component of AFUDC                   (10)       (5)      (28)      (19)
----------------------------------------------------------------------------
                                          225       164       686       457
----------------------------------------------------------------------------

13. 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 September 30
                                           2017
                          -------------------------------------
                                Net Earnings          Weighted
                                   to Common           Average
                                Shareholders            Shares
                                                              E
                                                              P
                                ($ millions)      (# millions)S
             --------------------------------------------------
             Basic EPS                   278             418.6$
             --------------------------------------------------
             Effect of
              potential
              dilutive
              securities:
               Stock
                Options                    -               0.7
               Preference
                Shares                     -                 -
             --------------------------------------------------
             Diluted EPS                 278             419.3$
             --------------------------------------------------


                                Quarter Ended September 30
                  2017                           2016
             ---------------------------------------------------------------
                                Net Earnings          Weighted
                                   to Common           Average
                                Shareholders            Shares
                       EPS      ($ millions)      (# millions)           EPS
----------------------------------------------------------------------------
Basic EPS             0.66               127             285.0$         0.45
----------------------------------------------------------------------------
Effect of
 potential
 dilutive
 securities:
  Stock
   Options                                 -               0.7
  Preference
   Shares                                  2               3.8
----------------------------------------------------------------------------
Diluted EPS           0.66               129             289.5$         0.45
----------------------------------------------------------------------------

                   Year-to-Date September 30
                              2017
             -------------------------------------
                   Net Earnings          Weighted
                      to Common           Average
                   Shareholders            Shares
                                                 E
                                                 P
                   ($ millions)      (# millions)S
--------------------------------------------------
Basic EPS                   829             413.9$
--------------------------------------------------
Effect of
 potential
 dilutive
 securities:
  Stock
   Options                    -               0.7
  Preference
   Shares                     -                 -
--------------------------------------------------
Diluted EPS                 829             414.6$
--------------------------------------------------


                                Year-to-Date September 30
                  2017                           2016
             ---------------------------------------------------------------
                                Net Earnings          Weighted
                                   to Common           Average
                                Shareholders            Shares
                       EPS      ($ millions)      (# millions)           EPS
----------------------------------------------------------------------------
Basic EPS             2.00               396             283.7$         1.40
----------------------------------------------------------------------------
Effect of
 potential
 dilutive
 securities:
  Stock
   Options                                 -               0.7
  Preference
   Shares                                  7               5.0
----------------------------------------------------------------------------
Diluted EPS           2.00               403             289.4$         1.39
----------------------------------------------------------------------------

14. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS

                                      Quarter Ended            Year-to-Date
                                       September 30            September 30
($ millions)                       2017        2016        2017        2016
----------------------------------------------------------------------------
Change in working capital:
Accounts receivable and
 other current assets                23          43          29         127
Prepaid expenses                    (61)        (30)        (50)        (37)
Inventories                         (36)        (39)        (25)          6
Regulatory assets - current
 portion                             15           4           2           4
Accounts payable and other
 current liabilities                 14          85          (7)         21
Regulatory liabilities -
 current portion                     25           -        (151)         16
----------------------------------------------------------------------------
                                    (20)         63        (202)        137
----------------------------------------------------------------------------

Non-cash investing and
 financing activities:
Accrued capital expenditures        295         152         295         152
Common share dividends
 reinvested                          61          37         186         102
Transfer of deposit on
 business acquisition (Note
 17)                                  -           -           -          38
Contributions in aid of
 construction                        32           6          32           6
Exercise of stock options
 into common shares                   -           1           4           4
----------------------------------------------------------------------------

15. 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  September 30,  December 31,
($ millions)                         hierarchy           2017          2016
----------------------------------------------------------------------------
Assets
Energy contracts subject to
 regulatory deferral (1) (2) (3)  Levels 1/2/3              5            19
Energy contracts not subject to
 regulatory deferral (1) (2) (4)    Levels 2/3             13             3
Interest rate swaps (5)                Level 2             13            11
Other investments (6)                  Level 1             80            69
----------------------------------------------------------------------------
Total gross assets                                        111           102
Less: Counterparty netting not
 offset on the balance sheet (7)                           (4)           (9)
----------------------------------------------------------------------------
Total net assets                                          107            93
----------------------------------------------------------------------------

Liabilities
Energy contracts subject to
 regulatory deferral (1) (2) (8)    Levels 2/3             37            26
Energy contracts not subject to
 regulatory deferral (1) (2) (9)     Level 2/3              1             9
Interest rate and total return
 swaps (5)                             Level 2              7             3
----------------------------------------------------------------------------
Total gross liabilities                                    45            38
Less: Counterparty netting not
 offset on the balance sheet (7)                           (4)           (9)
----------------------------------------------------------------------------
Total net liabilities                                      41            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 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 wholesale trading contracts and certain gas swap contracts.
(3) As at September 30, 2017, includes - $3 million - level 2 and $2 million
    - level 3 (December 31, 2016 - $1 million - level 1, $13 million - level
    2 and $5 million - level 3)
(4) As at September 30, 2017, includes - $8 million - level 2 and $5 million
    - level 3 (December 31, 2016 - $3 million - level 3)
(5) The fair value of the Corporation's interest rate and total return swaps
    is recognized in accounts receivable and other current assets, accounts
    payable and other current liabilities and long-term other liabilities.
(6) Included in long-term other assets on the consolidated balance sheet.
(7) 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.
(8) As at September 30, 2017, includes $26 million - level 2 and $11 million
    - level 3 (December 31, 2016 - $21 million - level 2 and $5 million -
    level 3).
(9) As at September 30, 2017, includes $1 million - level 3 (December 31,
    2016 - $9 million - level 2).

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 costs 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 September 30, 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 September 30, 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 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 from published market sources. The unrealized gains and losses on these derivative instruments are recognized in earnings.

Interest Rate and Total Return Swaps

As at September 30, 2017, ITC held forward-starting interest rate swaps, effective December 2017 and January 2018, with notional amounts totalling $936 million and with 5-year 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 long-term debt due in January 2018, and amounts outstanding under the revolving credit facility and commercial paper program.

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

In August 2017 the Corporation entered into three total return swaps with a combined notional amount of $33 million and terms ranging from one to three years terminating in January 2018, 2019 and 2020. The total return swaps manage the cash flow risk associated with forecasted future cash settlements of the respective DSU and RSU obligations (Note 9).

The unrealized gains and losses on interest rate swaps 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 $4 million (net of tax). The unrealized gains and losses on the total return swaps are recognized in earnings. 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 September 30, 2017, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.

                        Maturity Contracts                            There-
Volume(1)                 (year)       (#)  2017  2018 2019 2020  2021 after
----------------------------------------------------------------------------
Energy contracts
 subject to regulatory
 deferral:
Electricity swap
 contracts (GWh)            2019         8   247   832  438    -     -     -
Electricity power
 purchase contracts
 (GWh)                      2018        24   458   177    -    -     -     -
Gas swap contracts
 (PJ)                       2020       117     7    45   19    4     -     -
Gas supply contract
 premiums (PJ)              2024       125    40    82   31   28    22    43
Energy contracts not
 subject to regulatory
 deferral:
Wholesale trading
 contracts (GWh)            2018        19 1,056 2,300    -    -     -     -
Gas swap contracts
 (PJ)                       2018       111     6    27    -    -     -     -
----------------------------------------------------------------------------

(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 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
                                    September 30, 2017     December 31, 2016
                                --------------------------------------------
                                  Carrying   Estimated  Carrying   Estimated
($ millions)                         Value  Fair Value     Value  Fair Value
----------------------------------------------------------------------------
Long-term debt, including
 current portion (Note 6) (1)      20,634      22,147    21,219      22,523
Waneta Partnership promissory
 note (2)                              62          62        59          61
----------------------------------------------------------------------------

(1) 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.

16. 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, accounts receivable and other current assets, 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. FortisAlberta reduces its credit risk exposure 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 September 30, 2017, over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $721 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 September 30, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.3 billion, of which approximately $4.0 billion was unused, including $1.0 billion unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $4.8 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2022.

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

                                                           As at
                          Regulated   Corporate September 30,  December 31,
($ millions)              Utilities   and Other          2017          2016
----------------------------------------------------------------------------
Total credit facilities
 (1)                          3,950       1,385         5,335         5,976
Credit facilities
 utilized:
  Short-term borrowings
   (1) (2)                     (668)          -          (668)       (1,155)
  Long-term debt (Note
   6) (3)                      (266)       (272)         (538)         (973)
Letters of credit
 outstanding                    (73)        (55)         (128)         (119)
----------------------------------------------------------------------------
Credit facilities unused      2,943       1,058         4,001         3,729
----------------------------------------------------------------------------

(1) Total credit facilities and short-term borrowings as at September 30,
    2017 include $286 million outstanding under ITC's commercial paper
    program (December 31, 2016 - $195 million). Outstanding commercial paper
    does not reduce available capacity under the Corporation's consolidated
    credit facilities.
(2) The weighted average interest rate on short-term borrowings was
    approximately 1.5% as at September 30, 2017 (December 31, 2016 - 1.7%).
(3) As at September 30, 2017, none of the credit facility borrowings were
    classified as 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 2.4% as at September 30, 2017 (December 31, 2016 -
    1.8%).

As at September 30, 2017 and December 31, 2016, certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods. There were no material changes in credit facilities from that disclosed in the Corporation's 2016 annual audited consolidated financial statements except as follows.

In March 2017 the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares (Note 7). In July 2017 the Corporation amended its $1.3 billion unsecured committed revolving credit facility, resulting in an extension of the maturity date to July 2022. The Corporation has the option to increase the facility by $0.5 billion to $1.8 billion and, as at September 30, 2017, that option had not been exercised.

In September 2017 FortisAlberta repaid its $90 million bilateral credit facility using the proceeds from the issuance of long-term debt (Note 6). The bilateral credit facility was terminated upon repayment.

In October 2017 ITC replaced its US$1.0 billion ($1.2 billion) credit facility agreements with US$900 million ($1.1 billion) unsecured committed revolving credit facility agreements, maturing in October 2022.

Market Risk

Foreign Exchange Risk

The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, Fortis Turks and Caicos and Belize Electric Company Limited 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 September 30, 2017, the Corporation's corporately issued US$3,383 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 September 30, 2017, the Corporation had approximately US$7,671 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.

Consolidated earnings and cash flows of Fortis are impacted 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$1.25 as at September 30, 2017 would increase or decrease earnings per common share of Fortis by approximately 7 cents. In October 2017 the Corporation entered into forward sales contracts, with notional amounts totalling US$125 million, reducing its exposure to approximately 6 cents for every 5 cent change in the US dollar relative to the Canadian dollar. Management also continues to hedge future exchange rate fluctuations related to the Corporation's foreign net investments and US dollar-denominated earnings streams 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 15).

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 and Aitken Creek are 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. 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 and wholesale trading contracts at UNS Energy where the changes in fair value are recorded in earnings (Note 15).

17. BUSINESS ACQUISITIONS

2017

Terminated Acquisition of an Interest in Waneta Dam

In May 2017 Fortis had entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia. In August 2017 BC Hydro exercised its right of first offer to acquire Teck's two-thirds interest in the Waneta Dam and the purchase agreement between Fortis and Teck was terminated, resulting in the payment of a $28 million break fee to Fortis, which was recorded in operating expenses.

2016

ITC

On October 14, 2016, Fortis and GIC acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion ($15.7 billion) on closing, including approximately US$4.8 billion ($6.3 billion) of ITC consolidated indebtedness. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC.

Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion ($9.4 billion). The net cash consideration totalled approximately US$3.5 billion ($4.7 billion) and was financed using: (i) net proceeds from the issuance of US$2.0 billion unsecured notes in October 2016; (ii) net proceeds from GIC's US$1.228 billion minority investment, which includes a shareholder note of US$199 million; and (iii) drawings of approximately US$404 million ($535 million) under the Corporation's non-revolving term senior unsecured equity bridge credit facility. On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately US$3.5 billion ($4.7 billion), based on the closing price for Fortis common shares of $40.96 and the closing foreign exchange rate of US$1.00=CAD$1.32 on October 13, 2016. The financing of the acquisition was structured to allow Fortis to maintain investment-grade credit ratings.

The following table summarizes the preliminary allocation of the purchase consideration to the assets and liabilities acquired as at October 14, 2016 based on their fair values, using an exchange rate of US$1.00=CAD$1.32. The purchase price allocation remains preliminary pending final assessment of fair value estimates, income taxes, consideration transferred, and identification of assets and liabilities.

($ millions)                                                          Total
----------------------------------------------------------------------------

Share consideration                                                   4,684
Cash consideration                                                    4,658
----------------------------------------------------------------------------
Total consideration                                                   9,342
                                                                ------------

Purchase consideration for 80.1% of ITC common shares                 7,721
19.9% minority shareholder investment and shareholder note            1,621
----------------------------------------------------------------------------
                                                                      9,342
                                                                ------------

Fair value assigned to net assets:
Current assets                                                          319
Long-term regulatory assets                                             319
Capital assets, net                                                   8,345
Intangible assets, net                                                  392
Other long-term assets                                                   71
Current liabilities                                                    (625)
Assumed short-term borrowings                                          (311)
Assumed long-term debt (including current portion)                   (5,989)
Long-term regulatory liabilities                                       (327)
Deferred income taxes                                                  (926)
Other long-term liabilities                                            (166)
----------------------------------------------------------------------------
                                                                      1,102
Cash and cash equivalents                                               134
----------------------------------------------------------------------------
Fair value of net assets acquired                                     1,236
----------------------------------------------------------------------------
Goodwill                                                              8,106
----------------------------------------------------------------------------

The acquisition has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing on October 14, 2016.

Acquisition-related transaction costs totalled approximately $118 million ($90 million after tax) in 2016. Acquisition-related transaction costs included: (i) investment banking, legal, consulting and other fees totalling approximately $79 million ($62 million after tax) in 2016, which were included in operating expenses; and (ii) fees associated with the Corporation's acquisition credit facilities and deal-contingent interest rate swap contracts totalling approximately $39 million ($28 million after tax) in 2016, which were included in finance charges. From the date of acquisition, ITC also recognized US$21 million ($27 million) in after-tax expenses associated with the accelerated vesting of the Company's stock-based compensation awards as a result of the acquisition, of which the Corporation's share was US$17 million ($22 million).

Supplemental Pro Forma Data

The unaudited pro forma financial information below gives effect to the acquisition of ITC as if the transaction had occurred at the beginning of 2016. This pro forma data is presented for information purposes only, and does not necessarily represent the results that would have occurred had the acquisition taken place at the beginning of 2016, nor is it necessarily indicative of the results that may be expected in future periods.

($ millions)                                                            2016
----------------------------------------------------------------------------
Pro forma revenue                                                      7,995
Pro forma net earnings attributable to common equity shareholders
 (1)                                                                     919
----------------------------------------------------------------------------

(1) Pro forma net earnings attributable to common equity shareholders
    exclude all after-tax acquisition-related transaction costs incurred by
    ITC and the Corporation. A pro forma adjustment has been made to net
    earnings for the 12 months ended December 31, 2016 to reflect the
    Corporation's after-tax financing costs associated with the acquisition.

Aitken Creek

On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC from Chevron Canada Properties Ltd. for approximately $349 million (US$266 million), plus the cost of working gas inventory. The net cash purchase price was initially financed through US dollar-denominated borrowings under the Corporation's committed revolving credit facility. In December 2015 the Corporation paid a deposit of $38 million (US$29 million) as part of the purchase consideration for the transaction (Note 14).

The allocation of purchase consideration to the assets and liabilities acquired as at April 1, 2016, based on their fair values, resulted in the recognition of approximately $27 million in goodwill, which is associated with deferred income tax liabilities. The acquisition has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing on April 1, 2016. The purchase price allocation was finalized during the first quarter of 2017.

18. 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 3,367 asbestos cases have been raised, 1,177 remained pending as at September 30, 2017. Of the cases no longer pending against Central Hudson, 2,034 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 condensed consolidated interim 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. In September 2017 the Federal Court of Appeal set aside the minister's consent and returned the matter to the minister for redetermination. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the condensed consolidated interim 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 March 2017 an agreement in principle was reached to settle the case, subject to formal documentation and court approval. In September 2017 a final settlement approval hearing was held after which the court entered an order and final judgment approving the settlement. Pursuant to the order and final judgment, the shareholder class action litigation against ITC has been dismissed.

Fortis Turks and Caicos

In September 2017 the Turks and Caicos Islands were struck by Hurricane Irma, resulting in significant damage to Fortis Turks and Caicos' transmission and distribution system. Damaged energy infrastructure interrupted the Company's ability to provide electricity service to its customers, and restoration efforts continue. The Company is currently assessing the total cost of restoration. The possibility exists that the impact of Hurricane Irma could adversely affect future earnings of Fortis Turks and Caicos as well as impair its capital assets and goodwill. The outcome cannot be reasonably determined or estimated at this time and, accordingly, no amount has been accrued in the condensed consolidated interim financial statements.

19. COMPARATIVE FIGURES

Certain comparative figures have been reclassified to comply with current period presentation. To correct the treatment of related-party transactions to be in accordance with accounting standards for rate-regulated entities, Fortis no longer eliminates related-party transactions between non-regulated and regulated entities. As a result, the sale of energy from the Waneta Expansion to FortisBC Electric and the lease of natural gas storage from Aitken Creek to FortisBC Energy are no longer eliminated, increasing both revenue and energy supply costs for the three and nine months ended September 30, 2016 by $18 million and $41 million, respectively (Note 4).

Contacts:
Ms. Stephanie Amaimo
Vice president, investor relations
(709) 737-2900

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