Fortis Inc.
TSX : FTS
NYSE : FTS

Fortis Inc.

July 28, 2017 06:00 ET

Fortis Reports Strong Second Quarter Earnings of $257 million

ST. JOHN'S, NEWFOUNDLAND AND LABRADOR--(Marketwired - July 28, 2017) - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS)(NYSE:FTS), a leader in the North American regulated electric and gas utility industry, released its second quarter results today.

"Two clear goals for us in 2017 were realizing the economic benefit of the acquisition of ITC, which remains nicely accretive, and securing a reasonable outcome in our first large rate case in Arizona since the announcement of the UNS Energy acquisition in 2013. Achievement of these two goals was a factor in delivering strong second quarter results," said Barry Perry, President and Chief Executive Officer, Fortis.

Reported Net Earnings

The Corporation reported second quarter net earnings attributable to common equity shareholders of $257 million, or $0.62 per common share, compared to $107 million, or $0.38 per common share, for the same period of 2016. On a year-to-date basis, reported net earnings attributable to common equity shareholders were $551 million, or $1.34 per common share, compared to $269 million, or $0.95 per common share, for the same period of 2016.

  • Earnings per common share for the quarter benefitted from the impact of the rate case settlement and higher weather driven electricity sales at UNS Energy, and accretion associated with the acquisition of ITC.
  • Also contributing to the strong second quarter results was lower Corporate and Other expenses, primarily due to acquisition-related transaction costs associated with ITC recognized in the second quarter of 2016, higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives quarter over quarter, and favourable foreign exchange associated with US dollar-denominated earnings.

Adjusted Net Earnings1

On an adjusted basis, net earnings attributable to common equity shareholders for the second quarter were $253 million, or $0.61 per common share, an increase of $0.16 per common share over the same period of 2016. On a year-to-date basis, adjusted net earnings attributable to common equity shareholders were $540 million, or $1.31 per common share, an increase of $0.18 per common share over the same period of 2016. Adjusted net earnings no longer excludes mark-to-market adjustments related to derivative instruments, which occur in the normal course of business, as comparative information is now presented in reported net earnings.

  • UNS Energy contributed an additional $0.10 to adjusted net earnings per common share quarter over quarter, driven primarily by the impact of its rate case settlement and higher electricity sales due to weather.
  • ITC continues to be nicely accretive and in-line with expectations, with segmented net earnings of $93 million for the quarter. After considering the increase in the weighted average number of common shares outstanding and finance charges related to the acquisition, ITC had a $0.04 accretive impact on adjusted net earnings per common share. Accretion was tempered by the outperformance of the other utilities.

Capital expenditure plan on track and supported by strong cash flow

Capital expenditures for the first half of 2017 were $1.4 billion and the Corporation's consolidated capital expenditure plan of $3.1 billion for 2017 is on track.

Cash flow from operating activities totalled $1.2 billion for the first half of 2017, an increase of 28% over the same period of 2016. The increase reflects higher earnings, driven by UNS Energy and ITC, partially offset by timing differences in working capital.

1Non-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.

Execution of growth strategy

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

Construction of the Tilbury liquefied natural gas ("LNG") facility expansion in British Columbia, the Corporation's largest ongoing capital project, is nearing completion. The total cost of the project is estimated at approximately $400 million, before allowance for funds used during construction and development costs. The facility is expected to be in service in the third quarter of 2017.

The Corporation continues to invest in four Multi-Value Projects ("MVPs") at ITC, which are regional electric transmission projects that have been identified by the Midcontinent Independent System Operator to address system capacity needs and reliability in various states. Approximately $228 million (US$176 million) was invested in the MVPs from the date of acquisition of ITC and an additional $135 million (US$102 million) is expected to be spent in the remainder of 2017. Three of the MVPs are expected to be completed by the end of 2018, with the fourth scheduled for completion in 2023.

In addition to the Corporation's base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. Specifically, two significant electric transmission opportunities are being pursued. The Wataynikaneyap Power project in Northwestern Ontario, which involves construction of new transmission lines to connect remote First Nation communities to the electricity grid, and the Lake Erie Connector project at ITC, which would connect the Province of Ontario to the PJM electricity market. During the quarter noteworthy milestones were achieved with respect to the Lake Erie Connector project. In May ITC completed the major permit process in Pennsylvania upon receipt of two required permits from the Pennsylvania Department of Environmental Protection, and in June approval was received from Canada's Governor in Council and the Certificate of Public Convenience and Necessity was issued by the National Energy Board.

Furthermore, the Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including the potential pipeline expansion to the proposed Woodfibre LNG export facility and further expansion of the Tilbury LNG facility. Fortis and its utilities are focused on achieving key milestones in 2017 to further advance these opportunities.

In May 2017 Fortis entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia, for $1.2 billion. Closing of the transaction is subject to customary conditions, including receipt of certain approvals and consents. In addition, BC Hydro, which owns the remaining one-third ownership interest, has a right of first offer with respect to the sale by Teck. Providing BC Hydro does not exercise its right to purchase Teck's two-thirds interest in the dam, the transaction is expected to close in the fourth quarter of 2017.

"At Fortis our portfolio of utilities is well diversified and provides numerous growth opportunities. We continue to make progress on our $13 billion five-year base capital plan with more than $3 billion to be spent throughout 2017," continued Mr. Perry. "This plan coupled with incremental opportunities for investment in our service territories, including our intention to purchase a stake in the Waneta Dam hydroelectric facility, provides high quality low risk growth for the Corporation."

Outlook

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

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

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

"As we look past 2017, we are seeing upside to our five-year base capital plan at our utility businesses. The opportunities we are identifying will enhance our ability to serve customers safely and reliably, grow our rate base, and support our 6% average annual dividend growth target while maintaining a conservative payout ratio," concluded Mr. Perry.

Teleconference to Discuss Second Quarter 2017 Results
A teleconference and webcast will be held on July 28 at 10:00 a.m. (Eastern). Barry Perry, President and Chief Executive Officer and Karl Smith, Executive Vice President, Chief Financial Officer, will discuss the Corporation's second 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, www.fortisinc.com.

A replay of the conference will be available two hours after the conclusion of the call until August 28, 2017. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 37869181.

Interim Management Discussion and Analysis

For the three and six months ended June 30, 2017

Dated July 27, 2017

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

FORWARD-LOOKING INFORMATION

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

Fortis includes "forward-looking information" in the MD&A within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, collectively referred to as "forward-looking information". Forward-looking information included in the MD&A reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which include, without limitation: the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas ("LNG") facility and Multi-Value Projects, and additional opportunities including the pipeline expansion to the Woodfibre LNG site, the Lake Erie Connector Project and the Wataynikaneyap Project; the Corporation's forecast gross consolidated and segmented capital expenditures for 2017 and from 2017 to 2021; statements related to the acquisition of an interest in the Waneta Dam and related transmission assets, including the expected timing and benefits thereof, total expected consideration and adjustments, the expected financing of the acquisition and conditions precedent to the closing, including receipt of certain approvals and consents; the expectation that the Corporation's 2017 results will continue to benefit from the acquisition of ITC and the impact of Tucson Electric Power Company's general rate case;
the Corporation's forecast rate base over the five-year period through 2021; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; target average annual dividend growth through 2021; the expectation that subsidiary operating expenses and interest costs will be paid out of subsidiary operating cash flows; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis; the expectation that maintaining the targeted capital structure of the Corporation's regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; the expectation that cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions will be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt and advances from minority investors; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2017; the intent of management to refinance certain borrowings under Corporation's and subsidiaries' long-term committed credit facilities with long-term permanent financing; the expectation that long-term debt will not be settled prior to maturity; the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements; and the expectation that any liability from current legal proceedings and claims will not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows.

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

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

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

CORPORATE OVERVIEW

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

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

SIGNIFICANT ITEMS

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

FINANCIAL HIGHLIGHTS

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

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

Revenue

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

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

Energy Supply Costs

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

Operating Expenses

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

Depreciation and Amortization

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

Other Income, Net

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

Finance Charges

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

Income Tax Expense

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

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

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

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

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

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

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

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

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

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

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

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

SEGMENTED RESULTS OF OPERATIONS

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

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

REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES

ITC

Financial Highlights (1)
Periods Ended June 30, 2017 Quarter Year-to-Date
Average US:CAD Exchange Rate (2) 1.34 1.33
Revenue ($ millions) 408 803
Earnings ($ millions) 93 184
(1) Revenue represents 100% of ITC, while earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflects consolidated purchase price accounting adjustments.
(2) The reporting currency of ITC is the US dollar.

Revenue and Earnings

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

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

UNS ENERGY (1)

Financial Highlights Quarter Year-to-Date
Periods Ended June 30 2017 2016 Variance 2017 2016 Variance
Average US:CAD Exchange Rate (2) 1.34 1.29 0.05 1.33 1.33 -
Electricity Sales (gigawatt hours ("GWh")) 3,618 3,608 10 7,002 6,652 350
Gas Volumes (petajoules ("PJ")) 3 3 - 8 8 -
Revenue ($ millions) 552 490 62 1,010 930 80
Earnings ($ millions) 89 56 33 130 68 62
(1) Includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. and UNS Gas, Inc.
(2) The reporting currency of UNS Energy is the US dollar.

Electricity Sales & Gas Volumes

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

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

Gas volumes were comparable with the same periods in 2016.

Revenue

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

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

Earnings

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

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

CENTRAL HUDSON

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

Electricity Sales & Gas Volumes

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

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

Revenue

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

Earnings

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

REGULATED GAS UTILITY - CANADIAN

FORTISBC ENERGY

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

Gas Volumes

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

Revenue

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

Earnings

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

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

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

REGULATED ELECTRIC UTILITIES - CANADIAN

FORTISALBERTA

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

Energy Deliveries

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

Revenue

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

Earnings

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

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

FORTISBC ELECTRIC (1)

Financial Highlights Quarter Year-to-Date
Periods Ended June 30 2017 2016 Variance 2017 2016 Variance
Electricity Sales (GWh) 712 684 28 1,657 1,535 122
Revenue ($ millions) 85 83 2 198 187 11
Earnings ($ millions) 16 15 1 31 30 1
(1) Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants.

Electricity Sales

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

Revenue

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

Earnings

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

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

EASTERN CANADIAN ELECTRIC UTILITIES (1)

Financial Highlights Quarter Year-to-Date
Periods Ended June 30 2017 2016 Variance 2017 2016 Variance
Electricity Sales (GWh) 1,934 1,921 13 4,671 4,627 44
Revenue ($ millions) 251 245 6 583 574 9
Earnings ($ millions) 18 16 2 36 34 2
(1) Comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime Electric Company, Limited and FortisOntario Inc. ("FortisOntario").

Electricity Sales

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

Revenue

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

Earnings

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

REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)

Financial Highlights Quarter Year-to-Date
Periods Ended June 30 2017 2016 Variance 2017 2016 Variance
Average US:CAD Exchange Rate (2) 1.34 1.29 0.05 1.33 1.33 -
Electricity Sales (GWh) 220 215 5 411 405 6
Revenue ($ millions) 80 71 9 150 146 4
Earnings ($ millions) 9 11 (2 ) 17 21 (4 )
(1) Comprised of Caribbean Utilities Company, Ltd. ("Caribbean Utilities"), in which Fortis holds an approximate 60% controlling interest, and two wholly owned utilities, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "Fortis Turks and Caicos"). Also includes the Corporation's 33% equity investment in Belize Electricity.
(2) The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00.

Electricity Sales

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

Revenue

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

Earnings

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

NON-REGULATED - ENERGY INFRASTRUCTURE (1)

Financial Highlights Quarter Year-to-Date
Periods Ended June 30 2017 2016 Variance 2017 2016 Variance
Energy Sales (GWh) 519 516 3 601 605 (4 )
Revenue ($ millions) 59 67 (8 ) 115 95 20
Earnings ($ millions) 25 19 6 48 30 18
(1) Primarily comprised of long-term contracted generation assets in British Columbia and Belize, with a combined generating capacity of 391 MW, and the Aitken Creek natural gas storage facility in British Columbia, with a total working gas capacity of 77 billion cubic feet.

Energy Sales

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

Revenue

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

Earnings

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

CORPORATE AND OTHER (1)

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

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

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

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

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

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

REGULATORY HIGHLIGHTS

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

ITC

ROE Complaints

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

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

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

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

UNS Energy

General Rate Application

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

FERC Order

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

Central Hudson

General Rate Application

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

FortisAlberta

Capital Tracker Applications

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

Generic Cost of Capital

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

Next Generation Performance-Based Rate-Setting Proceeding

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

Significant Regulatory Proceedings

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

Regulated Utility Application/Proceeding Filing Date Expected Decision
ITC Second MISO Base ROE Complaint Not applicable To be determined
Central Hudson General Rate Application July 2017 July 2018

CONSOLIDATED FINANCIAL POSITION

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

Significant Changes in the Consolidated Balance Sheets between June 30, 2017 and December 31, 2016

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

LIQUIDITY AND CAPITAL RESOURCES

SUMMARY OF CONSOLIDATED CASH FLOWS

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

Summary of Consolidated Cash Flows
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2017 2016 Variance 2017 2016 Variance
Cash, Beginning of Period 298 232 66 269 242 27
Cash Provided by (Used in):
Operating Activities 649 448 201 1,190 931 259
Investing Activities (741 ) (762 ) 21 (1,460 ) (1,175 ) (285 )
Financing Activities 27 380 (353 ) 235 314 (79 )
Effect of Exchange Rate Changes on Cash and Cash Equivalents (2 ) (2 ) - (3 ) (16 ) 13
Cash, End of Period 231 296 (65 ) 231 296 (65 )

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

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

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

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

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

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

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

Proceeds from Long-Term Debt, Net of Issue Costs
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2017 2016 Variance 2017 2016 Variance
ITC (1) 267 - 267 601 - 601
Central Hudson (2) - 29 (29 ) - 29 (29 )
FortisBC Energy (3) - 298 (298 ) - 298 (298 )
Eastern Canadian (4) 75 - 75 75 - 75
Caribbean Electric (5)(6) 26 29 (3 ) 80 29 51
Total 368 356 12 756 356 400
(1) In March 2017 ITC entered into 1-year and 2-year unsecured term loan credit agreements at floating interest rates of a one-month LIBOR plus a spread of 0.90% and 0.65%, respectively. As at June 30, 2017, borrowings under the term loan credit agreements were US$200 million ($268 million) and US$50 million ($67 million), respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes. In April 2017 ITC issued 30-year US$200 million ($268 million) 4.16% secured first mortgage bonds. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.
(2) In June 2016 Central Hudson issued 4-year US$24 million ($29 million) 2.16% unsecured notes. The net proceeds were used to finance capital expenditures and for general corporate purposes.
(3) In April 2016 FortisBC Energy issued $300 million of unsecured debentures in a dual tranche of 10-year $150 million unsecured debentures at 2.58% and 30-year $150 million unsecured debentures at 3.67%. The net proceeds were used to repay short-term borrowings and to finance capital expenditures.
(4) In June 2017 Newfoundland Power issued 40-year $75 million 3.82% first mortgage sinking fund bonds. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.
(5) In March and May 2017, Caribbean Utilities issued US$60 million ($80 million) of unsecured notes in a dual tranche of 15-year US$40 million ($54 million) at 3.90% and 30-year US$20 million ($26 million) at 4.64%, respectively. The net proceeds from the issuances were used to finance capital expenditures and repay short-term borrowings.
(6) In May 2016 Fortis Turks and Caicos issued 15-year US$23 million ($29 million) 5.14% unsecured notes. The net proceeds were used to finance capital expenditures.
Repayments of Long-Term Debt and Capital Lease and Finance Obligations
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2017 2016 Variance 2017 2016 Variance
UNS Energy (6 ) (6 ) - (19 ) (19 ) -
Central Hudson (1 ) (10 ) 9 (1 ) (10 ) 9
FortisBC Energy (1 ) (7 ) 6 (3 ) (9 ) 6
FortisBC Electric - - - (1 ) (25 ) 24
Eastern Canadian - (30 ) 30 - (30 ) 30
Caribbean Electric (11 ) (16 ) 5 (11 ) (16 ) 5
Total (19 ) (69 ) 50 (35 ) (109 ) 74
Net (Repayments) Borrowings Under Committed Credit Facilities
Periods Ended June 30 Quarter Year-to-Date
($ millions) 2017 2016 Variance 2017 2016 Variance
ITC (219 ) - (219 ) (242 ) - (242 )
UNS Energy 26 22 4 40 68 (28 )
FortisAlberta 60 45 15 95 62 33
Eastern Canadian (80 ) 24 (104 ) (52 ) 46 (98 )
Corporate (1) (28 ) 330 (358 ) (17 ) 337 (354 )
Total (241 ) 421 (662 ) (176 ) 513 (689 )
(1) Borrowings under the Corporation's committed credit facility in the second quarter of 2016 were primarily used to finance the acquisition of Aitken Creek.

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

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

CONTRACTUAL OBLIGATIONS

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

CAPITAL STRUCTURE

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

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

Capital Structure As at
June 30, 2017 December 31, 2016
($ millions) (%) ($ millions) (%)
Total debt and capital lease and financeobligations (net of cash) (1) 21,959 58.9 22,490 60.6
Preference shares 1,623 4.4 1,623 4.4
Common shareholders' equity 13,691 36.7 12,974 35.0
Total 37,273 100.0 37,087 100.0
(1) Includes long-term debt and capital lease and finance obligations, including current portion, and short-term borrowings, net of cash

Including amounts related to non-controlling interests, the Corporation's capital structure as at June 30, 2017 was 56.1% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 35.0% common shareholders' equity and 4.7% non-controlling interests (December 31, 2016 - 57.8% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 33.3% common shareholders' equity and 4.7% non-controlling interests). The change in the Corporation's capital structure was mainly due to an increase in common equity at the Corporation due to the issuance of $500 million of common shares in March 2017, used to repay short-term borrowings.

CREDIT RATINGS

The Corporation's credit ratings are as follows.

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

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

CAPITAL EXPENDITURE PROGRAM

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

Gross Consolidated Capital Expenditures (1)
Year-to-Date June 30, 2017
($ millions)
Regulated
ITC UNS
Energy

Central
Hudson

FortisBC
Energy

Fortis
Alberta

FortisBC
Electric

Eastern
Canadian

Caribbean
Electric
Total
Regulated
Utilities
Non-
Regulated (2)


Total
Total 512 248 103 197 195 46 63 57 1,421 7 1,428
(1) Represents cash payments to construct capital and intangible assets, as reflected on the condensed consolidated interim statement of cash flows. Excludes the non-cash equity component of AFUDC.
(2) Includes Energy Infrastructure and Corporate and Other segments

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

Gross consolidated capital expenditures for 2017 are forecast to be approximately $3.1 billion. There have been no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those that were disclosed in the 2016 Annual MD&A, with the exception of those noted below for UNS Energy and FortisBC Energy.

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

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

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

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

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

ADDITIONAL INVESTMENT OPPORTUNITIES

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

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

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

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

In January 2017 ITC received approval of a Presidential Permit from the U.S. Department of Energy for the Lake Erie Connector transmission line, which is a required approval for international border-crossing projects. Also in January, ITC received a report from Canada's NEB recommending the issuance of a Certificate of Public Convenience and Necessity ("CPCN") with prescribed conditions for the transmission line. In May 2017 ITC completed the major permit process in Pennsylvania upon receipt of two required permits from the Pennsylvania Department of Environmental Protection. In June 2017 ITC received approval from Canada's Governor in Council and the CPCN was issued by the NEB. The Lake Erie Connector project is a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line that would provide the first direct link between the markets of the Ontario Independent Electricity System Operator and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets. The project continues to advance through regulatory, operational, and economic milestones. Remaining key milestones include: receiving approval from the U.S. Army Corps of Engineers of a joint application, of which approval by the Pennsylvania Department of Environmental Protection was received in May 2017; completing project cost refinements; and securing favourable transmission service agreements with prospective counterparties. Pending achievement of key milestones, the expected in-service date for the project is late 2020.

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

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

CASH FLOW REQUIREMENTS

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

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

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

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

As at June 30, 2017, management expects consolidated fixed-term debt maturities and repayments to average approximately $730 million annually over the next five years. The combination of available credit facilities and manageable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.

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

CREDIT FACILITIES

As at June 30, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.4 billion, of which approximately $4.0 billion was unused, including $940 million unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2017 through 2022.

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

Credit Facilities As at

($ millions)
Regulated
Utilities
Corporate
and Other
June 30, 2017 December 31,
2016
Total credit facilities (1) 4,041 1,385 5,426 5,976
Credit facilities utilized:
Short-term borrowings (1) (564 ) (4 ) (568 ) (1,155 )
Long-term debt (including current portion) (2) (420 ) (359 ) (779 ) (973 )
Letters of credit outstanding (67 ) (57 ) (124 ) (119 )
Credit facilities unused (1) 2,990 965 3,955 3,729
(1) Total credit facilities and short-term borrowings as at June 30, 2017 include $207 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 June 30, 2017, credit facility borrowings classified as long-term debt included $104 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2016 - $61 million).

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

OFF-BALANCE SHEET ARRANGEMENTS

With the exception of letters of credit outstanding of $124 million as at June 30, 2017 (December 31, 2016 - $119 million), the Corporation had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.

BUSINESS RISK MANAGEMENT

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

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

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

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

CHANGES IN ACCOUNTING POLICIES

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

Simplifying the Test for Goodwill Impairment

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

FUTURE ACCOUNTING PRONOUNCEMENTS

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

Revenue from Contracts with Customers

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

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

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

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

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

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

Recognition and Measurement of Financial Assets and Financial Liabilities

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

Leases

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

Measurement of Credit Losses on Financial Instruments

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

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

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

FINANCIAL INSTRUMENTS

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

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

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

Derivative Instruments

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

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

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

CRITICAL ACCOUNTING ESTIMATES

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

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

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

Fortis and ITC

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

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

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

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 six months ended June 30, 2017 and 2016.

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

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

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

SUMMARY OF QUARTERLY RESULTS

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

Summary of Quarterly Results Net Earnings
Attributable to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
June 30, 2017 2,015 257 0.62 0.62
March 31, 2017 2,274 294 0.72 0.72
December 31, 2016 2,053 189 0.49 0.49
September 30, 2016 1,528 127 0.45 0.45
June 30, 2016 1,485 107 0.38 0.38
March 31, 2016 1,772 162 0.57 0.57
December 31, 2015 1,723 135 0.48 0.48
September 30, 2015 1,579 151 0.54 0.54

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

June 2017/June 2016: Net earnings attributable to common equity shareholders were $257 million, or $0.62 per common share, for the second quarter of 2017 compared to earnings of $107 million, or $0.38 per common share, for the second quarter of 2016. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.

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

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

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

OUTLOOK

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

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

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

OUTSTANDING SHARE DATA

As at July 27, 2017, the Corporation had issued and outstanding 417.9 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation's First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether such dividends have been declared.

The number of common shares of Fortis that would be issued if all outstanding stock options were converted as at July 27, 2017 is approximately 4.0 million.

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

FORTIS INC.
Condensed Consolidated Interim Financial Statements
For the three and six months ended June 30, 2017 and 2016
(Unaudited)
Fortis Inc.
Condensed Consolidated Interim Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
June 30,December 31,
20172016
ASSETS
Current assets
Cash and cash equivalents$231$269
Accounts receivable and other current assets 1,106 1,127
Prepaid expenses 65 85
Inventories 355 372
Regulatory assets (Note 5) 306 313
Total current assets 2,063 2,166
Other assets 451 406
Regulatory assets (Note 5) 2,617 2,620
Capital assets, net 29,419 29,337
Intangible assets, net 1,040 1,011
Goodwill 11,991 12,364
Total assets$47,581$47,904
LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings (Note 15)$568$1,155
Accounts payable and other current liabilities 1,803 1,970
Regulatory liabilities (Note 5) 455 492
Current installments of long-term debt (Note 6) 1,186 251
Current installments of capital lease and finance obligations 68 76
Total current liabilities 4,080 3,944
Other liabilities 1,182 1,279
Regulatory liabilities (Note 5) 1,439 1,691
Deferred income taxes 3,368 3,263
Long-term debt (Note 6) 19,926 20,817
Capital lease and finance obligations 442 460
Total liabilities 30,437 31,454
Commitments and Contingencies (Note 17)
Equity
Common shares (1) (Note 7) 11,435 10,762
Preference shares 1,623 1,623
Additional paid-in capital 9 12
Accumulated other comprehensive income 407 745
Retained earnings 1,840 1,455
Shareholders' equity 15,314 14,597
Non-controlling interests 1,830 1,853
Total equity 17,144 16,450
Total liabilities and equity$47,581$47,904
(1)No par value. Unlimited authorized shares; 417.9 million and 401.5 million issued and outstanding as at June 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 June 30
(in millions of Canadian dollars, except per share amounts)
Quarter EndedYear-to-Date
2017201620172016
Revenue$2,015$1,485$4,289$3,257
Expenses
Energy supply costs 524 488 1,278 1,195
Operating 571 454 1,153 928
Depreciation and amortization 298 232 595 466
Total expenses 1,393 1,174 3,026 2,589
Operating income 622 311 1,263 668
Other income, net (Note 10) 24 9 55 25
Finance charges (Note 11) 232 150 461 293
Earnings before income taxes 414 170 857 400
Income tax expense 102 28 208 70
Net earnings$312$142$649$330
Net earnings attributable to:
Non-controlling interests$38$17$65$24
Preference equity shareholders 17 18 33 37
Common equity shareholders 257 107 551 269
$312$142$649$330
Earnings per common share (Note 12)
Basic$0.62$0.38$1.34$0.95
Diluted$0.62$0.38$1.34$0.95

See accompanying Notes to Condensed Consolidated Interim Financial Statements

Fortis Inc.
Condensed Consolidated Interim Statements of Comprehensive Income (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter EndedYear-to-Date
2017201620172016
Net earnings$312 $142 $649 $330
Other comprehensive (loss) income
Unrealized foreign currency translation losses, net of hedging activities and tax (244) (18) (336) (287)
Net change in available-for-sale investment, net of tax - (1) - 2
Net change in fair value of cash flow hedges, net of tax (2) - (2) -
(246) (19) (338) (285)
Comprehensive income$66 $123 $311 $45
Comprehensive income attributable to:
Non-controlling interests$38 $17 $65 $24
Preference equity shareholders 17 18 33 37
Common equity shareholders 11 88 213 (16)
$66 $123 $311 $45

See accompanying Notes to Condensed Consolidated Interim Financial Statements

Fortis Inc.
Condensed Consolidated Interim Statements of Cash Flows (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Quarter EndedYear-to-Date
2017201620172016
Operating activities
Net earnings$312 $142 $649 $330
Adjustments to reconcile net earnings to net cash provided by operating activities:
Depreciation - capital assets 267 207 533 416
Amortization - intangible assets 24 17 48 35
Amortization - other 7 8 14 15
Deferred income tax expense 102 28 174 30
Accrued employee future benefits 9 9 10 22
Equity component of allowance for funds used during construction (Note 10) (19) (6) (36) (13)
Other (33) 33 (11) 54
Change in long-term regulatory assets and liabilities (2) (34) (9) (32)
Change in working capital (Note 13) (18) 44 (182) 74
Cash from operating activities 649 448 1,190 931
Investing activities
Capital expenditures - capital assets (654) (408) (1,323) (817)
Capital expenditures - intangible assets (65) (25) (105) (42)
Contributions in aid of construction 24 7 37 18
Proceeds on sale of assets 2 - 3 10
Business acquisitions, net of cash acquired (Note 16) - (318) - (318)
Other (48) (18) (72) (26)
Cash used in investing activities (741) (762) (1,460) (1,175)
Financing activities
Proceeds from long-term debt, net of issue costs 368 356 756 356
Repayments of long-term debt and capital lease and finance obligations (19) (69) (35) (109)
Net (repayments) borrowings under committed credit facilities (241) 421 (176) 513
Change in short-term borrowings, net 26 (243) (587) (275)
Advances from non-controlling interests 2 1 3 1
Issue of common shares to an institutional investor (Note 7) - - 500 -
Issue of common shares, net of costs and dividends reinvested 30 8 44 27
Dividends
Common shares, net of dividends reinvested (104) (70) (202) (147)
Preference shares (17) (18) (33) (37)
Subsidiary dividends paid to non-controlling interests (22) (6) (39) (15)
Other 4 - 4 -
Cash from financing activities 27 380 235 314
Effect of exchange rate changes on cash and cash equivalents (2) (2) (3) (16)
Change in cash and cash equivalents (67) 64 (38) 54
Cash and cash equivalents, beginning of period 298 232 269 242
Cash and cash equivalents, end of period$231 $296 $231 $296

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

See accompanying Notes to Condensed Consolidated Interim Financial Statements

Fortis Inc.
Condensed Consolidated Interim Statements of Changes in Equity (Unaudited)
For the periods ended June 30
(in millions of Canadian dollars)
Common
Shares
Preference
Shares
Additional
Paid-In
Capital
Accumulated
Other
Comprehensive
Income (Loss)
Retained
Earnings
Non-Controlling
Interests
Total Equity
(Note 7)
As at January 1, 2017$10,762$1,623$12 $745 $1,455 $1,853 $16,450
Net earnings - - - - 584 65 649
Other comprehensive loss - - - (338) - - (338)
Common share issues 673 - (4) - - - 669
Stock-based compensation - - 1 - - - 1
Advances from non-controlling interests - - - - - 3 3
Foreign currency translation impacts - - - - - (52) (52)
Subsidiary dividends paid to non-controlling interests - - - - - (39) (39)
Dividends declared on common shares ($0.40 per share) - - - - (166) - (166)
Dividends declared on preference shares - - - - (33) - (33)
As at June 30, 2017$11,435$1,623$9 $407 $1,840 $1,830 $17,144
As at January 1, 2016$5,867$1,820$14 $791 $1,388 $473 $10,353
Net earnings - - - - 306 24 330
Other comprehensive loss - - - (285) - - (285)
Common share issues 95 - (3) - - - 92
Stock-based compensation - - 1 - - - 1
Advances from non-controlling interests - - - - - 1 1
Foreign currency translation impacts - - - - - (8) (8)
Subsidiary dividends paid to non-controlling interests - - - - - (15) (15)
Dividends declared on common shares ($0.375 per share) - - - - (106) - (106)
Dividends declared on preference shares - - - - (37) - (37)
Adoption of new accounting policy - - - - 16 - 16
As at June 30, 2016$5,962$1,820$12 $506 $1,567 $475 $10,342

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 is consistent with the Corporation's 2016 annual audited consolidated financial statements.

REGULATED UTILITIES

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

  1. Regulated Electric Transmission Utility - United States: Comprised of ITC Holdings Corp. 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 16).

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

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

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

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

NON-REGULATED - ENERGY INFRASTRUCTURE

Non-Regulated - Energy Infrastructure is primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility ("Aitken Creek") in British Columbia. Aitken Creek was acquired by Fortis in April 2016 (Note 16).

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 unaudited condensed consolidated interim financial statements for the three and six months ended June 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, under which comparative periods would be restated, and the cumulative impact of applying the standard would be recognized as at January 1, 2017, the earliest period presented; and (ii) the modified retrospective method, under which comparative periods would not be restated and the cumulative impact of applying the standard would be recognized at the date of initial adoption, January 1, 2018. The Corporation expects to use the modified retrospective approach; however, it continues to monitor interpretative issues that remain outstanding. Any significant developments in interpretative issues could change the Corporation's expected method of adoption.

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

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

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

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

Recognition and Measurement of Financial Assets and Financial Liabilities

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

Leases

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

Measurement of Credit Losses on Financial Instruments

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

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

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

4. SEGMENTED INFORMATION

Information by reportable segment is as follows:

REGULATEDNON-REGULATED
United StatesCanada
Quarter Ended June 30, 2017
($ millions)

ITC
UNS
Energy
Central
Hudson
FortisBC
Energy
Fortis
Alberta
FortisBC
Electric
Eastern
Canadian
Caribbean
Electric

Total
Energy
Infra
structure
Corporate
and Other
Intersegment
eliminations

Total
Revenue40855220622714885251801,95759 1 (2)2,015
Energy supply costs-1756472-2115835525- - (1)524
Operating expenses115150100724821331355210 10 (1)571
Depreciation and amortization56671750461524142898 1 - 298
Operating income (loss)23716025335428361859141 (10)- 622
Other income (expenses), net113251-1-23- 2 (1)24
Finance charges672611292491451851 47 (1)232
Income tax expense (recovery)674863-35-1322 (32)- 102
Net earnings (loss)114891063116181329738 (23)- 312
Non-controlling interests21------42513 - - 38
Preference share dividends---------- 17 - 17
Net earnings (loss) attributable to common equity shareholders9389106311618927225 (40)- 257
Goodwill7,9601,7935859132272356718411,96427 - - 11,991
Identifiable assets9,9256,9032,5045,2624,0141,9202,3321,14834,0081,554 93 (65)35,590
Total assets17,8858,6963,0896,1754,2412,1552,3991,33245,9721,581 93 (65)47,581
Gross capital expenditures244121531031022536327163 - - 719
Quarter Ended June 30, 2016
($ millions)
Revenue-49018520114483245711,41967 3 (4)1,485
Energy supply costs-1765241-211542947316 - (1)488
Operating expenses-1468969482134124199 28 (2)454
Depreciation and amortization-651550441423132247 1 - 232
Operating income (loss)-10329415227341730335 (26)(1)311
Other income (expenses), net-214--119(1)1 - 9
Finance charges-2510332291431161 34 (1)150
Income tax expense (recovery)-2484-35-441 (17)- 28
Net earnings (loss)-561283015161515232 (42)- 142
Non-controlling interests-------4413 - - 17
Preference share dividends---------- 18 - 18
Net earnings (loss) attributable to common equity shareholders-561283015161114819 (60)- 107
Goodwill-1,784582913227235671833,99127 - - 4,018
Identifiable assets-6,5622,4305,0633,7171,8742,2471,06622,9591,473 234 (61)24,605
Total assets-8,3463,0125,9763,9442,1092,3141,24926,9501,500 234 (61)28,623
Gross capital expenditures-986079871935424205 8 - 433
REGULATEDNON-REGULATED
United StatesCanada
Year-to-Date June 30, 2017
($ millions)

ITC
UNS
Energy
Central
Hudson
FortisBC
Energy
Fortis
Alberta
FortisBC
Electric
Eastern
Canadian
Caribbean
Electric

Total
Energy
Infra
structure
Corporate
and Other
Intersegment
eliminations

Total
Revenue8031,0104646762951985831504,1791151 (6)4,289
Energy supply costs-346149254-67394681,2781- (1)1,278
Operating expenses2272972101441004468231,1132322 (5)1,153
Depreciation and amortization1101333410095314728578161 - 595
Operating income (loss)466234711781005674311,21075(22)- 1,263
Other income (expenses), net2115492-1254-2 (1)55
Finance charges13052215846182810363297 (1)461
Income tax expense (recovery)132672126-711-2647(63)- 208
Net earnings (loss)225130331035631362363766(54)- 649
Non-controlling interests41------64718- - 65
Preference share dividends----------33 - 33
Net earnings (loss) attributable to common equity shareholders184130331035631361759048(87)- 551
Goodwill7,9601,7935859132272356718411,96427- - 11,991
Identifiable assets9,9256,9032,5045,2624,0141,9202,3321,14834,0081,55493 (65)35,590
Total assets17,8858,6963,0896,1754,2412,1552,3991,33245,9721,58193 (65)47,581
Gross capital expenditures5122481031971954663571,4217- - 1,428
Year-to-Date June 30, 2016
($ millions)
Revenue-9304346072861875741463,164955 (7)3,257
Energy supply costs-356133175-61388661,17917- (1)1,195
Operating expenses-299193140964369248641653 (5)928
Depreciation and amortization-1323110089284526451132 - 466
Operating income (loss)-1437719210155723067049(50)(1)668
Other income (expenses), net-4272-142014 - 25
Finance charges-5120644219286230262 (1)293
Income tax expense (recovery)-282335-611-1031(34)- 70
Net earnings (loss)-68361006130342835747(74)- 330
Non-controlling interests-------7717- - 24
Preference share dividends----------37 - 37
Net earnings (loss) attributable to common equity shareholders-68361006130342135030(111)- 269
Goodwill-1,784582913227235671833,99127- - 4,018
Identifiable assets-6,5622,4305,0633,7171,8742,2471,06622,9591,473234 (61)24,605
Total assets-8,3463,0125,9763,9442,1092,3141,24926,9501,500234 (61)28,623
Gross capital expenditures-2181181661663863648331610 - 859

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 six months ended June 30, 2017 and 2016.

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

Quarter EndedYear-to-Date
June 30June 30
($ millions)2017201620172016
Sale of capacity from Waneta Expansion to FortisBC Electric (Note 18)331918
Sale of energy from Belize Electric Company Limited to Belize Electricity761414
Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy (Note 18)55135

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

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
June 30, December 31,
($ millions)2017 2016
Regulatory assets
Deferred income taxes1,267 1,260
Employee future benefits545 576
Deferred energy management costs194 178
Rate stabilization accounts158 183
Deferred lease costs100 97
Deferred operating overhead costs85 78
Manufactured gas plant site remediation deferral80 107
Navajo retirement costs (1)50 -
Natural gas for transportation incentives34 40
Other regulatory assets410 414
Total regulatory assets2,923 2,933
Less: current portion(306)(313)
Long-term regulatory assets2,617 2,620
As at
June 30, December 31,
($ millions)2017 2016
Regulatory liabilities
Non-asset retirement obligation removal cost provision1,098 1,194
Rate stabilization accounts205 230
Return on equity refund liability184 346
Energy efficiency liability65 49
Electric and gas moderator account60 71
Renewable energy surcharge59 53
Employee future benefits48 42
Other regulatory liabilities175 198
Total regulatory liabilities1,894 2,183
Less: current portion(455)(492)
Long-term regulatory liabilities1,439 1,691
(1)Navajo 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. TEP is currently recovering Navajo retirement costs through to 2030. As a result of the planned early retirement of Navajo, the net book value and other related retirement costs of $50 million (US$38 million) were reclassified from capital assets to regulatory assets as at June 30, 2017.

6. LONG-TERM DEBT

As at
June 30, December 31,
($ millions)2017 2016
Long-term debt20,478 20,246
Long-term classification of credit facility borrowings (Note 15)779 973
Total long-term debt (Note 14)21,257 21,219
Less: Deferred financing costs and debt discounts(145)(151)
Less: Current installments of long-term debt(1,186)(251)
19,926 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 June 30, 2017, borrowings under the term loan credit agreements were US$200 million ($268 million) and US$50 million ($67 million), respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes.

In April 2017 ITC issued 30-year US$200 million ($268 million) 4.16% secured first mortgage bonds. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.

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

In June 2017 Newfoundland Power issued 40-year $75 million 3.82% first mortgage sinking fund bonds. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.

7. COMMON SHARES

Common shares issued during the period were as follows.

Quarter EndedYear-to-Date
June 30, 2017June 30, 2017
Number Number
of SharesAmountof SharesAmount
(in thousands)($ millions)(in thousands)($ millions)
Balance, beginning of period415,57111,340401,48610,762
Private Offering--12,195500
Dividend Reinvestment Plan1,451632,955126
Stock Option Plans7192695534
Employee Share Purchase Plan137627712
Consumer Share Purchase Plan7-151
Conversion of Convertible Debentures--2-
Balance, end of period417,88511,435417,88511,435

Private Offering

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

8. STOCK-BASED COMPENSATION PLANS

For the three and six months ended June 30, 2017, stock-based compensation expense of approximately $12 million and $24 million, respectively was recognized ($6 million and $15 million for the three and six months ended June 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.

Performance Share Unit Plans

In the first half of 2017, the Corporation granted 728,552 Performance Share Units ("PSUs"), under the 2015 PSU Plan, 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 June 30, 2017, the estimated payout percentages for the grants under the 2015 PSU Plan ranged from 97% to 109%.

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, under the 2013 PSU Plan. 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

In the first half of 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.

9. EMPLOYEE FUTURE BENEFITS

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

Quarter Ended June 30
Defined Benefit
Pension Plans
OPEB Plans
($ millions)2017 2016 2017 2016
Components of net benefit cost:
Service costs20 16 7 3
Interest costs29 28 7 5
Expected return on plan assets(38)(35)(4)(3)
Amortization of actuarial losses12 11 1 1
Amortization of past service credits/plan amendments- 1 (3)(3)
Regulatory adjustments- 1 1 3
Net benefit cost23 22 9 6
Year-to-Date June 30
Defined Benefit
Pension Plans
OPEB Plans
($ millions)2017 2016 2017 2016
Components of net benefit cost:
Service costs39 32 14 7
Interest costs58 55 13 11
Expected return on plan assets(76)(71)(7)(6)
Amortization of actuarial losses23 23 1 1
Amortization of past service credits/plan amendments- 1 (6)(6)
Regulatory adjustments- 3 2 5
Net benefit cost44 43 17 12

For the three and six months ended June 30, 2017, the Corporation expensed $9 million and $20 million, respectively ($7 million and $15 million for the three and six months ended June 30, 2016, respectively) related to defined contribution pension plans.

10. OTHER INCOME, NET

Quarter EndedYear-to-Date
June 30June 30
($ millions)2017201620172016
Equity component of allowance for funds used during construction ("AFUDC")1963613
Interest income3274
Equity income - Belize Electricity-113
Other2-115
2495525

11. FINANCE CHARGES

Quarter EndedYear-to-Date
June 30June 30
($ millions)2017 2016 2017 2016
Interest:
Long-term debt and capital lease and finance obligations238 144 471 289
Short-term borrowings3 2 8 4
Acquisition credit facilities- 10 - 14
Debt component of AFUDC(9)(6)(18)(14)
232 150 461 293

12. EARNINGS PER COMMON SHARE

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

EPS was as follows.

Quarter Ended June 30
20172016
Net EarningsWeighted Net EarningsWeighted
to CommonAverage to CommonAverage
ShareholdersShares ShareholdersShares
($ millions)(# millions)EPS($ millions)(# millions)EPS
Basic EPS257416.8$0.62107 283.7 $0.38
Effect of potential dilutive securities:
Stock Options-0.6 - 0.6
Preference Shares-- 3 5.6
257417.4 110 289.9
Deduct anti-dilutive impacts:
Preference Shares-- (3)(5.6)
Diluted EPS257417.4$0.62107 284.3 $0.38
Year-to-Date June 30
20172016
Net EarningsWeighted Net EarningsWeighted
to CommonAverage to CommonAverage
ShareholdersShares ShareholdersShares
($ millions)(# millions)EPS($ millions)(# millions)EPS
Basic EPS551411.5$1.34269283.0$0.95
Effect of potential dilutive securities:
Stock Options-0.6 -0.6
Preference Shares-- 55.6
Diluted EPS551412.1$1.34274289.2$0.95

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

Quarter EndedYear-to-Date
June 30June 30
($ millions)2017 2016 2017 2016
Change in working capital:
Accounts receivable and other current assets19 21 6 84
Prepaid expenses10 10 11 (7)
Inventories(40)(6)11 45
Regulatory assets - current portion10 (7)(13)-
Accounts payable and other current liabilities(15)5 (21)(64)
Regulatory liabilities - current portion(2)21 (176)16
(18)44 (182)74
Non-cash investing and financing activities:
Accrued capital expenditures309 131 309 131
Common share dividends reinvested63 36 125 65
Transfer of deposit on business acquisition (Note 16)- 38 - 38
Contributions in aid of construction15 8 15 8
Exercise of stock options into common shares3 1 4 3

14. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS

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

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

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

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

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

As at
Fair valueJune 30,December 31,
($ millions)hierarchy2017 2016
Assets
Energy contracts subject to regulatory deferral (1) (2) (3)Levels 1/2/37 19
Energy contracts not subject to regulatory deferral (1) (2) (4)Levels 2/310 3
Interest rate swaps - cash flow hedges (5)Level 29 11
Other investments (6)Level 185 69
Total gross assets 111 102
Less: Counterparty netting not offset on the balance sheet (7) (6)(9)
Total net assets 105 93
Liabilities
Energy contracts subject to regulatory deferral (1) (2) (8)Levels 2/334 26
Energy contracts not subject to regulatory deferral (1)Level 2- 9
Interest rate swaps - cash flow hedges (5)Level 26 3
Total gross liabilities 40 38
Less: Counterparty netting not offset on the balance sheet (7) (6)(9)
Total net liabilities 34 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 June 30, 2017, includes - $5 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 June 30, 2017, includes - $4 million - level 2 and $6 million - level 3 (December 31, 2016 - $3 million - level 3)
(5)The fair value of the Corporation's interest rate swaps is recognized in accounts receivable and other current assets, accounts payable and other current liabilities and long-term other liabilities.
(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 June 30, 2017, includes $22 million - level 2 and $12 million - level 3 (December 31, 2016 - $21 million - level 2 and $5 million - level 3).

Derivative Instruments

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

Energy Contracts Subject to Regulatory Deferral

UNS Energy holds electricity power purchase contracts and gas swap contracts to reduce its exposure to energy price risk associated with purchased power and gas requirements. UNS Energy primarily applies the market approach for fair value measurements using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission 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 June 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 June 30, 2017, unrealized losses of $28 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 Swaps - Cash Flow Hedges

As at June 30, 2017, ITC held forward-starting interest rate swaps, effective December 2017 and January 2018, with notional amounts totalling $325 million and 10-year original terms. The agreements include a mandatory early termination provision and will be terminated no later than the effective dates. The interest rate swaps manage the interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the refinancing of maturing $500 million long-term debt due in January 2018.

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

The unrealized gains and losses on cash flow hedges are recognized in other comprehensive income and reclassified to earnings as a component of interest expense over the life of the hedged debt. The loss expected to be reclassified to earnings within the next twelve months is estimated to be approximately $4 million. Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows.

Volume of Derivative Activity

As at June 30, 2017, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.

Volume(1)Maturity
(year)
Contracts
(#)
20172018201920202021There-after
Energy contracts subject to regulatory deferral:
Electricity swap contracts (GWh)20197561742438---
Electricity power purchase contracts (GWh)201832903154----
Gas swap contracts (PJ)20201152232142--
Gas supply contract premiums (PJ)202475565531282243
Energy contracts not subject to regulatory deferral:
Wholesale trading contracts (GWh)2018181,9991,787----
Gas swap contracts (PJ)20186266----
(1)GWh means gigawatt hours and PJ means petajoules.

Financial Instruments Not Carried At Fair Value

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

As at
June 30, 2017December 31, 2016
($ millions)Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
Long-term debt, including current portion (Note 6) (1)21,25723,13721,21922,523
Waneta Partnership promissory note (2)61625961
(1)Includes $4,074 million (December 31, 2016 - $1,673 million) unsecured debentures and notes, and credit facility borrowings valued using Level 1 inputs. All other long-term debt is valued using Level 2 inputs.
(2)Included in long-term other liabilities on the consolidated balance sheet

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

15. FINANCIAL RISK MANAGEMENT

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

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

Credit Risk

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

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

FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at June 30, 2017, FortisAlberta's gross credit risk exposure was approximately $129 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $1 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.

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

Liquidity Risk

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

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

The Corporation's committed corporate credit facility is used for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at June 30, 2017, over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $730 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 June 30, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.4 billion, of which approximately $4.0 billion was unused, including $940 million unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2017 through 2022.

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

As at
Regulated Corporate June 30, December 31,
($ millions)Utilities and Other 2017 2016
Total credit facilities (1)4,041 1,385 5,426 5,976
Credit facilities utilized:
Short-term borrowings (1) (2)(564)(4)(568)(1,155)
Long-term debt (Note 6) (3)(420)(359)(779)(973)
Letters of credit outstanding(67)(57)(124)(119)
Credit facilities unused (1)2,990 965 3,955 3,729
(1)Total credit facilities and short-term borrowings as at June 30, 2017 include $207 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 June 30, 2017 (December 31, 2016 - 1.7%).
(3)As at June 30, 2017, credit facility borrowings classified as long-term debt included $104 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2016 - $61 million). The weighted average interest rate on credit facility borrowings classified as long-term debt was approximately 2.3% as at June 30, 2017 (December 31, 2016 - 1.8%).

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

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 June 30, 2017, the Corporation's corporately issued US$3,440 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 June 30, 2017, the Corporation had approximately US$7,522 million (December 31, 2016 - US$7,250 million) in foreign net investments that were unhedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as effective hedges are recorded on the consolidated balance sheet in accumulated other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which gains and losses are also recorded on the consolidated balance sheet in accumulated other comprehensive income.

As a result of the acquisition of ITC, consolidated earnings and cash flows of Fortis are impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, it is estimated that a 5 cent increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.30 as at June 30, 2017 would increase or decrease earnings per common share of Fortis by approximately 7 cents. Management will continue to hedge future exchange rate fluctuations related to the Corporation's foreign net investments and US dollar-denominated earnings streams, where appropriate, through future US dollar-denominated borrowings, and will continue to monitor the Corporation's exposure to foreign currency fluctuations on a regular basis.

Interest Rate Risk

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

Commodity Price Risk

UNS Energy is exposed to commodity price risk associated with changes in the market price of gas, purchased power and coal. Central Hudson is exposed to commodity price risk associated with changes in the market price of electricity and gas. FortisBC Energy 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 14).

16. BUSINESS ACQUISITIONS

2017

Pending Acquisition of an Interest in Waneta Dam

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

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 consideration4,684
Cash consideration4,658
Total consideration9,342
Purchase consideration for 80.1% of ITC common shares7,721
19.9% minority shareholder investment and shareholder note1,621
9,342
Fair value assigned to net assets:
Current assets319
Long-term regulatory assets319
Capital assets, net8,345
Intangible assets, net392
Other long-term assets71
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 equivalents134
Fair value of net assets acquired1,236
Goodwill8,106

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 revenue7,995
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 13).

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.

17. COMMITMENTS AND CONTINGENCIES

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

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

Central Hudson

Prior to and after its acquisition by Fortis, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,365 asbestos cases have been raised, 1,175 remained pending as at June 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 consolidated financial statements.

FHI

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

Fortis and ITC

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

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

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

18. 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 six months ended June 30, 2016 by $8 million and $23 million, respectively (Note 4).

Contact Information

  • Ms. Janet Craig
    Vice President, Investor Relations
    709.737.2900