ST. JOHN'S, NEWFOUNDLAND AND LABRADOR - Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS)(NYSE:FTS), a leader in the North American regulated electric and gas utility industry, released its third quarter results today.
"Strong third quarter results continue to demonstrate the benefit of the acquisition of electric transmission company, ITC Holdings Corp., and the reasonable outcome in our first rate case in Arizona," said Barry Perry, President and Chief Executive Officer, Fortis.
Reported Net Earnings
The Corporation reported third quarter net earnings attributable to common equity shareholders of $278 million, or $0.66 per common share, compared to $127 million, or $0.45 per common share, for the same period in 2016. On a year-to-date basis, net earnings attributable to common equity shareholders were $829 million, or $2.00 per common share, compared to $396 million, or $1.40 per common share, for the same period in 2016.
- Earnings per common share ("EPS") for the quarter was favourably impacted by earnings associated with the acquisition of ITC, the receipt of a $24 million break fee, net of transaction costs and tax, associated with the termination of the Waneta Dam acquisition, and higher earnings from the Aitken Creek natural gas storage facility, driven by unrealized gains on mark-to-market of derivatives.
- Also contributing to the increase in the third quarter results compared to last year was the impact of the rate case settlement at UNS Energy, lower Corporate and Other expenses, primarily due to acquisition-related transaction costs associated with ITC recognized in the third quarter of 2016, and higher earnings from FortisAlberta, partially offset by the favourable impact of the settlement of Springerville Unit 1 matters at UNS Energy recognized in the third quarter of 2016.
Adjusted Net Earnings1
On an adjusted basis, third quarter net earnings attributable to common equity shareholders were $254 million, or $0.61 per common share, an increase of $0.07 per common share over the same period in 2016. On a year-to-date basis, adjusted net earnings attributable to common equity shareholders were $794 million, or $1.92 per common share, an increase of $0.26 per common share over the same period in 2016.
- ITC continues to perform consistent with expectations, delivering segmented net earnings of $89 million for the quarter. After considering the issuance of common shares and finance charges related to the acquisition, ITC had a $0.03 accretive impact on adjusted EPS for the quarter.
- Aitken Creek contributed an additional $0.03 to adjusted EPS quarter over quarter, driven by unrealized gains on the mark-to-market of derivatives.
- Also contributing to the increase in adjusted EPS quarter over quarter was the impact of the rate case settlement at UNS Energy and higher earnings from FortisAlberta, partially offset by the higher number of common shares outstanding associated with the Corporation's dividend reinvestment and share plans and unfavourable foreign exchange associated with the translation of US dollar-denominated earnings.
Hurricane Irma
In September Hurricane Irma damaged the transmission and distribution systems on the Turks and Caicos Islands. The Corporation responded quickly and currently 99% of electricity service has been restored to customers who can receive it. The local workforce of Fortis Turks and Caicos, along with crews from the Corporation's other utilities and contracted employees, continue to work hard to finish the task of reconnecting customers.
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Non-US GAAP Measures |
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Fortis uses financial measures that do not have a standardized meaning under generally accepted accounting principles in the United States of America ("US GAAP") and may not be comparable to similar measures presented by other entities. Fortis calculated the non-US GAAP measures by adjusting certain US GAAP measures for specific items that impact comparability but which the Corporation does not consider part of normal, ongoing operations. Refer to the Financial Highlights section of the Corporation's Management Discussion and Analysis for further discussion of these items. |
Capital expenditure plan on track and supported by strong cash flow
Capital expenditures for the nine months ended September 30, 2017 were $2.1 billion and the Corporation's consolidated capital expenditure plan of approximately $3.1 billion for 2017 remains on track.
Cash flow from operating activities totalled $2.0 billion for the nine months ended September 30, 2017, an increase of 41% over the same period in 2016. The increase reflects higher earnings, driven by ITC and UNS Energy, partially offset by timing differences in working capital.
Execution of growth strategy
The Corporation's capital expenditure program continues to address the energy infrastructure needs of customers, while modernizing energy networks to address the changes occurring in the utility industry. The Corporation's five-year capital expenditure program from 2018 through 2022 is expected to be approximately $14.5 billion, up $1.5 billion from the prior year's plan.
The five-year capital expenditure program now includes a natural gas pipeline expansion ("Eagle Mountain Woodfibre Gas Pipeline Project") and a multi-year Pipeline Integrity Management Program at FortisBC Energy, and the expected addition of 200 megawatts ("MW") of flexible generation resources and the 550 MW Gila River Generating Unit 2 at UNS Energy.
The Eagle Mountain Woodfibre Gas Pipeline Project, estimated at approximately $350 million, includes a pipeline expansion to a proposed liquefied natural gas ("LNG") site in Squamish, British Columbia. The project has received a number of approvals and remains contingent on Woodfibre LNG Limited proceeding with its LNG export facility. The multi-year Pipeline Integrity Management Program, estimated at approximately $300 million, is focused on improving pipeline safety and the integrity of the high-pressure transmission system, including pipeline modifications and looping.
The 200 MW of flexible generation resources, which will consist of 10 natural gas-fired reciprocating engines, is estimated at $230 million (US$180 million) with expected in-service dates between 2019 and 2020. The engines will provide ramping and peaking capabilities, replace aging, less efficient steam turbines and will facilitate the addition of renewable generating sources to the grid. The expected addition of the 550 MW natural gas-fired Gila River Generating Unit 2, estimated at $210 million (US$165 million), will assist with the replacement of retiring coal-fired generation facilities. This project will include an initial tolling agreement with a purchase option expected to be exercised in late 2019.
The Corporation continues to pursue additional investment opportunities within existing service territories. One such opportunity at ITC, not included in the five-year capital expenditure program, is the Lake Erie Connector project, which is a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line that would provide the first direct link between the markets of the Ontario Independent Electricity System Operator and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets. In October ITC received permits from the U.S. Army Corps of Engineers, which completes the project's major application process in the United States and Canada. Pending achievement of remaining milestones, the expected in-service date for the project is late 2021.
"After a very strategic and successful expansion into the United States, the Corporation is now focused on sustainable investment in its existing utilities. The opportunities that we are pursuing will enhance our ability to serve customers safely and reliably, grow our rate base, and support our 6% average annual dividend growth target," concluded Mr. Perry.
Outlook
The Corporation's results for 2017 will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital expenditure plan, the balance and strength of its diversified portfolio of utility businesses, as well as growth opportunities within its service territories.
Over the five-year period from 2018 through 2022, the Corporation's capital expenditure program is expected to total approximately $14.5 billion, up $1.5 billion from the prior year's plan and increasing rate base to almost $32 billion by 2022. The five-year capital expenditure program is driven by projects that improve the transmission grid, address natural gas system capacity and gas line network integrity, increase cyber protection and allow the grid to deliver cleaner energy. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends.
In October the Corporation announced a quarterly dividend increase of 6.25%, effective with the December 1 payment, translating into an annualized dividend of $1.70. This marks 44 consecutive years of annual common share dividend increases. Fortis has extended its guidance for targeted average annual dividend growth of approximately 6% through to 2022.
About Fortis
Fortis is a leader in the North American regulated electric and gas utility industry with total assets of approximately $47 billion as of September 30, 2017. More than 8,000 of the Corporation's employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.
Fortis shares are listed on the TSX and NYSE and trade under the symbol FTS. Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov.
Forward-Looking Information
Fortis includes "forward-looking information" in this media release within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995 (collectively referred to as "forward-looking information"). Forward-looking information included in this media release reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which includes, without limitation: the Corporation's forecast consolidated capital spending for 2017 and the five-year period from 2018 through 2022; the nature, timing and expected costs of certain capital projects including, without limitation, the FortisBC Eagle Mountain Woodfibre Gas Pipeline Project and UNS Energy flexible generation resource investment and combined cycle generation purchase; additional opportunities beyond the base capital plan including the Lake Erie Connector; the expectation that the Corporation's 2017 results will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy; the Corporation's consolidated forecast rate base for 2022; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; and targeted average annual dividend growth through 2022.
Forward-looking information involves significant risk, uncertainties and assumptions. Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information. These factors or assumptions are subject to inherent risks and uncertainties surrounding future expectations generally, including those identified from time to time in the forward-looking information. Such risk factors or assumptions include, but are not limited to: reasonable decisions by utility regulators and the expectation of regulatory stability; the implementation of the Corporation's five-year capital plan; no material capital project and financing cost overrun related to any of the Corporation's capital projects; sufficient human resources to deliver service and execute the capital program; the realization of additional opportunities; fluctuating foreign exchange; and the Board exercising its discretion to declare dividends, taking into account the business performance and financial condition of the Corporation. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. For additional information with respect to certain of these risks or factors, reference should be made to the continuous disclosure materials filed from time to time by the Corporation with Canadian securities regulatory authorities and the Securities and Exchange Commission. Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.
| Teleconference to Discuss Third Quarter 2017 Results |
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| A teleconference and webcast will be held on November 3 at 8:30 a.m. (Eastern). Barry Perry, President and Chief Executive Officer, and Karl Smith, Executive Vice President, Chief Financial Officer, will discuss the Corporation's third quarter 2017 results. |
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| 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. |
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| A live and archived audio webcast of the teleconference will be available on the Corporation's website, http://www.fortisinc.com/. |
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| A replay of the conference will be available two hours after the conclusion of the call until December 3, 2017. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 92431300. |
Interim Management Discussion and Analysis
For the three and nine months ended September 30, 2017
Dated November 2, 2017
| TABLE OF CONTENTS |
| Forward-Looking Information |
1 |
|
|
Summary of Consolidated Cash Flows |
17 |
| Corporate Overview |
3 |
|
|
Contractual Obligations |
19 |
| Significant Items |
3 |
|
|
Capital Structure |
19 |
| Financial Highlights |
4 |
|
|
Credit Ratings |
19 |
| Segmented Results of Operations |
7 |
|
|
Capital Expenditure Program |
20 |
| Regulated Electric & Gas Utilities - United States |
8 |
|
|
Additional Investment Opportunities |
21 |
| |
ITC |
8 |
|
|
Cash Flow Requirements |
22 |
| |
UNS Energy |
8 |
|
|
Credit Facilities |
23 |
| |
Central Hudson |
9 |
|
Off-Balance Sheet Arrangements |
24 |
| Regulated Gas Utility - Canadian |
10 |
|
Business Risk Management |
24 |
| |
FortisBC Energy |
10 |
|
Changes in Accounting Policies |
24 |
| Regulated Electric Utilities - Canadian |
10 |
|
Future Accounting Pronouncements |
24 |
| |
FortisAlberta |
10 |
|
Financial Instruments |
26 |
| |
FortisBC Electric |
11 |
|
Critical Accounting Estimates |
27 |
| |
Eastern Canadian Electric Utilities |
11 |
|
Related-Party and Inter-Company Transactions |
28 |
| Regulated Electric Utilities - Caribbean |
12 |
|
Summary of Quarterly Results |
29 |
| Non-Regulated - Energy Infrastructure |
13 |
|
Outlook |
30 |
| Corporate and Other |
13 |
|
Outstanding Share Data |
30 |
| Regulatory Highlights |
14 |
|
Condensed Consolidated Interim Financial Statements (Unaudited) |
F-1 |
| Consolidated Financial Position |
16 |
| Liquidity and Capital Resources |
17 |
|
|
|
FORWARD-LOOKING INFORMATION
The following Fortis Inc. ("Fortis" or the "Corporation") Management Discussion and Analysis ("MD&A") has been prepared in accordance with National Instrument 51-102 - Continuous Disclosure Obligations. The MD&A should be read in conjunction with the unaudited condensed consolidated interim financial statements and notes thereto for the three and nine months ended September 30, 2017 and the MD&A and audited consolidated financial statements for the year ended December 31, 2016 included in the Corporation's 2016 Annual Report. Financial information contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") and is presented in Canadian dollars unless otherwise specified.
Fortis includes "forward-looking information" in the MD&A within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, collectively referred to as "forward-looking information". Forward-looking information included in the MD&A reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which include, without limitation: the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions;
the Corporation's forecast gross consolidated and segmented capital expenditures for 2017 and for the period from 2018 through 2022; the nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas ("LNG") facility and the Eagle Mountain Woodfibre Gas Pipeline Project at FortisBC, flexible generation resource investment and combined cycle generation purchase at UNS Energy and additional opportunities beyond the base capital expenditure program including the Lake Erie Connector Project and the Wataynikaneyap Project; the expectation that subsidiary operating expenses and interest costs will be paid out of subsidiary operating cash flows; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis; the expectation that maintaining the targeted capital structure of the Corporation's regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; the expectation that cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions will be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2017; the intent of management to refinance certain borrowings under Corporation's and subsidiaries' long-term committed credit facilities with long-term permanent financing; the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements; the expectation that long-term debt will not be settled prior to maturity; the expectation that any liability from current legal proceedings and claims will not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows; the expectation that the Corporation's 2017 results will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy; the Corporation's consolidated forecast rate base for 2022; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends, and targeted average annual dividend growth through 2022.
Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; no material capital project and financing cost overrun related to any of the Corporation's capital projects; the realization of additional opportunities; the Board of Directors exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; no significant changes in tax laws; no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel, coal and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans, environmental laws and regulations that may materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the continued tax deferred treatment of earnings from the Corporation's foreign operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital expenditure program.
Forward-looking information involves significant risks, uncertainties and assumptions. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risk Management" in this MD&A and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2017 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation's utilities; uncertainty of the impact a continuation of a low interest rate environment may have on the allowed rate of return on common shareholders' equity at the Corporation's regulated utilities; the impact of fluctuations in foreign exchange rates; uncertainty related to proposed tax reform in the United States; risk associated with the impacts of less favourable economic conditions on the Corporation's results of operations; risk that the expected benefits of the acquisition of ITC may fail to materialize, or may not occur within the time periods anticipated; risk associated with the Corporation's ability to comply with Section 404(a) of the Sarbanes-Oxley Act of 2002 and the related rules of the U.S. Securities and Exchange Commission and the Public Company Accounting Oversight Board; risk associated with the completion of the Corporation's 2017 capital expenditures plan, including completion of major capital projects in the timelines anticipated and at the expected amounts; and uncertainty in the timing and access to capital markets to arrange sufficient and cost-effective financing to finance, among other things, capital expenditures and the repayment of maturing debt.
All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Fortis disclaims any intention or obligation to update or revise any forward-looking information, whether as a result of new information, future events or otherwise.
CORPORATE OVERVIEW
Fortis is a leader in the North American regulated electric and gas utility business, with total assets of approximately $47 billion and fiscal 2016 revenue of $6.8 billion. More than 8,000 employees of the Corporation serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.
Year-to-date September 30, 2017, the Corporation's electricity systems met a combined peak demand of 31,917 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,567 terajoules. For additional information on the Corporation's operations and business segments, refer to Note 1 to the Corporation's unaudited condensed consolidated interim financial statements for the three and nine months ended September 30, 2017 and to the "Corporate Overview" section of the 2016 Annual MD&A.
SIGNIFICANT ITEMS
Terminated Acquisition of Interest in Waneta Dam: In May 2017 Fortis had entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia. In August 2017 BC Hydro exercised its right of first offer to acquire Teck's two-thirds interest in the Waneta Dam and the purchase agreement between Fortis and Teck was terminated, resulting in the payment of a $28 million break fee ($24 million net of related transaction costs and tax) to Fortis.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of long-term profitable growth with the primary measure of financial performance being earnings per common share. Key financial highlights for the third quarter and year-to-date periods ended September 30, 2017 and 2016 are provided in the following table.
| Consolidated Financial Highlights |
| Periods Ended September 30 |
Quarter |
Year-to-Date |
| ($ millions, except for common share data) |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Revenue |
1,901 |
|
1,528 |
|
373 |
|
6,190 |
|
4,785 |
|
1,405 |
|
| Energy Supply Costs |
478 |
|
503 |
|
(25 |
) |
1,756 |
|
1,698 |
|
58 |
|
| Operating Expenses |
504 |
|
439 |
|
65 |
|
1,657 |
|
1,367 |
|
290 |
|
| Depreciation and Amortization |
290 |
|
234 |
|
56 |
|
885 |
|
700 |
|
185 |
|
| Other Income, Net |
23 |
|
10 |
|
13 |
|
78 |
|
35 |
|
43 |
|
| Finance Charges |
225 |
|
164 |
|
61 |
|
686 |
|
457 |
|
229 |
|
| Income Tax Expense |
106 |
|
40 |
|
66 |
|
314 |
|
110 |
|
204 |
|
| Net Earnings |
321 |
|
158 |
|
163 |
|
970 |
|
488 |
|
482 |
|
| Net Earnings Attributable to: |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Non-Controlling Interests |
27 |
|
9 |
|
18 |
|
92 |
|
33 |
|
59 |
|
| |
Preference Equity Shareholders |
16 |
|
22 |
|
(6 |
) |
49 |
|
59 |
|
(10 |
) |
| |
Common Equity Shareholders |
278 |
|
127 |
|
151 |
|
829 |
|
396 |
|
433 |
|
| Net Earnings |
321 |
|
158 |
|
163 |
|
970 |
|
488 |
|
482 |
|
| Earnings per Common Share |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Basic ($) |
0.66 |
|
0.45 |
|
0.21 |
|
2.00 |
|
1.40 |
|
0.60 |
|
| |
Diluted ($) |
0.66 |
|
0.45 |
|
0.21 |
|
2.00 |
|
1.39 |
|
0.61 |
|
| Weighted Average Number of Common Shares Outstanding (# millions) |
418.6 |
|
285.0 |
|
133.6 |
|
413.9 |
|
283.7 |
|
130.2 |
|
| Cash Flow from Operating Activities |
800 |
|
478 |
|
322 |
|
1,990 |
|
1,409 |
|
581 |
|
Revenue
The increase in revenue for the quarter and year to date was driven by the acquisition of ITC in October 2016, higher revenue at UNS Energy, and the flow through in customer rates of higher overall energy supply costs, partially offset by unfavourable foreign exchange associated with the translation of US dollar-denominated revenue. The increase in revenue at UNS Energy was mainly due to the impact of the rate case settlement, United States Federal Energy Regulatory Commission ("FERC") ordered transmission refunds recognized in the third quarter and year-to-date 2016 of $11 million ($7 million after tax) and $29 million ($18 million after tax), respectively, and higher short-term wholesale sales. The increase in revenue at UNS Energy was partially offset by $17 million ($10 million after tax) in revenue related to the settlement of Springerville Unit 1 matters recognized in the third quarter of 2016.
Energy Supply Costs
The decrease in energy supply costs for the quarter was primarily due to favourable foreign exchange associated with the translation of US dollar-denominated energy supply costs, partially offset by higher overall commodity costs.
The increase in energy supply costs year to date was primarily due to higher overall commodity costs, partially offset by favourable foreign exchange associated with the translation of US dollar-denominated energy supply costs.
Operating Expenses
The increase in operating expenses for the quarter and year to date was primarily due to the acquisition of ITC, and general inflationary and employee-related cost increases. The increase was partially offset by the receipt of a $28 million break fee ($24 million net of related transaction costs and tax) associated with the termination of the Waneta Dam purchase agreement in the third quarter of 2017, acquisition-related transaction costs of $4 million ($3 million after tax) and $39 million ($32 million after tax) for the third quarter and year-to-date 2016, respectively, associated with ITC, and favourable foreign exchange associated with the translation of US dollar-denominated operating expenses.
Depreciation and Amortization
The increase in depreciation and amortization for the quarter and year to date was primarily due to the acquisition of ITC and continued investment in energy infrastructure at the Corporation's other regulated utilities.
Other Income, Net
The increase in other income, net of expenses, for the quarter and year to date was primarily due to the acquisition of ITC. The favourable settlement of matters at UNS Energy pertaining to FERC-ordered transmission refunds of $11 million ($7 million after tax), in the first quarter of 2017, also contributed to the year-to-date increase.
Finance Charges
The increase in finance charges for the quarter and year to date was primarily due to the acquisition of ITC, including interest expense on debt issued to complete the financing of the acquisition. The increase was partially offset by acquisition-related transaction costs of $21 million ($16 million after tax) and $35 million ($26 million after tax) for the third quarter and year-to-date 2016, respectively, associated with ITC.
Income Tax Expense
The increase in income tax expense for the quarter and year to date was driven by the acquisition of ITC and higher earnings before taxes. ITC's higher federal and state jurisdictional tax rates also increased the total effective income tax rate of Fortis.
Net Earnings Attributable to Common Equity Shareholders and Basic Earnings per Common Share
The increase in net earnings attributable to common equity shareholders for the quarter was driven by earnings of $89 million at ITC, which was acquired in October 2016. The increase for the quarter was also due to: (i) lower Corporate and Other expenses, primarily due to the receipt of a break fee, net of related transaction costs, of $24 million associated with the termination of the Waneta Dam purchase agreement recognized in the third quarter of 2017, and $19 million in acquisition-related transactions costs associated with ITC recognized in the third quarter of 2016; (ii) higher earnings from the Aitken Creek natural gas storage facility ("Aitken Creek") related to the unrealized gain on the mark-to-market of derivatives quarter over quarter; (iii) strong performance at UNS Energy, largely due to the impact of the rate case settlement in 2017 and FERC-ordered refunds of $7 million in the third quarter of 2016; (iv) higher earnings at FortisAlberta due to an increase in capital tracker revenue; and (v) a lower loss at FortisBC Energy due to higher allowance for funds used during construction ("AFUDC") and lower operating expenses. The increase was partially offset by: (i) higher finance charges associated with the acquisition of ITC; (ii) the favourable settlement of Springerville Unit 1 matters at UNS Energy in the third quarter of 2016; (iii) unfavourable foreign exchange associated with the translation of US dollar-denominated earnings; (iv) lower contribution from the Caribbean, mainly due to the impact of Hurricane Irma and lower equity income from Belize Electricity Limited ("Belize Electricity"); and (v) business development costs related to the Wataynikaneyap Power Project.
The increase in net earnings attributable to common equity shareholders year to date was driven by earnings of $273 million at ITC. The year-to-date increase was also due to: (i) lower Corporate and Other expenses, primarily due to the receipt of a break fee, as discussed above for the quarter, and $58 million in acquisition-related transactions costs associated with ITC recognized year-to-date 2016; (ii) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives period over period and contribution from the first quarter of 2017; (iii) strong performance at UNS Energy, as discussed above for the quarter, as well as the overall favourable impact of $29 million associated with FERC-ordered refunds; and (iv) higher earnings from FortisBC Energy due to higher AFUDC. The increase was partially offset by: (i) higher finance charges associated with the acquisitions of ITC and Aitken Creek; (ii) the favourable settlement of Springerville Unit 1 matters, as discussed above for the quarter; (iii) lower contribution from the Caribbean, as discussed above for the quarter; (iv) unfavourable foreign exchange associated with the translation of US dollar-denominated earnings; and (v) business development costs related to the Wataynikaneyap Power Project.
Earnings per common share for the quarter and year to date were $0.21 and $0.60 higher, respectively, compared to the same periods in 2016. The impact of the above-noted items on net earnings attributable to common equity shareholders was partially offset by an increase in the weighted average number of common shares outstanding associated with the financing of the acquisition of ITC and the Corporation's dividend reinvestment and share plans.
Adjusted Net Earnings Attributable to Common Equity Shareholders and Adjusted Basic Earnings per Common Share
Fortis supplements the use of US GAAP financial measures with non-US GAAP financial measures, including adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share. The Corporation refers to these measures as non-US GAAP financial measures since they are not required by, or presented in accordance with, US GAAP. The most directly comparable US GAAP measures to adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share are net earnings attributable to common equity shareholders and basic earnings per common share, respectively.
The Corporation calculates adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes are not reflective of the normal, ongoing operations of the business. For the quarter and year-to-date periods ended September 30, 2017 and 2016, the Corporation adjusted net earnings attributable to common equity shareholders for: (i) an acquisition break fee; (ii) acquisition-related transactions costs; and (iii) cumulative adjustments for regulatory decisions pertaining to prior periods considered to be outside the normal course of business for the periods presented. The Corporation no longer excludes mark-to-market adjustments related to derivative instruments at Aitken Creek, which occur in the normal course of Aitken Creek's business, in its calculation of adjusted net earnings attributable to common equity shareholders as comparative information is now presented in reported net earnings.
The adjusting items described above do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar adjustments presented by other companies.
The Corporation calculates adjusted basic earnings per common share by dividing adjusted net earnings attributable to common equity shareholders by the weighted average number of common shares outstanding.
The following table provides a reconciliation of the non-US GAAP financial measures. Each of the adjusting items are discussed in the segmented results of operations for the respective reporting segments.
| Non-US GAAP Reconciliation |
| Periods Ended September 30 |
Quarter |
Year-to-Date |
| ($ millions, except for common share data) |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Net Earnings Attributable to Common Equity Shareholders |
278 |
|
127 |
|
151 |
|
829 |
|
396 |
|
433 |
|
| Adjusting Items: |
|
|
|
|
|
|
|
|
|
|
|
|
| UNS Energy - |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Settlement of FERC-ordered transmission refunds |
- |
|
- |
|
- |
|
(11 |
) |
- |
|
(11 |
) |
| |
FERC-ordered transmission refunds |
- |
|
7 |
|
(7 |
) |
- |
|
18 |
|
(18 |
) |
| Corporate and Other - |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Acquisition break fee |
(24 |
) |
- |
|
(24 |
) |
(24 |
) |
- |
|
(24 |
) |
| |
Acquisition-related transaction costs |
- |
|
19 |
|
(19 |
) |
- |
|
58 |
|
(58 |
) |
| Adjusted Net Earnings Attributable to Common Equity Shareholders |
254 |
|
153 |
|
101 |
|
794 |
|
472 |
|
322 |
|
| Adjusted Basic Earnings Per Common Share ($) |
0.61 |
|
0.54 |
|
0.07 |
|
1.92 |
|
1.66 |
|
0.26 |
|
| Weighted Average Number of Common Shares Outstanding (# millions) |
418.6 |
|
285.0 |
|
133.6 |
|
413.9 |
|
283.7 |
|
130.2 |
|
SEGMENTED RESULTS OF OPERATIONS
| Segmented Net Earnings Attributable to Common Equity Shareholders |
| Periods Ended September 30 |
Quarter |
Year-to-Date |
| ($ millions) |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Regulated Electric & Gas Utilities- United States |
|
|
|
|
|
|
|
|
|
|
|
|
| |
ITC |
89 |
|
- |
|
89 |
|
273 |
|
- |
|
273 |
|
| |
UNS Energy |
112 |
|
102 |
|
10 |
|
242 |
|
170 |
|
72 |
|
| |
Central Hudson |
15 |
|
14 |
|
1 |
|
48 |
|
50 |
|
(2 |
) |
| Regulated Gas Utility - Canadian |
|
|
|
|
|
|
|
|
|
|
|
|
| |
FortisBC Energy |
(15 |
) |
(19 |
) |
4 |
|
88 |
|
81 |
|
7 |
|
| Regulated Electric Utilities - Canadian |
|
|
|
|
|
|
|
|
|
|
|
|
| |
FortisAlberta |
35 |
|
30 |
|
5 |
|
91 |
|
91 |
|
- |
|
| |
FortisBC Electric |
11 |
|
11 |
|
- |
|
42 |
|
41 |
|
1 |
|
| |
Eastern Canadian |
12 |
|
14 |
|
(2 |
) |
48 |
|
48 |
|
- |
|
| Regulated Electric Utilities - Caribbean |
8 |
|
13 |
|
(5 |
) |
25 |
|
34 |
|
(9 |
) |
| Non-Regulated - Energy Infrastructure |
21 |
|
15 |
|
6 |
|
69 |
|
45 |
|
24 |
|
| Corporate and Other |
(10 |
) |
(53 |
) |
43 |
|
(97 |
) |
(164 |
) |
67 |
|
| Net Earnings Attributable to Common Equity Shareholders |
278 |
|
127 |
|
151 |
|
829 |
|
396 |
|
433 |
|
The following is a discussion of the financial results of the Corporation's reporting segments. A discussion of the material regulatory decisions and applications pertaining to the Corporation's regulated utilities is provided in the "Regulatory Highlights" section of this MD&A.
REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES
ITC
| Financial Highlights (1) |
|
| Periods Ended September 30, 2017 |
Quarter |
Year-to-Date |
| Average US:CAD Exchange Rate (2) |
1.25 |
1.31 |
| Revenue ($ millions) |
376 |
1,179 |
| Earnings ($ millions) |
89 |
273 |
| (1) |
Revenue represents 100% of ITC, while earnings represent the Corporation's 80.1% controlling ownership interest in ITC and reflects consolidated purchase price accounting adjustments. |
| (2) |
The reporting currency of ITC is the US dollar. |
Revenue and Earnings
ITC was acquired by Fortis in October 2016 and, therefore, there are no revenue and earnings reported for the comparative periods.
There were no transactions or events, outside the normal course of operations, that materially impacted revenue or earnings for the quarter and year to date.
UNS ENERGY (1)
| Financial Highlights |
Quarter |
Year-to-Date |
| Periods Ended September 30 |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Average US:CAD Exchange Rate(2) |
1.25 |
|
1.31 |
|
(0.06 |
) |
1.31 |
|
1.32 |
|
(0.01 |
) |
| Electricity Sales (gigawatt hours ("GWh")) |
4,416 |
|
4,379 |
|
37 |
|
11,418 |
|
11,031 |
|
387 |
|
| Gas Volumes (petajoules ("PJ")) |
1 |
|
1 |
|
- |
|
9 |
|
9 |
|
- |
|
| Revenue ($ millions) |
599 |
|
604 |
|
(5 |
) |
1,609 |
|
1,534 |
|
75 |
|
| Earnings ($ millions) |
112 |
|
102 |
|
10 |
|
242 |
|
170 |
|
72 |
|
| (1) |
Includes Tucson Electric Power Company ("TEP"), UNS Electric, Inc. and UNS Gas, Inc. |
| (2) |
The reporting currency of UNS Energy is the US dollar. |
Electricity Sales & Gas Volumes
The increase in electricity sales for the quarter was primarily due to higher long-term wholesale sales due to the commencement of a new contract in 2017, partially offset by lower short-term wholesale sales. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings.
The increase in electricity sales year to date was primarily due to higher short-term wholesale sales in the first quarter of 2017 as a result of more favourable commodity prices.
Gas volumes were comparable with the same periods in 2016.
Revenue
The decrease in revenue for the quarter was due to: (i) approximately $25 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue; (ii) $17 million (US$13 million), or $10 million (US$8 million) after tax, in revenue related to the settlement of Springerville Unit 1 matters in the third quarter of 2016; and (iii) lower revenue related to a decrease in fuel cost recovery rates, which has no impact on earnings. The decrease was partially offset by the impact of the rate case settlement effective February 27, 2017, approximately $11 million (US$9 million), or $7 million (US$5 million) after tax, in FERC-ordered transmission refunds recognized in the third quarter of 2016, and higher long-term wholesale sales as discussed above.
The increase in revenue year to date was due to: (i) the impact of the rate case settlement; (ii) approximately $29 million (US$22 million), or $18 million (US$13 million) after tax, in FERC-ordered transmission refunds recognized year-to-date 2016; (iii) higher short-term wholesale sales; and (iv) the reversal of $7 million (US$5 million), or $4 million (US$3 million) after-tax, in transmission refund accruals in the second quarter of 2017. The increase was partially offset by approximately $20 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue, revenue related to the settlement of Springerville Unit 1 matters, as discussed above, and lower revenue related to a decrease in fuel cost recovery rates.
Earnings
The increase in earnings for the quarter was primarily due to the impact of the rate case settlement and $7 million (US$5 million) in FERC-ordered transmission refunds in the third quarter of 2016. The increase was partially offset by $10 million (US$8 million) related to the favourable settlement of Springerville Unit 1 matters recognized in the third quarter of 2016, and approximately $2 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings.
The increase in earnings year to date was due to: (i) the impact of the rate case settlement; (ii) $18 million (US$13 million) in FERC-ordered transmission refunds year-to-date 2016; (iii) more favorably priced long-term wholesale sales; and (iv) approximately $11 million (US$8 million) related to the favourable settlement of FERC-ordered transmission refunds year-to-date 2017. The increase was partially offset by the favourable settlement of Springerville Unit 1 matters, as discussed above, and approximately $1 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings.
CENTRAL HUDSON
| Financial Highlights |
Quarter |
Year-to-Date |
| Periods Ended September 30 |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Average US:CAD Exchange Rate(1) |
1.25 |
|
1.31 |
|
(0.06 |
) |
1.31 |
|
1.32 |
|
(0.01 |
) |
| Electricity Sales (GWh) |
1,318 |
|
1,513 |
|
(195 |
) |
3,696 |
|
3,917 |
|
(221 |
) |
| Gas Volumes (PJ) |
3 |
|
5 |
|
(2 |
) |
16 |
|
18 |
|
(2 |
) |
| Revenue ($ millions) |
197 |
|
208 |
|
(11 |
) |
661 |
|
642 |
|
19 |
|
| Earnings ($ millions) |
15 |
|
14 |
|
1 |
|
48 |
|
50 |
|
(2 |
) |
| (1) |
The reporting currency of Central Hudson is the US dollar. |
Electricity Sales & Gas Volumes
The decrease in electricity sales for the quarter and year to date was primarily due to lower average consumption as a result of cooler temperatures. Also contributing to the year-to-date decrease was lower average consumption in the first quarter of 2017, as a result of warmer temperatures. The decrease in gas volumes for the quarter and year to date was due to reduced demand as a result of cooler temperatures.
Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result, do not have a material impact on earnings.
Revenue
The decrease in revenue for the quarter was mainly due to lower electricity sales and approximately $8 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue. The decrease was partially offset by higher delivery revenue due to the increase in base electricity rates effective July 1, 2017.
The increase in revenue year to date was mainly due to higher delivery revenue from increases in base electricity rates effective July 1, 2017 and 2016 and the recovery from customers of higher commodity costs. The increase was partially offset by lower electricity sales and approximately $9 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.
Earnings
The increase in earnings for the quarter was primarily due to the increase in delivery revenue discussed above, partially offset by higher operating costs. The decrease in earnings year to date was due to higher operating expenses and the timing of unbilled revenue, which is not subject to the operation of the decoupling mechanism, partially offset by increases in delivery revenue. Earnings for the quarter and year to date were also impacted by approximately $1 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings.
REGULATED GAS UTILITY - CANADIAN
FORTISBC ENERGY
| Financial Highlights |
Quarter |
Year-to-Date |
| Periods Ended September 30 |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Gas Volumes (PJ) |
27 |
|
28 |
|
(1 |
) |
152 |
|
130 |
|
22 |
|
| Revenue ($ millions) |
156 |
|
151 |
|
5 |
|
832 |
|
758 |
|
74 |
|
| (Loss) Earnings ($ millions) |
(15 |
) |
(19 |
) |
4 |
|
88 |
|
81 |
|
7 |
|
Gas Volumes
Gas volumes for the quarter were comparable with the same period in 2016. The increase in gas volumes year to date was primarily due to growth in the number of customers and higher average consumption by residential and commercial customers as a result of colder temperatures in the first half of 2017. Also contributing to the increase was higher volumes for transportation customers due to additional customers switching to natural gas compared to alternative fuel sources.
Revenue
The increase in revenue for the quarter and year to date was due to a higher commodity cost of natural gas charged to customers, partially offset by an increase in flow-through adjustments owing to customers. Also contributing to the increase year to date was higher gas volumes.
Earnings
The lower loss for the quarter was primarily due to higher AFUDC and lower operating expenses, partially offset by the timing of quarterly revenue and operating expenses compared to the same period in 2016.
The increase in earnings year to date was primarily due to higher AFUDC and the timing of quarterly revenue and operating expenses compared to the same period in 2016.
FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery of natural gas. As a result of the operation of regulatory deferral mechanisms, changes in consumption levels and the cost of natural gas do not materially affect earnings.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
| Financial Highlights |
Quarter |
Year-to-Date |
| Periods Ended September 30 |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Energy Deliveries (GWh) |
4,156 |
|
4,081 |
|
75 |
|
12,690 |
|
12,436 |
|
254 |
|
| Revenue ($ millions) |
153 |
|
143 |
|
10 |
|
448 |
|
429 |
|
19 |
|
| Earnings ($ millions) |
35 |
|
30 |
|
5 |
|
91 |
|
91 |
|
- |
|
Energy Deliveries
The increase in energy deliveries for the quarter and year to date was primarily due to higher average consumption by residential, commercial and irrigation customers, mainly due to warmer temperatures in the third quarter of 2017, partially offset by lower oil and gas activity. Growth in the number of residential and commercial customers also contributed to the year-to-date increase.
Revenue
The increase in revenue for the quarter and year to date was primarily due to an increase in capital tracker revenue, higher energy deliveries due to higher average consumption, and higher revenue related to the flow through of costs to customers. The increase was partially offset by a decrease in customer rates effective January 1, 2017. Growth in the number of residential and commercial customers also contributed to the year-to-date increase.
Earnings
The increase in earnings for the quarter was primarily due to higher capital tracker revenue, partially offset by lower customer rates, as discussed above, and higher finance charges.
Earnings year to date were comparable with the same period in 2016. The increase in earnings due to higher capital tracker revenue and customer growth was offset by higher finance charges and operating costs and lower customer rates.
FORTISBC ELECTRIC (1)
| Financial Highlights |
Quarter |
Year-to-Date |
| Periods Ended September 30 |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Electricity Sales (GWh) |
779 |
|
728 |
|
51 |
|
2,436 |
|
2,263 |
|
173 |
|
| Revenue ($ millions) |
93 |
|
88 |
|
5 |
|
291 |
|
275 |
|
16 |
|
| Earnings ($ millions) |
11 |
|
11 |
|
- |
|
42 |
|
41 |
|
1 |
|
| (1) |
Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants. |
Electricity Sales
The increase in electricity sales for the quarter and year to date was primarily due to higher average consumption as a result of weather conditions.
Revenue
The increase in revenue for the quarter and year to date was primarily due to higher electricity sales and an increase in base electricity rates effective January 1, 2017, partially offset by higher flow-through adjustments owing to customers.
Earnings
Earnings for the quarter were comparable with the same period in 2016. The increase in earnings year to date was due to lower-than-anticipated operating expenses and higher AFUDC.
Variances from regulated forecasts used to set rates for electricity revenue and energy supply costs are flowed back to customers in future rates through approved regulatory deferral mechanisms and, therefore, these variances do not have an impact on earnings.
EASTERN CANADIAN ELECTRIC UTILITIES (1)
| Financial Highlights |
Quarter |
Year-to-Date |
| Periods Ended September 30 |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Electricity Sales (GWh) |
1,507 |
|
1,540 |
|
(33 |
) |
6,178 |
|
6,167 |
|
11 |
|
| Revenue ($ millions) |
206 |
|
211 |
|
(5 |
) |
789 |
|
785 |
|
4 |
|
| Earnings ($ millions) |
12 |
|
14 |
|
(2 |
) |
48 |
|
48 |
|
- |
|
(1) Comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime Electric Company, Limited and FortisOntario Inc. ("FortisOntario"). Also includes the Corporation's 49% equity investment in Wataynikaneyap Power Limited Partnership.
Electricity Sales
The decrease in electricity sales for the quarter was due to lower average consumption, partially offset by growth in the number of customers.
The increase in electricity sales year to date was primarily due to growth in the number of customers, partially offset by an overall decrease in consumption.
Revenue
The decrease in revenue for the quarter was primarily due to lower electricity sales and the flow through in customer electricity rates of lower energy supply costs, partially offset by an increase in customer electricity rates.
The increase in revenue year to date was due to higher electricity sales and an increase in customer electricity rates, partially offset by the flow through in customer electricity rates of lower energy supply costs.
Earnings
The decrease in earnings for the quarter was due to approximately $2 million in business development costs related to the Wataynikaneyap Power Project. For details on the Wataynikaneyap Power Project refer to the "Additional Investment Opportunities" section of this MD&A.
Earnings year to date were comparable with the same period in 2016. Lower-than-anticipated finance costs, an increase in customer electricity rates and higher electricity sales were offset by business development costs, as discussed above.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
| Financial Highlights |
Quarter |
Year-to-Date |
| Periods Ended September 30 |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Average US:CAD Exchange Rate(2) |
1.25 |
|
1.31 |
|
(0.06 |
) |
1.31 |
|
1.32 |
|
(0.01 |
) |
| Electricity Sales (GWh) |
231 |
|
227 |
|
4 |
|
642 |
|
632 |
|
10 |
|
| Revenue ($ millions) |
77 |
|
79 |
|
(2 |
) |
227 |
|
225 |
|
2 |
|
| Earnings ($ millions) |
8 |
|
13 |
|
(5 |
) |
25 |
|
34 |
|
(9 |
) |
| (1) |
Comprised of Caribbean Utilities Company, Ltd. ("Caribbean Utilities"), in which Fortis holds an approximate 60% controlling interest, and two wholly owned utilities, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "Fortis Turks and Caicos"). Also includes the Corporation's 33% equity investment in Belize Electricity. |
| (2) |
The reporting currency of Caribbean Utilities and Fortis Turks and Caicos is the US dollar. The reporting currency of Belize Electricity is the Belizean dollar, which is pegged to the US dollar at BZ$2.00=US$1.00. |
Electricity Sales
The increase in electricity sales for the quarter and year to date was due to higher average consumption, partially offset by the impact of Hurricane Irma on Fortis Turks and Caicos.
Revenue
The decrease in revenue for the quarter was due to lower electricity sales as a result of the impact of Hurricane Irma and approximately $3 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue. The decrease was partially offset by the flow through in customer electricity rates of higher fuel costs.
The increase in revenue year to date was mainly due to the flow through in customer electricity rates of higher fuel costs and higher base electricity rates. The increase was partially offset by lower electricity sales as a result of the impact of Hurricane Irma and approximately $3 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.
Earnings
The decrease in earnings for the quarter and year to date was due to lower revenue as a result of the impact of Hurricane Irma and lower equity income from Belize Electricity. Also contributing to the decrease year to date was higher finance costs, primarily due to lower capitalized interest.
NON-REGULATED - ENERGY INFRASTRUCTURE (1)
| Financial Highlights |
Quarter |
Year-to-Date |
| Periods Ended September 30 |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Energy Sales (GWh) |
180 |
|
181 |
|
(1 |
) |
781 |
|
786 |
|
(5 |
) |
| Revenue ($ millions) |
47 |
|
44 |
|
3 |
|
162 |
|
139 |
|
23 |
|
| Earnings ($ millions) |
21 |
|
15 |
|
6 |
|
69 |
|
45 |
|
24 |
|
| (1) |
Primarily comprised of long-term contracted generation assets in British Columbia and Belize, with a combined generating capacity of 391 MW, and the Aitken Creek natural gas storage facility in British Columbia, with a total working gas capacity of 77 billion cubic feet. |
Energy Sales
Energy sales for the quarter and year to date were comparable with the same periods in 2016.
Revenue
The increase in revenue for the quarter and year to date was driven by Aitken Creek. Also reflected in the year-to-date increase was the contribution from Aitken Creek in the first quarter of 2017, due to its acquisition occurring in April 2016.
Earnings
The increase in earnings for the quarter and year to date was primarily due to higher earnings from Aitken Creek associated with the unrealized gains on the mark-to-market of derivatives period over period. Also reflected in the year-to-date increase was the contribution from Aitken Creek in the first quarter of 2017.
CORPORATE AND OTHER (1)
| Financial Highlights |
|
|
| Periods Ended September 30 |
Quarter |
Year-to-date |
| ($ millions) |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Revenue |
- |
|
2 |
|
(2 |
) |
1 |
|
7 |
|
(6 |
) |
| Operating Expenses |
(23 |
) |
8 |
|
(31 |
) |
(1 |
) |
61 |
|
(62 |
) |
| Depreciation and Amortization |
- |
|
1 |
|
(1 |
) |
1 |
|
3 |
|
(2 |
) |
| Other Income, Net |
2 |
|
1 |
|
1 |
|
4 |
|
5 |
|
(1 |
) |
| Finance Charges |
47 |
|
47 |
|
- |
|
144 |
|
109 |
|
35 |
|
| Income Tax Recovery |
(28 |
) |
(22 |
) |
(6 |
) |
(91 |
) |
(56 |
) |
(35 |
) |
| |
6 |
|
(31 |
) |
37 |
|
(48 |
) |
(105 |
) |
57 |
|
| Preference Share Dividends |
16 |
|
22 |
|
(6 |
) |
49 |
|
59 |
|
(10 |
) |
| Corporate and Other |
(10 |
) |
(53 |
) |
43 |
|
(97 |
) |
(164 |
) |
67 |
|
| (1) |
Includes Fortis net Corporate expenses and non-regulated holding company expenses |
The decrease at Corporate and Other for the quarter and year to date was primarily due to lower operating expenses, a higher income tax recovery and lower preference share dividends. The year-to-date decrease was partially offset by higher finance charges.
The decrease in operating expenses for the quarter and year to date was primarily due to the receipt of a $28 million break fee ($24 million net of related transaction costs and tax) associated with the termination of the Waneta Dam purchase agreement in the third quarter of 2017, and acquisition-related transaction costs associated with ITC totalling approximately $4 million ($3 million after tax) and $39 million ($32 million after tax) for the third quarter and year-to-date 2016, respectively. The year-to-date decrease was partially offset by higher compensation-related expenditures, general inflationary increases and ancillary expenses to support the Corporation's listing on the New York Stock Exchange.
Finance charges for the quarter were comparable with the same period last year. Finance charges in the third quarter of 2017 reflect the financing of the ITC acquisition, which were offset by acquisition-related transaction costs incurred in the third quarter of 2016 totalling approximately $21 million ($16 million after tax) associated with ITC.
The increase in year-to-date finance charges was mainly due to the financing of the ITC acquisition since October 2016, partially offset by acquisition-related transaction costs discussed above totalling approximately $35 million ($26 million after tax) year-to-date 2016. Finance charges associated with the acquisition of Aitken Creek in April 2016 also contributed to the year-to-date increase.
The higher income tax recovery for the quarter and year to date was mainly due to the increase in finance charges, partially offset by lower acquisition-related transaction costs.
The decrease in preference share dividends for the quarter and year to date was due to the redemption of First Preference Shares, Series E in September 2016.
REGULATORY HIGHLIGHTS
The nature of regulation associated with each of the Corporation's regulated electric and gas utilities is generally consistent with that disclosed in the 2016 Annual MD&A. The following summarizes the significant ongoing regulatory proceedings and significant decisions and applications for the Corporation's regulated utilities year-to-date 2017.
ITC
Return on Equity Complaints
Since 2013 two third-party complaints were filed with FERC requesting that FERC find the Midcontinent Independent System Operator ("MISO") regional base return on equity ("ROE") for all MISO transmission owners, including some of ITC's operating subsidiaries, for the periods November 2013 through February 2015 (the "Initial Refund Period" or "Initial Complaint") and February 2015 through May 2016 (the "Second Refund Period" or "Second Complaint") to no longer be just and reasonable. In September 2016 FERC issued an order affirming the presiding Administrative Law Judge's ("ALJ") initial decision for the Initial Refund Period and setting the base ROE for the Initial Refund Period at 10.32%, with a maximum ROE of 11.35%. Additionally, the rates established by the September 2016 order will be used prospectively from the date of the order until a new approved rate is established for the Second Refund Period. FERC's September 2016 order regarding the Initial Complaint is currently under appeal by the MISO transmission owners. In June 2016 the presiding ALJ issued an initial decision for the Second Refund Period, which recommended a base ROE of 9.70%, with a maximum ROE of 10.68%, which is a recommendation to FERC.
The total estimated refund for the Initial Complaint was $158 million (US$118 million), including interest, as at December 31, 2016. The true-up of the net refund was substantially finalized in the second quarter of 2017 and paid during the first half of 2017. The total amount of the refund, including interest and the associated true-up, for the Initial Complaint was not materially different from the amount recorded as at December 31, 2016.
An order has not yet been issued by FERC in connection with the Second Complaint and in September 2017 the MISO transmission owners filed a motion for FERC to dismiss the Second Complaint. If the Second Complaint is not dismissed, it is expected that FERC will establish a new base ROE and range of reasonableness to calculate the refund liability for the Second Refund Period and future ROEs for ITC's operating subsidiaries. As at September 30, 2017, the estimated range of refunds for the Second Refund Period was between US$105 million to US$143 million and ITC has recognized an aggregated estimated regulatory liability of $178 million (US$143 million).
The estimated regulatory liabilities were accrued by ITC before its acquisition by Fortis. There is uncertainty regarding the final outcome of the Initial and Second Complaints and the timing of the completion of these matters. This is due, in part, to a recent court decision requiring FERC to further justify the methodology used to establish new ROEs. It is possible that the outcome of these matters could differ materially from the estimated range of refunds.
UNS Energy
General Rate Application
In February 2017 the Arizona Corporation Commission issued a rate order for new rates that took effect February 27, 2017 ("2017 Rate Order"). Provisions of the 2017 Rate Order include: (i) an increase in non-fuel base revenue of $108 million (US$81.5 million), including $20 million (US$15 million) of operating costs related to the 50.5% undivided interest in Unit 1 of Springerville Generating Station purchased by TEP in September 2016; (ii) a 7.04% return on original cost rate base, including a cost of equity of 9.75% and an embedded cost of long-term debt of 4.32%; (iii) a common equity component of capital structure of approximately 50%; and (iv) the adoption of proposed depreciation rates which reflect a reduction in the depreciable life for Unit 1 of San Juan Generating Station. Certain aspects of the general rate application, including net metering and rate design for new distributed generation customers, have been deferred to a second phase of TEP's rate case, which is currently expected to be completed in the first quarter of 2018. TEP cannot predict the outcome of these proceedings.
FERC Order
In May 2017 FERC informed TEP that no further enforcement actions were necessary regarding TEP's transmission refunds and closed the related investigation. As a result, TEP reversed the remaining $7 million (US$5 million) provision related to potential time-value refunds.
Central Hudson
General Rate Application
In July 2017 Central Hudson filed a rate case with the New York Public Service Commission ("PSC") requesting an increase in electric and nature gas rates of $55 million (US$43 million) and $23 million (US$18 million), respectively. Included in the rate case was a request to increase the allowed ROE to 9.5% from 9.0% and the equity component of the capital structure to 50% from 48%. An order from the PSC is expected in June 2018 with the new rates to become effective no later than July 1, 2018.
FortisAlberta
Capital Tracker Applications
In January 2017 the Alberta Utilities Commission ("AUC") issued its decision on FortisAlberta's 2015 True-Up Application approving the 2015 capital tracker revenue as filed, pending approval of the Company's Compliance Filing, filed in February 2017. The AUC approved the Compliance Filing in May 2017. In June 2017 the Company filed its 2016 True-Up Application for 2016 capital tracker revenue and a decision is expected in the first quarter of 2018. There was no material adjustment to capital tracker revenue resulting from this application.
Generic Cost of Capital
In July 2017 the AUC established a proceeding to determine the ROE and capital structure for 2018, 2019 and 2020. The proceeding commenced in October 2017, with an oral hearing in March 2018. A decision is expected in the third quarter of 2018.
Next Generation Performance-Based Rate-Setting Proceeding
In December 2016 the AUC issued its decision outlining the manner in which distribution rates will be determined during the second performance-based rate-setting ("PBR") term, being the five-year period from 2018 through 2022. FortisAlberta filed a rebasing application in April 2017 to establish the going-in revenue requirement for the second PBR term, which will be used to determine the going-in rates upon which the PBR formula will be applied to establish distribution rates for 2018. A decision on this application is expected in the first quarter of 2018. The AUC has directed FortisAlberta to use the approved 2017 PBR rates on a continuing interim basis, and 2018 PBR rates will be determined in a separate proceeding following a decision on the Company's rebasing application.
Significant Regulatory Proceedings
The following table summarizes significant ongoing regulatory proceedings, including filing dates and expected timing of decisions for the Corporation's utilities.
| Regulated Utility |
Application/Proceeding |
Filing Date |
Expected Decision |
| ITC |
Second MISO Base ROE 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 September 30, 2017 and December 31, 2016.
| Significant Changes in the Consolidated Balance Sheets between September 30, 2017 and December 31, 2016 |
Balance Sheet Account |
|
Increase/
(Decrease)
($ millions) |
Explanation |
| Capital assets, net |
|
(270) |
The decrease was mainly due to the impact of foreign exchange associated with the translation of US dollar-denominated capital assets, depreciation, the reclassification of a reserve from regulatory liabilities at UNS Energy, and the reclassification of the net book value of assets planned for early retirement to regulatory assets at UNS Energy, partially offset by capital expenditures. |
| Goodwill |
|
(776) |
The decrease was due to the impact of foreign exchange associated with the translation of US dollar-denominated goodwill. |
| Short-term borrowings |
|
(487) |
The decrease was mainly due to the 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 FortisAlberta using proceeds from the issuance of long-term debt. The decrease was partially offset by higher short-term borrowings at ITC and FortisBC Energy. |
| Accounts payable and other current liabilities |
|
(201) |
The decrease was primarily due to the timing of the declaration of the Corporation's common share dividends, lower amounts owing for energy supply costs at FortisBC Energy and Newfoundland Power associated with the seasonality of operations, and the impact of foreign-exchange associated with the translation of US dollar-denominated accounts payable. The decrease was partially offset by an increase in capital accruals at ITC and an increase in transmission costs payable at FortisAlberta. |
| Regulatory liabilities - current and long-term |
|
(258) |
The decrease was primarily due to a reduction in regulatory liabilities at ITC associated with the refund payment associated with the Initial Complaint, the reclassification of a reserve to capital assets at UNS Energy, and the translation of US dollar-denominated regulatory liabilities. The decrease was partially offset by an increase in FortisBC Energy's deferral adjustments owing to customers. |
| Long-term debt (including current portion) |
|
(576) |
The decrease was mainly due to the impact of foreign exchange associated with the translation of US dollar-denominated debt and regularly scheduled debt repayments. The decrease was partially offset by the issuance of term loan credit agreements and first mortgage bonds by ITC, and debt issued at other of the regulated utilities. |
| Deferred income tax liabilities |
|
141 |
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 |
|
527 |
The increase was primarily due to: (i) the issuance of $500 million of common shares; (ii) net earnings attributable to common equity shareholders for the nine months ended September 30, 2017, less dividends declared on common shares; and (iii) the issuance of common shares under the Corporation's dividend reinvestment, employee share purchase and stock option plans. The increase was partially offset by a decrease in accumulated other comprehensive income associated with the translation of the Corporation's US dollar-denominated investments in subsidiaries, net of hedging activities and tax. |
LIQUIDITY AND CAPITAL RESOURCES
SUMMARY OF CONSOLIDATED CASH FLOWS
The table below outlines the Corporation's sources and uses of cash for the third quarter and year-to-date periods ended September 30, 2017 compared to the same periods in 2016, followed by a discussion of the nature of the variances in cash flows.
| Summary of Consolidated Cash Flows |
| Periods Ended September 30 |
Quarter |
Year-to-Date |
| ($ millions) |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| Cash, Beginning of Period |
231 |
|
296 |
|
(65 |
) |
269 |
|
242 |
|
27 |
|
| Cash Provided by (Used in): |
|
|
|
|
|
|
|
|
|
|
|
|
| |
Operating Activities |
800 |
|
478 |
|
322 |
|
1,990 |
|
1,409 |
|
581 |
|
| |
Investing Activities |
(683 |
) |
(529 |
) |
(154 |
) |
(2,143 |
) |
(1,704 |
) |
(439 |
) |
| |
Financing Activities |
(87 |
) |
51 |
|
(138 |
) |
148 |
|
365 |
|
(217 |
) |
| |
Effect of Exchange Rate Changes on Cash and Cash Equivalents |
(9 |
) |
5 |
|
(14 |
) |
(12 |
) |
(11 |
) |
(1 |
) |
| Cash, End of Period |
252 |
|
301 |
|
(49 |
) |
252 |
|
301 |
|
(49 |
) |
Operating Activities: Cash flow provided by operating activities was $322 million higher quarter over quarter and $581 million higher year to date compared to the same periods in 2016. The increase was primarily due to higher cash earnings, driven by ITC and UNS Energy, and favourable changes in long-term regulatory deferrals. The year-to-date increase was partially offset by timing differences in working capital, mainly due to the payment of the Initial Complaint refund at ITC in the first quarter of 2017.
Investing Activities: Cash used in investing activities was $154 million higher quarter over quarter and $439 million higher year to date compared to the same periods in 2016. The increase was driven by capital spending at ITC. The year-to-date increase was partially offset by the acquisition of Aitken Creek in the second quarter of 2016 for a net cash purchase price of $318 million.
Financing Activities: Cash provided by financing activities was $138 million lower quarter over quarter and $217 million lower year to date compared to the same periods in 2016. The decrease was primarily due to higher net repayments under committed credit facilities and short-term borrowings, partially offset by lower repayments of long-term debt and higher proceeds from the issuance of long-term debt.
In March 2017 approximately 12.2 million common shares of Fortis were issued to an institutional investor for proceeds of $500 million. The proceeds were used to repay short-term borrowings.
In September 2016 the Corporation redeemed all of the First Preference Shares, Series E for $200 million.
Proceeds from long-term debt, net of issue costs, for the quarter and year to date compared to the same periods last year are summarized in the following table.
| Proceeds from Long-Term Debt, Net of Issue Costs |
|
|
|
| Periods Ended September 30 |
Quarter |
Year-to-Date |
| ($ millions) |
2017 |
|
2016 |
|
Variance |
2017 |
|
2016 |
|
Variance |
| ITC (1) |
- |
|
- |
|
- |
|
601 |
|
- |
|
601 |
|
| Central Hudson (2) |
75 |
|
- |
|
75 |
|
75 |
|
29 |
|
46 |
|
| FortisBC Energy (3) |
- |
|
- |
|
- |
|
- |
|
298 |
|
(298 |
) |
| FortisAlberta (4) |
199 |
|
149 |
|
50 |
|
199 |
|
149 |
|
50 |
|
| Eastern Canadian (5)(6) |
- |
|
40 |
|
(40 |
) |
75 |
|
40 |
|
35 |
|
| Caribbean Electric (7)(8) |
- |
|
36 |
|
(36 |
) |
80 |
|
65 |
|
15 |
|
| Corporate |
- |
|
(2 |
) |
2 |
|
- |
|
(2 |
) |
2 |
|
| Total |
274 |
|
223 |
|
51 |
|
1,030 |
|
579 |
|
451 |
|
| (1) |
In March 2017 ITC entered into 1-year and 2-year unsecured term loan credit agreements at floating interest rates of a one-month LIBOR plus a spread of 0.90% and 0.65%, respectively. During 2017 borrowings under the term loan credit agreements were US$200 million ($250 million) and US$50 million ($62 million), respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes. In April 2017 ITC issued 30-year US$200 million ($250 million) 4.16% secured first mortgage bonds. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes. |
| (2) |
In August 2017 Central Hudson issued 30-year US$30 million ($37 million) unsecured notes at 4.05% and 40-year US$30 million ($37 million) unsecured notes at 4.20%. The net proceeds from the issuances were used to repay long-term debt and for general corporate purposes. In June 2016 Central Hudson issued 5-year US$24 million ($29 million) unsecured notes at 2.16%. The net proceeds were used to finance capital expenditures and for general corporate purposes. |
| (3) |
In April 2016 FortisBC Energy issued $300 million of unsecured debentures in a dual tranche of 10-year $150 million unsecured debentures at 2.58% and 30-year $150 million unsecured debentures at 3.67%. The net proceeds were used to repay short-term borrowings and to finance capital expenditures. |
| (4) |
In September 2017 FortisAlberta issued 30-year $200 million unsecured debentures at 3.67%. The net proceeds from the issuance were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes. In September 2016 FortisAlberta issued 30-year $150 million unsecured debentures at 3.34%. The net proceeds were used to repay credit facility borrowings and for general corporate purposes. |
| (5) |
In June 2017 Newfoundland Power issued 40-year $75 million first mortgage sinking fund bonds at 3.815%. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes. |
| (6) |
In August 2016 Maritime Electric issued 40-year $40 million secured first mortgage bonds at 3.657%. The net proceeds were primarily used to repay long-term debt and short-term borrowings. |
| (7) |
In March and May 2017, Caribbean Utilities issued US$60 million ($75 million) of unsecured notes in a dual tranche of 15-year US$40 million ($50 million) at 3.90% and 30-year US$20 million ($25 million) at 4.64%, respectively. The net proceeds from the issuances were used to finance capital expenditures and repay short-term borrowings. |
| (8) |
In May and September 2016 Fortis Turks and Caicos issued 15-year US$45 million ($65 million) unsecured notes, in a dual tranche of US$22.5 million ($29 million) at 5.14% and US$22.5 million ($36 million) at 5.29%, respectively. The net proceeds were used to finance capital expenditures and for general corporate purposes. |
Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay borrowings under the Corporation's committed credit facility.
Common share dividends paid in the third quarter of 2017 were $106 million, net of $61 million of dividends reinvested, compared to $69 million, net of $37 million of dividends reinvested, paid in the third quarter of 2016. Common share dividends paid year-to-date 2017 were $308 million, net of $186 million of dividends reinvested, compared to $216 million, net of $102 million of dividends reinvested, paid year-to-date 2016. The dividend paid per common share for each of the first, second and third quarters of 2017 was $0.40 compared to $0.375 for each of the same quarters of 2016. The weighted average number of common shares outstanding for the third quarter and year-to-date 2017 was 418.6 million and 413.9 million, respectively, compared to 285.0 million and 283.7 million for each of the same periods in 2016.
CONTRACTUAL OBLIGATIONS
There were no material changes in the nature and amount of the Corporation's contractual obligations during the three and nine months ended September 30, 2017 from those disclosed in the 2016 Annual MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated electric and gas utilities require ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings, and advances from minority investors. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in their customer rates.
The consolidated capital structure of Fortis is presented in the following table.
| Capital Structure |
As at |
| |
September 30, 2017 |
December 31, 2016 |
| |
($ millions) |
(%) |
($ millions) |
(%) |
| Total debt and capital lease and financeobligations (net of cash)(1) |
21,420 |
58.6 |
22,490 |
60.6 |
| Preference shares |
1,623 |
4.4 |
1,623 |
4.4 |
| Common shareholders' equity |
13,501 |
37.0 |
12,974 |
35.0 |
| Total |
36,544 |
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 September 30, 2017 was 55.9% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 35.3% common shareholders' equity and 4.6% non-controlling interests (December 31, 2016 - 57.8% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 33.3% common shareholders' equity and 4.7% non-controlling interests). The improvement in the Corporation's capital structure was primarily due the issuance of $500 million of common shares in March 2017, for which the net proceeds were used to repay short-term borrowings.
CREDIT RATINGS
The Corporation's credit ratings are as follows.
| Rating Agency |
Credit Rating |
Type of Rating |
Outlook |
| Standard & Poor's ("S&P") |
A- |
Corporate |
Stable |
| |
BBB+ |
Unsecured debt |
Stable |
| DBRS |
BBB (high) |
Corporate |
Stable |
| |
BBB (high) |
Unsecured debt |
Stable |
| Moody's Investor Service ("Moody's") |
Baa3 |
Issuer |
Stable |
| |
Baa3 |
Unsecured debt |
Stable |
The above-noted credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company. In May 2017 S&P and DBRS affirmed the Corporation's long-term corporate and unsecured debt credit ratings, and in September 2017 Moody's affirmed the Corporation's long-term issuer and unsecured debt credit ratings.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $2.1 billion in gross consolidated capital expenditures by segment year-to-date 2017 is provided in the following table.
| Gross Consolidated Capital Expenditures (1) |
| Year-to-date September 30, 2017 |
| ($ millions) |
| |
Regulated |
|
|
|
|
| |
|
|
|
|
|
|
|
|
Total |
|
|
| |
|
UNS |
Central |
FortisBC |
Fortis |
FortisBC |
Eastern |
Caribbean |
Regulated |
Non- |
|
| |
ITC |
Energy |
Hudson |
Energy |
Alberta |
Electric |
Canadian |
Electric |
Utilities |
Regulated(2) |
Total |
| Total |
725 |
347 |
156 |
329 |
304 |
72 |
102 |
86 |
2,121 |
13 |
2,134 |
| (1) |
Represents cash payments to construct capital and intangible assets, as reflected on the condensed consolidated interim statement of cash flows. Excludes the non-cash equity component of AFUDC. |
| (2) |
Includes Energy Infrastructure and Corporate and Other segments |
Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from those forecast.
Gross consolidated capital expenditures for 2017 are forecast to be approximately $3.1 billion. There have been no material changes in the overall expected level, nature and timing of the Corporation's capital expenditures from those that were disclosed in the 2016 Annual MD&A, with the exception of capital expenditures for UNS Energy. Capital expenditures at UNS Energy are expected to be higher than the original forecast, primarily due to capital expenditures related to investment in natural gas-fired facilities and distribution modernization projects.
At ITC approximately $300 million (US$231 million) was invested in the Multi-Value Projects ("MVPs") from the date of acquisition. The MVPs consist of four regional electric transmission projects that have been identified by MISO to address system capacity needs and reliability in various states.
Approximately $448 million, including AFUDC and development costs, has been invested in the Tilbury Liquefied Natural Gas ("LNG") facility expansion ("Tilbury LNG Facility Expansion"), in British Columbia, to the end of the third quarter of 2017. The total cost of the project is estimated at approximately $470 million, including approximately $70 million of AFUDC and development costs, which could be impacted depending on the date the project is considered in service for rate-making purposes. The facility includes a second LNG tank and a new liquefier, both expected to be in service in the fourth quarter of 2017 or the first quarter of 2018.
Beginning with the first Order in Council ("OIC") in 2013, the Government of British Columbia has continued to support the Tilbury LNG Facility Expansion. The most recent OIC issued in March 2017 further facilitates the expansion of the facility by increasing the capital cost limit to $425 million from $400 million, before AFUDC and development costs. This latest OIC also provides greater discretion around when certain projects approved pursuant to previous OICs, including the Tilbury LNG Expansion Facility, could be added to rate base.
Over the five-year period from 2018 through 2022 ("five-year capital program"), gross consolidated capital expenditures are expected to be approximately $14.5 billion, $1.5 billion higher than $13 billion previously forecast for the period from 2017 through 2021. The improvement in the five-year capital program is the result of the Corporation's sustainable organic growth platform and reflects increased investment mainly at FortisBC Energy and UNS Energy. The low-risk, highly executable five-year capital program contains only a small number of major projects.
The five-year capital program includes approximately $350 million at FortisBC Energy related to a natural gas pipeline expansion ("Eagle Mountain Woodfibre Gas Pipeline Project") at a proposed LNG site in Squamish, British Columbia. The current estimate of FortisBC Energy's investment in the project may be updated for final scoping, detailed construction estimates and scheduling, and final determination of customer capital contributions. FortisBC Energy received an OIC from the Government of British Columbia effectively exempting this project from further regulatory approval by the British Columbia Utilities Commission. Woodfibre LNG has obtained an export license from the National Energy Board ("NEB"), which was recently extended from 25 to 40 years, and received environmental assessment approvals from the Squamish First Nation, the British Columbia Environmental Assessment Office and the Canadian Environmental Assessment Agency. FortisBC Energy also received environmental assessment approval from the Squamish First Nation and provincial environmental assessment approval in 2016. In November 2016 Woodfibre LNG announced the approval from its parent company, Pacific Oil & Gas Limited, which is part of the Singapore-based RGE group of companies, of the funds necessary to proceed with the project. Given the increased certainty with the number of project approvals received and the level of planning, engineering and expenditures completed by Woodfibre LNG to date, the Eagle Mountain Woodfibre Gas Pipeline Project has been included in the five-year capital program, and is not expected to be in service before 2021. The project remains contingent on Woodfibre LNG making a final investment decision.
Also included in the five-year capital program is approximately $300 million associated with a multi-year Pipeline Integrity Management Program at FortisBC Energy. The program is focused on improving pipeline safety and the integrity of the high-pressure transmission system, including pipeline modifications and looping.
The five-year capital program includes the expected addition of 200 MW of flexible generation resources at UNS Energy, which will consist of 10 natural gas-fired reciprocating engines. The engines will provide ramping and peaking capabilities, replace aging, less efficient steam turbines and will facilitate the addition of renewable generating sources to the grid. The total cost of the program is estimated at $230 million (US$180 million) with expected in-service dates between 2019 and 2020. Also included in the capital program is the expected addition of the 550 MW natural gas-fired Gila River Generating Unit 2 by UNS Energy, estimated at $210 million (US$165 million), which will assist with the replacement of retiring coal-fired generation facilities. This project includes an initial tolling agreement with a purchase option expected to be exercised in late 2019.
ADDITIONAL INVESTMENT OPPORTUNITIES
Management is pursuing additional investment opportunities within existing service territories. These additional investment opportunities, as discussed below, are not included in the Corporation's base five-year capital program.
FortisOntario - Wataynikaneyap Power Project
The Wataynikaneyap Power Project continues to advance in Ontario. Consisting of a partnership between 22 First Nation communities and Fortis, the project's mandate is to connect remote First Nation communities to the electricity grid in Ontario through the development of new transmission lines. In 2016 the Government of Ontario designated Wataynikaneyap Power as the licensed transmission company to complete this project. Fortis reached an agreement with Renewable Energy Systems Canada in December 2016 to acquire its ownership interest in the Wataynikaneyap Partnership. The transaction was approved by the Ontario Energy Board ("OEB") and closed in March 2017. As a result, Fortis' ownership interest in the Wataynikaneyap Partnership has increased to 49%, with the remaining 51% ownership interest held by the 22 First Nation communities. The total estimated capital cost for the project, subject to final cost estimation, is approximately $1.35 billion and is expected to contribute to significant savings for the First Nation communities and result in a significant reduction in greenhouse gas emissions. In March 2017 the project reached a significant milestone with the approval by the OEB of a deferral account to recover development costs incurred between November 2010 and the commencement of construction. In August 2017 the federal government announced it will fully fund, up to $60 million, to connect the Pikangikum First Nation to Ontario's power grid, a component of the larger Wataynikaneyap Power Project. In addition to environmental assessments underway, other regulatory approvals are currently being sought and the next regulatory milestone will be the preparation and filing of the leave to construct with the OEB, which is expected in the fourth quarter of 2017. Construction of the larger Wataynikaneyap Power Project will commence pending the receipt of permits, approvals and a cost-sharing agreement between the federal and provincial governments.
ITC - Lake Erie Connector
The Lake Erie Connector is a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line that would provide the first direct link between the markets of the Ontario Independent Electricity System Operator and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets.
In January 2017 ITC received approval of a Presidential Permit from the U.S. Department of Energy for the Lake Erie Connector transmission line, which is a required approval for international border-crossing projects. Also in January, ITC received a report from Canada's NEB recommending the issuance of a Certificate of Public Convenience and Necessity ("CPCN") with prescribed conditions for the transmission line. In May 2017 ITC completed the major permit process in Pennsylvania upon receipt of two required permits from the Pennsylvania Department of Environmental Protection. In June 2017 ITC received approval from Canada's Governor in Council and the CPCN was issued by the NEB. In October 2017 ITC received permits from the U.S. Army Corps of Engineers, which completes the project's major application process in the United States and Canada. The project continues to advance through regulatory, operational, and economic milestones. Ongoing activities include completing project cost refinement and securing favourable transmission service agreements with prospective counterparties. Pending achievement of key milestones, the expected in-service date for the project is late 2021.
FortisBC - LNG
The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including further expansion of Tilbury. The Tilbury LNG facility is uniquely positioned to meet customer demand for clean-burning natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment, and is relatively close to international shipping lanes. Fortis continues to have discussions with a number of potential export customers.
Other Opportunities
Other capital investment opportunities, above the base five-year capital program, include, but are not limited to: incremental regulated transmission and contracted transmission investment opportunities at ITC; renewable energy investments, energy storage projects, grid modernization, infrastructure resiliency, and transmission investments at UNS Energy; and further gas infrastructure opportunities at FortisBC Energy.
CASH FLOW REQUIREMENTS
At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of subsidiary operating cash flows, with varying levels of residual cash flows available for subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities may be required from time to time to support seasonal working capital requirements. Cash required to complete subsidiary capital expenditure programs is also expected to be financed from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis.
The Corporation's ability to service its debt obligations and pay dividends on its common and preference shares is dependent on the financial results of the operating subsidiaries and the related cash payments from these subsidiaries. Certain regulated subsidiaries are subject to restrictions that may limit their ability to distribute cash to Fortis. These include restrictions by certain regulators limiting the amount of annual dividends and restrictions by certain lenders limiting the amount of debt to total capitalization at the subsidiaries. In addition, there are practical limitations on using the net assets of each of the Corporation's regulated operating subsidiaries to pay dividends based on management's intent to maintain the regulator-approved capital structures for each of its regulated operating subsidiaries. The Corporation does not expect that maintaining the targeted capital structures of its regulated operating subsidiaries will have an impact on its ability to pay dividends in the foreseeable future.
Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends.
In October 2017 FortisBC Energy filed a short-form base shelf prospectus, under which the Company may issue debentures in an aggregate principal amount of up to $650 million during the 25-month life of the base shelf prospectus. Also in October, the Company issued $175 million of unsecured debentures at 3.69% under the base shelf prospectus. The net proceeds from the issuance were used to repay short-term borrowings.
In November 2016 Fortis filed a short-form base shelf prospectus, under which the Corporation may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $5 billion during the 25-month life of the base shelf prospectus. In July 2017 Fortis exchanged its US$2.0 billion ($2.6 billion) unregistered senior unsecured notes for US$2.0 billion ($2.6 billion) registered senior unsecured notes under the base shelf prospectus. In March 2017 Fortis issued $500 million common equity and in December 2016 issued $500 million unsecured notes at 2.85%, both under the base shelf prospectus. A principal amount of approximately $1.5 billion remains under the base shelf prospectus.
As at September 30, 2017, management expects consolidated fixed-term debt maturities and repayments to average approximately $721 million annually over the next five years. The combination of available credit facilities and manageable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
Fortis and its subsidiaries were in compliance with debt covenants as at September 30, 2017 and are expected to remain compliant throughout 2017.
CREDIT FACILITIES
As at September 30, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.3 billion, of which approximately $4.0 billion was unused, including $1.0 billion unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $4.8 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2022.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
| Credit Facilities |
|
|
As at |
| |
Regulated
Utilities |
|
Corporate
and Other |
|
September 30, 2017 |
|
December 31,
2016 |
|
| ($ millions) |
| Total credit facilities(1) |
3,950 |
|
1,385 |
|
5,335 |
|
5,976 |
|
| Credit facilities utilized: |
|
|
|
|
|
|
|
|
| |
Short-term borrowings(1) |
(668 |
) |
- |
|
(668 |
) |
(1,155 |
) |
| |
Long-term debt (includingcurrent portion)(2) |
(266 |
) |
(272 |
) |
(538 |
) |
(973 |
) |
| Letters of credit outstanding |
(73 |
) |
(55 |
) |
(128 |
) |
(119 |
) |
| Credit facilities unused |
2,943 |
|
1,058 |
|
4,001 |
|
3,729 |
|
| (1) |
Total credit facilities and short-term borrowings as at September 30, 2017 include $286 million outstanding under ITC's commercial paper program (December 31, 2016 - $195 million). Outstanding commercial paper does not reduce available capacity under the Corporation's consolidated credit facilities. |
| (2) |
As at September 30, 2017, none of the credit facility borrowings were classified as current installments of long-term debt on the consolidated balance sheet (December 31, 2016 - $61 million). |
As at September 30, 2017 and December 31, 2016, certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods. There were no material changes in credit facilities from that disclosed in the Corporation's 2016 Annual MD&A, except as follows.
In March 2017 the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares. In July 2017 the Corporation amended its $1.3 billion unsecured committed revolving credit facility, resulting in an extension of the maturity date to July 2022. The Corporation has the option to increase the facility by $0.5 billion to $1.8 billion and, as at September 30, 2017, that option had not been exercised.
In September 2017 FortisAlberta repaid its $90 million bilateral credit facility using the proceeds from the issuance of long-term debt. The bilateral credit facility was terminated upon repayment.
In October 2017 ITC replaced its US$1.0 billion ($1.2 billion) credit facility agreements with US$900 million ($1.1 billion) unsecured committed revolving credit facility agreements, maturing in October 2022.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $128 million as at September 30, 2017 (December 31, 2016 - $119 million), the Corporation had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
Year-to-date 2017, the business risks of the Corporation were generally consistent with those disclosed in the Corporation's 2016 Annual MD&A, including certain risks, as disclosed below, and an update to those risks, where applicable.
Regulatory Risk: For further information, refer to the "Regulatory Highlights" section of this MD&A.
Capital Resources and Liquidity Risk - Credit Ratings: Year-to-date 2017 the following changes occurred to the debt credit ratings of the Corporations' utilities: In April 2017 S&P upgraded TEP's unsecured debt rating to 'A-' from 'BBB+', with a stable outlook and in September 2017 S&P upgraded ITC's unsecured debt rating to 'A-' from 'BBB+'. For a discussion on the Corporation's credit ratings refer to the "Liquidity and Capital Resources" section of this MD&A.
Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at September 30, 2017, the fair value of the Corporation's consolidated defined benefit pension and other post-employment benefit plan assets was $2,994 million compared to $2,898 million as at December 31, 2016.
CHANGES IN ACCOUNTING POLICIES
The condensed consolidated interim financial statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation's 2016 annual audited consolidated financial statements, except as described below.
Simplifying the Test for Goodwill Impairment
Effective January 1, 2017, the Corporation adopted Accounting Standards Update ("ASU") No. 2017-04, Simplifying the Test for Goodwill Impairment. The amendments in this update simplify the subsequent measurement of goodwill by eliminating step two in the current two-step goodwill impairment test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. The above-noted ASU was applied prospectively and did not impact the Corporation's condensed consolidated interim financial statements for the three and nine months ended September 30, 2017.
FUTURE ACCOUNTING PRONOUNCEMENTS
The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board ("FASB"). The following updates have been issued by FASB, but have not yet been adopted by Fortis. Any ASUs not included below were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements.
Revenue from Contracts with Customers
ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and can be applied consistently across various transactions, industries and capital markets. In 2016 a number of additional ASUs were issued that clarify implementation guidance in ASC Topic 606. This standard, and all related ASUs, is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted for annual and interim periods beginning after December 15, 2016. The Corporation has elected not to early adopt.
The new guidance permits two methods of adoption: (i) the full retrospective method; and (ii) the modified retrospective method. The Corporation expects to adopt the guidance using the modified retrospective method, under which comparative periods would not be restated and the cumulative impact of applying the standard would be recognized at the date of initial adoption, January 1, 2018.
More than 90% of the Corporation's revenue is generated from energy sales to retail and wholesale customers based on published tariff rates, as approved by the respective regulators. Fortis has assessed retail and wholesale tariff revenue and expects that the adoption of this standard will not change the Corporation's accounting policy for recognizing retail and wholesale tariff revenue and, therefore, will not have an impact on earnings. Fortis is finalizing its assessment on whether this standard will have an impact on its remaining revenue streams. The Corporation has not disclosed the expected impact of adoption on its consolidated financial statements as it is not expected to be material.
Alternative revenue programs of rate regulated utilities are outside the scope of this standard as they are not considered contracts with customers. Revenues arising from alternative revenue programs will be presented separately from revenues in scope of the new guidance. The Corporation also expects to add additional disclosures to address the requirements to provide more information regarding the nature, amount, timing and uncertainty of revenue and cash flows. Fortis is in the process of drafting these required disclosures.
As part of its effort to adopt the new revenue recognition standard, Fortis is monitoring its adoption process under its existing internal controls over financial reporting ("ICFR"), including accounting processes and the gathering and evaluation of information used in assessing the required disclosures. As the implementation process continues, Fortis will assess any necessary changes to ICFR.
Recognition and Measurement of Financial Assets and Financial Liabilities
ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial instrument. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Leases
ASU No. 2016-02 was issued in February 2016 and the amendments in this update create ASC Topic 842, Leases, and supersede lease requirements in ASC Topic 840, Leases. The main provision of ASC Topic 842 is the recognition of lease assets and lease liabilities on the balance sheet by lessees for those leases that were previously classified as operating leases. For operating leases, a lessee is required to do the following: (i) recognize a right-of-use asset and a lease liability, initially measured at the present value of the lease payments, on the balance sheet; (ii) recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and (iii) classify all cash payments within operating activities in the statement of cash flows. These amendments also require qualitative disclosures along with specific quantitative disclosures. This update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Measurement of Credit Losses on Financial Instruments
ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, was issued in March 2017 and the amendments in this update require that an employer disaggregate the current service cost component of net benefit cost and present it in the same statement of earnings line item(s) as other employee compensation costs arising from services rendered. The other components of net benefit cost are required to be presented separately from the service cost component and outside of operating income. Additionally, the amendments allow only the service cost component to be eligible for capitalization when applicable. This update is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted. The amendments in this update should be applied retrospectively for the presentation of the net periodic benefit costs and prospectively, on and after the effective date, for the capitalization in assets of only the service cost component of net periodic benefit costs. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Targeted Improvements to Accounting for Hedging Activities
ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, was issued in August 2017 and the amendments in this update better align risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and presentation of hedge results. This update is effective for annual and interim periods beginning after December 15, 2018. Early adoption is permitted. The amendments in this update should be reflected as of the beginning of the fiscal year of adoption. For cash flow and net investment hedges existing at the date of adoption, the amendments should be applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to the opening balance of retained earnings. Amended presentation and disclosure guidance is required only prospectively. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows.
| Financial Instruments |
As at |
| |
September 30, 2017 |
December 31, 2016 |
| |
Carrying |
Estimated |
Carrying |
Estimated |
| ($ millions) |
Value |
Fair Value |
Value |
Fair Value |
| Long-term debt, including current portion |
20,634 |
22,147 |
21,219 |
22,523 |
| Waneta Partnership promissory note |
62 |
62 |
59 |
61 |
The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.
Derivative Instruments
The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments is the estimate of the amounts that the Corporation would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates. The Corporation's derivatives primarily include energy contracts that are subject to regulatory deferral, as permitted by the regulators, as well as certain limited energy contracts that are not subject to regulatory deferral and cash flow hedges.
For further details of the Corporation's derivative instruments as at September 30, 2017 refer to Note 15 to the Corporation's unaudited condensed consolidated interim financial statements. There were no material changes in the nature and amount of the Corporations' derivative instruments from those disclosed in the 2016 Annual MD&A, except as follows.
In 2017 ITC entered into additional forward-starting interest rate swaps, all effective December 2017, with a combined notional amount of $811 million and with 5-year and 10-year original terms. The agreements include a mandatory early termination provision and will be terminated no later than the effective date. The interest rate swaps manage the interest rate risk associated with the forecasted future issuance of fixed-rate debt and amounts outstanding under the revolving credit agreement and commercial paper program.
In August 2017 the Corporation entered into three total return swaps with a combined notional amount of $33 million and terms ranging from one to three years terminating in January 2018, 2019 and 2020. The total return swaps manage the cash flow risk associated with forecasted future cash settlements of certain stock-based compensation.
In October 2017 the Corporation entered into forward sales contracts with notional amounts totalling US$125 million to manage its exposure to foreign currency fluctuations.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's condensed consolidated interim financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, they are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.
Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates from those disclosed in the 2016 Annual MD&A, except as follows.
Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows. For complete details of legal proceedings affecting the Corporation, refer to Note 18 to the Corporation's unaudited condensed consolidated interim financial statements. There were no material changes in the Corporation's contingencies from those disclosed in the 2016 Annual MD&A, except as described below.
Fortis and ITC
Following announcement of the acquisition of ITC in February 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan ("Superior Court") and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified damages and costs, including attorneys' fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In March 2017 an agreement in principle was reached to settle the case, subject to formal documentation and court approval. In September 2017 a final settlement approval hearing was held after which the court entered an order and final judgment approving the settlement. Pursuant to the order and final judgment, the shareholder class action litigation against ITC has been dismissed.
Fortis Turks and Caicos
In September 2017 the Turks and Caicos Islands were struck by Hurricane Irma, resulting in significant damage to Fortis Turks and Caicos' transmission and distribution system. Damaged energy infrastructure interrupted the Company's ability to provide electricity service to its customers, and restoration efforts continue. The Company is currently assessing the total cost of restoration. The possibility exists that the impact of Hurricane Irma could adversely affect future earnings of Fortis Turks and Caicos as well as impair its capital assets and goodwill. The outcome cannot be reasonably determined or estimated at this time and, accordingly, no amount has been accrued in the condensed consolidated interim financial statements.
RELATED-PARTY AND INTER-COMPANY TRANSACTIONS
Related-party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. There were no material related-party transactions for the three and nine months ended September 30, 2017 and 2016.
Inter-company balances and inter-company transactions, including any related inter-company profit, are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The significant inter-company transactions are summarized in the following table.
| Related-party and inter-company transactions |
|
|
| Periods Ended September 30 |
Quarter |
Year-to-Date |
| ($ millions) |
2017 |
2016 |
2017 |
2016 |
| Sale of capacity from Waneta Expansion to FortisBC Electric |
11 |
14 |
30 |
32 |
| Sale of energy from Belize Electric Company Limited toBelize Electricity |
11 |
12 |
25 |
26 |
| Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy |
5 |
4 |
18 |
9 |
As at September 30, 2017, accounts receivable on the Corporation's condensed consolidated interim balance sheet included approximately $16 million due from Belize Electricity (December 31, 2016 - $16 million), in which Fortis holds a 33% equity investment.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth certain quarterly information for the Corporation. The quarterly information has been obtained from the Corporation's unaudited condensed consolidated interim financial statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.
| Summary of Quarterly Results |
|
Net Earnings |
|
| |
|
Attributable to |
| |
|
Common Equity |
|
| |
Revenue |
Shareholders |
Earnings per Common Share |
| Quarter Ended |
($ millions) |
($ millions) |
Basic ($) |
Diluted ($) |
| September 30, 2017 |
1,901 |
278 |
0.66 |
0.66 |
| June 30, 2017 |
2,015 |
257 |
0.62 |
0.62 |
| March 31, 2017 |
2,274 |
294 |
0.72 |
0.72 |
| December 31, 2016 |
2,053 |
189 |
0.49 |
0.49 |
| September 30, 2016 |
1,528 |
127 |
0.45 |
0.45 |
| June 30, 2016 |
1,485 |
107 |
0.38 |
0.38 |
| March 31, 2016 |
1,772 |
162 |
0.57 |
0.57 |
| December 31, 2015 |
1,723 |
135 |
0.48 |
0.48 |
The summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions net of the associated acquisition-related transaction costs, and the impact of the sale of non-regulated assets, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of electricity and gas demand, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel, purchased power and natural gas, which are flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric utilities in the United States are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.
September 2017/September 2016: Net earnings attributable to common equity shareholders were $278 million, or $0.66 per common share, for the third quarter of 2017 compared to earnings of $127 million or $0.45 per common share, for the third quarter of 2016. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.
June 2017/June 2016: Net earnings attributable to common equity shareholders were $257 million, or $0.62 per common share, for the second quarter of 2017 compared to earnings of $107 million, or $0.38 per common share, for the second quarter of 2016. The increase was driven by earnings of $93 million at ITC, acquired in October 2016. The increase for the quarter was also due to: (i) strong performance at UNS Energy, largely due to the impact of the rate case settlement and higher electricity sales; (ii) lower Corporate and Other expenses, primarily due to $22 million in acquisition-related transaction costs associated with ITC recognized in the second quarter of 2016; (iii) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives quarter over quarter; and (iv) favourable foreign exchange associated with the translation of US dollar-denominated earnings. The increase was partially offset by higher finance charges associated with the acquisition of ITC.
March 2017/March 2016: Net earnings attributable to common equity shareholders were $294 million, or $0.72 per common share, for the first quarter of 2017 compared to earnings of $162 million, or $0.57 per common share, for the first quarter of 2016. The increase was driven by earnings of $91 million at ITC, acquired in October 2016. The increase was also due to: (i) strong performance at UNS Energy, due to the favourable settlement of matters pertaining to FERC-ordered transmission refunds of $7 million, after-tax, in January 2017 compared to $11 million, after-tax, in FERC-ordered transmission refunds in the first quarter of 2016, and higher retail rates as approved pursuant to its 2017 general rate case; (ii) acquisition-related transactions costs associated with ITC recognized in Corporate and Other expenses in the first quarter of 2016; (iii) contribution from Aitken Creek, including an after-tax $6 million unrealized gain on the mark-to-market of derivatives; and (iv) the timing of quarterly revenue and operating expenses as compared to the same period in 2016 and higher AFUDC at FortisBC Energy. The increase was partially offset by: (i) lower contribution from FortisAlberta, mainly due to lower customer rates and higher operating expenses; (ii) higher finance charges at Corporate and Other associated with the acquisitions of ITC and Aitken Creek; and (iii) unfavourable foreign exchange associated with US dollar-denominated earnings.
December 2016/December 2015: Net earnings attributable to common equity shareholders were $189 million, or $0.49 per common share, for the fourth quarter of 2016 compared to earnings of $135 million, or $0.48 per common share, for the fourth quarter of 2015. The increase in earnings was driven by contribution of $59 million from ITC, which was reduced by $22 million in expenses associated with the accelerated vesting of the Company's stock-based compensation awards as a result of the acquisition. Strong performance at most of the Corporation's regulated utilities and contribution of $6 million from Aitken Creek, net of an after-tax $3 million unrealized loss on the mark-to-market of derivatives, also contributed to higher earnings. The increase was partially offset by higher Corporate and Other expenses. Corporate and Other expenses reflected after-tax acquisition-related transaction costs of $32 million in the fourth quarter of 2016, compared to $7 million in the fourth quarter of 2015, with the remaining increase primarily due to finance charges associated with the acquisition of ITC.
OUTLOOK
The Corporation's results for 2017 will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital expenditure plan, the balance and strength of its diversified portfolio of utility businesses, as well as growth opportunities within its service territories.
Over the five-year period from 2018 through 2022, the Corporation's capital expenditure program is expected to total approximately $14.5 billion, up $1.5 billion from the prior year's plan and increasing rate base to almost $32 billion by 2022. The five-year capital expenditure program is driven by projects that improve the transmission grid, address natural gas system capacity and gas line network integrity, increase cyber protection and allow the grid to deliver cleaner energy. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends.
Fortis has extended its targeted average annual dividend growth of approximately 6% through to 2022. This dividend guidance takes into account many factors, including continued good performance of the Corporation's utilities and growth in their service territories, the expectation of reasonable outcomes for regulatory proceedings, and the successful execution of the five-year capital expenditure program.
OUTSTANDING SHARE DATA
As at November 2, 2017, the Corporation had issued and outstanding 419.5 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation's First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether such dividends have been declared.
The number of common shares of Fortis that would be issued if all outstanding stock options were converted as at November 2, 2017 is approximately 4.0 million.
Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov. The information contained on, or accessible through, any of these websites is not incorporated by reference into this document.
| FORTIS INC. |
| |
| Condensed Consolidated Interim Financial Statements |
| For the three and nine months ended September 30, 2017 and 2016 |
| (Unaudited) |
| Fortis Inc. |
| Condensed Consolidated Interim Balance Sheets (Unaudited) |
| As at |
| (in millions of Canadian dollars) |
| |
| | September 30, | December 31, |
| | 2017 | 2016 |
| | | | | |
| ASSETS | | | | |
| | | | | |
| Current assets | | | | |
| Cash and cash equivalents | $ | 252 | $ | 269 |
| Accounts receivable and other current assets | | 1,047 | | 1,127 |
| Prepaid expenses | | 124 | | 85 |
| Inventories | | 382 | | 372 |
| Regulatory assets (Note 5) | | 270 | | 313 |
| Total current assets | | 2,075 | | 2,166 |
| Other assets | | 444 | | 406 |
| Regulatory assets (Note 5) | | 2,620 | | 2,620 |
| Capital assets, net | | 29,067 | | 29,337 |
| Intangible assets, net | | 1,051 | | 1,011 |
| Goodwill | | 11,588 | | 12,364 |
| Total assets | $ | 46,845 | $ | 47,904 |
| | | | | |
| LIABILITIES AND EQUITY | | | | |
| | | | | |
| Current liabilities | | | | |
| Short-term borrowings (Note 16) | $ | 668 | $ | 1,155 |
| Accounts payable and other current liabilities | | 1,769 | | 1,970 |
| Regulatory liabilities (Note 5) | | 463 | | 492 |
| Current installments of long-term debt (Note 6) | | 997 | | 251 |
| Current installments of capital lease and finance obligations | | 65 | | 76 |
| Total current liabilities | | 3,962 | | 3,944 |
| Other liabilities | | 1,184 | | 1,279 |
| Regulatory liabilities (Note 5) | | 1,462 | | 1,691 |
| Deferred income taxes | | 3,404 | | 3,263 |
| Long-term debt (Note 6) | | 19,495 | | 20,817 |
| Capital lease and finance obligations | | 447 | | 460 |
| Total liabilities | | 29,954 | | 31,454 |
| Commitments and Contingencies (Note 18) | | | | |
| Equity | | | | |
| Common shares (1) (Note 7) | | 11,505 | | 10,762 |
| Preference shares (Note 8) | | 1,623 | | 1,623 |
| Additional paid-in capital | | 10 | | 12 |
| Accumulated other comprehensive income | | 35 | | 745 |
| Retained earnings | | 1,951 | | 1,455 |
| Shareholders' equity | | 15,124 | | 14,597 |
| Non-controlling interests | | 1,767 | | 1,853 |
| Total equity | | 16,891 | | 16,450 |
| Total liabilities and equity | $ | 46,845 | $ | 47,904 |
| | | | | |
| (1) | No par value. Unlimited authorized shares; 419.4 million and 401.5 million issued and outstanding as at September 30, 2017 and December 31, 2016, respectively |
| | |
See accompanying Notes to Condensed Consolidated Interim Financial Statements
| Fortis Inc. |
| Condensed Consolidated Interim Statements of Earnings (Unaudited) |
| For the periods ended September 30 |
| (in millions of Canadian dollars, except per share amounts) |
| | | | | |
| | Quarter Ended | Year-to-Date |
| | 2017 | 2016 | 2017 | 2016 |
| | | | | | | | | |
| Revenue | $ | 1,901 | $ | 1,528 | $ | 6,190 | $ | 4,785 |
| | | | | | | | | |
| Expenses | | | | | | | | |
| | Energy supply costs | | 478 | | 503 | | 1,756 | | 1,698 |
| | Operating | | 504 | | 439 | | 1,657 | | 1,367 |
| | Depreciation and amortization | | 290 | | 234 | | 885 | | 700 |
| Total expenses | | 1,272 | | 1,176 | | 4,298 | | 3,765 |
| Operating income | | 629 | | 352 | | 1,892 | | 1,020 |
| Other income, net (Note 11) | | 23 | | 10 | | 78 | | 35 |
| Finance charges (Note 12) | | 225 | | 164 | | 686 | | 457 |
| Earnings before income taxes | | 427 | | 198 | | 1,284 | | 598 |
| Income tax expense | | 106 | | 40 | | 314 | | 110 |
| Net earnings | $ | 321 | $ | 158 | $ | 970 | $ | 488 |
| | | | | | | | | |
| Net earnings attributable to: | | | | | | | | |
| | Non-controlling interests | $ | 27 | $ | 9 | $ | 92 | $ | 33 |
| | Preference equity shareholders | | 16 | | 22 | | 49 | | 59 |
| | Common equity shareholders | | 278 | | 127 | | 829 | | 396 |
| | $ | 321 | $ | 158 | $ | 970 | $ | 488 |
| Earnings per common share (Note 13) | | | | | | | | |
| | Basic | $ | 0.66 | $ | 0.45 | $ | 2.00 | $ | 1.40 |
| | Diluted | $ | 0.66 | $ | 0.45 | $ | 2.00 | $ | 1.39 |
| | | | | | | | | |
See accompanying Notes to Condensed Consolidated Interim Financial Statements
| Fortis Inc. |
| Condensed Consolidated Interim Statements of Comprehensive (Loss) Income (Unaudited) |
| For the periods ended September 30 |
| (in millions of Canadian dollars) |
| |
| | Quarter Ended | | Year-to-Date | |
| | 2017 | | 2016 | | 2017 | | 2016 | |
| | | | | | | | | | | | | |
| Net earnings | $ | 321 | | $ | 158 | | $ | 970 | | $ | 488 | |
| | | | | | | | | | | | | |
| Other comprehensive (loss) income | | | | | | | | | | | | |
| Unrealized foreign currency translation (losses) gains, net of hedging activities and tax | | (375 | ) | | 58 | | | (711 | ) | | (229 | ) |
| Net change in available-for-sale investment, net of tax | | - | | | 4 | | | - | | | 6 | |
| Net change in fair value of cash flow hedges, net of tax | | 3 | | | (3 | ) | | 1 | | | (3 | ) |
| | | (372 | ) | | 59 | | | (710 | ) | | (226 | ) |
| Comprehensive (loss) income | $ | (51 | ) | $ | 217 | | $ | 260 | | $ | 262 | |
| Comprehensive income (loss) attributable to: | | | | | | | | | | | | |
| | Non-controlling interests | $ | 27 | | $ | 9 | | $ | 92 | | $ | 33 | |
| | Preference equity shareholders | | 16 | | | 22 | | | 49 | | | 59 | |
| | Common equity shareholders | | (94 | ) | | 186 | | | 119 | | | 170 | |
| | $ | (51 | ) | $ | 217 | | $ | 260 | | $ | 262 | |
| | | | | | | | | | | | | |
See accompanying Notes to Condensed Consolidated Interim Financial Statements
| Fortis Inc. | |
| Condensed Consolidated Interim Statements of Cash Flows (Unaudited) | |
| For the periods ended September 30 | |
| (in millions of Canadian dollars) | |
| | | | | |
| | Quarter Ended | | Year-to-Date | |
| | 2017 | | 2016 | | 2017 | | 2016 | |
| | | | | | | | | | | | | |
| Operating activities | | | | | | | | | | | | |
| Net earnings | $ | 321 | | $ | 158 | | $ | 970 | | $ | 488 | |
| Adjustments to reconcile net earnings to net cash provided by operating activities: | | | | | | | | | | | | |
| | Depreciation - capital assets | | 261 | | | 210 | | | 794 | | | 626 | |
| | Amortization - intangible assets | | 23 | | | 17 | | | 71 | | | 52 | |
| | Amortization - other | | 6 | | | 7 | | | 20 | | | 22 | |
| | Deferred income tax expense | | 110 | | | 29 | | | 284 | | | 59 | |
| | Accrued employee future benefits | | - | | | 1 | | | 10 | | | 23 | |
| | Equity component of allowance for funds used during construction (Note 11) | | (19 | ) | | (7 | ) | | (55 | ) | | (20 | ) |
| | Other | | 16 | | | 6 | | | 5 | | | 60 | |
| Change in long-term regulatory assets and liabilities | | 102 | | | (6 | ) | | 93 | | | (38 | ) |
| Change in working capital (Note 14) | | (20 | ) | | 63 | | | (202 | ) | | 137 | |
| Cash from operating activities | | 800 | | | 478 | | | 1,990 | | | 1,409 | |
| Investing activities | | | | | | | | | | | | |
| Capital expenditures - capital assets | | (644 | ) | | (498 | ) | | (1,967 | ) | | (1,315 | ) |
| Capital expenditures - intangible assets | | (62 | ) | | (24 | ) | | (167 | ) | | (66 | ) |
| Contributions in aid of construction | | 39 | | | 15 | | | 76 | | | 33 | |
| Proceeds on sale of assets | | 1 | | | 1 | | | 4 | | | 11 | |
| Business acquisitions, net of cash acquired (Note 17) | | - | | | - | | | - | | | (318 | ) |
| Other | | (17 | ) | | (23 | ) | | (89 | ) | | (49 | ) |
| Cash used in investing activities | | (683 | ) | | (529 | ) | | (2,143 | ) | | (1,704 | ) |
| Financing activities | | | | | | | | | | | | |
| Proceeds from long-term debt, net of issue costs | | 274 | | | 223 | | | 1,030 | | | 579 | |
| Repayments of long-term debt and capital lease and finance obligations | | (105 | ) | | (215 | ) | | (140 | ) | | (324 | ) |
| Net (repayments) borrowings under committed credit facilities | | (221 | ) | | 83 | | | (397 | ) | | 596 | |
| Change in short-term borrowings, net | | 109 | | | 252 | | | (478 | ) | | (23 | ) |
| Advances from non-controlling interests | | 1 | | | 1 | | | 4 | | | 2 | |
| Issue of common shares to an institutional investor (Note 7) | | - | | | - | | | 500 | | | - | |
| Issue of common shares, net of costs and dividends reinvested | | 8 | | | 13 | | | 52 | | | 40 | |
| Redemption of preference shares (Note 8) | | - | | | (200 | ) | | - | | | (200 | ) |
| Dividends | | | | | | | | | | | | |
| | Common shares, net of dividends reinvested | | (106 | ) | | (69 | ) | | (308 | ) | | (216 | ) |
| | Preference shares | | (16 | ) | | (19 | ) | | (49 | ) | | (56 | ) |
| | Subsidiary dividends paid to non-controlling interests | | (34 | ) | | (18 | ) | | (73 | ) | | (33 | ) |
| Other | | 3 | | | - | | | 7 | | | - | |
| Cash (used in) from financing activities | | (87 | ) | | 51 | | | 148 | | | 365 | |
| Effect of exchange rate changes on cash and cash equivalents | | (9 | ) | | 5 | | | (12 | ) | | (11 | ) |
| Change in cash and cash equivalents | | 21 | | | 5 | | | (17 | ) | | 59 | |
| Cash and cash equivalents, beginning of period | | 231 | | | 296 | | | 269 | | | 242 | |
| Cash and cash equivalents, end of period | $ | 252 | | $ | 301 | | $ | 252 | | $ | 301 | |
| | | | | | | | | | | | | |
Supplementary Information to Condensed Consolidated Interim Statements of Cash Flows (Note 14)
See accompanying Notes to Condensed Consolidated Interim Financial Statements
| Fortis Inc. |
| Condensed Consolidated Interim Statements of Changes in Equity (Unaudited) |
| For the periods ended September 30 |
| (in millions of Canadian dollars) |
| |
| | Common
Shares | Preference
Shares | | Additional
Paid-In
Capital | | Accumulated
Other
Comprehensive
Income (Loss) | | Retained
Earnings | | Non-Controlling
Interests | | Total
Equity | |
| | (Note 7) | (Note 8) | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| As at January 1, 2017 | $ | 10,762 | $ | 1,623 | | $ | 12 | | $ | 745 | | $ | 1,455 | | $ | 1,853 | | $ | 16,450 | |
| Net earnings | | - | | - | | | - | | | - | | | 878 | | | 92 | | | 970 | |
| Other comprehensive loss | | - | | - | | | - | | | (710 | ) | | - | | | - | | | (710 | ) |
| Common share issues | | 743 | | - | | | (4 | ) | | - | | | - | | | - | | | 739 | |
| Stock-based compensation | | - | | - | | | 2 | | | - | | | - | | | - | | | 2 | |
| Advances from non-controlling interests | | - | | - | | | - | | | - | | | - | | | 4 | | | 4 | |
| Foreign currency translation impacts | | - | | - | | | - | | | - | | | - | | | (109 | ) | | (109 | ) |
| Subsidiary dividends paid to non-controlling interests | | - | | - | | | - | | | - | | | - | | | (73 | ) | | (73 | ) |
| Dividends declared on common shares ($0.80 per share) | | - | | - | | | - | | | - | | | (333 | ) | | - | | | (333 | ) |
| Dividends declared on preference shares | | - | | - | | | - | | | - | | | (49 | ) | | - | | | (49 | ) |
| As at September 30, 2017 | $ | 11,505 | $ | 1,623 | | $ | 10 | | $ | 35 | | $ | 1,951 | | $ | 1,767 | | $ | 16,891 | |
| | | | | | | | | | | | | | | | | | | | | |
| As at January 1, 2016 | $ | 5,867 | $ | 1,820 | | $ | 14 | | $ | 791 | | $ | 1,388 | | $ | 473 | | $ | 10,353 | |
| Net earnings | | - | | - | | | - | | | - | | | 455 | | | 33 | | | 488 | |
| Other comprehensive loss | | - | | - | | | - | | | (226 | ) | | - | | | - | | | (226 | ) |
| Common share issues | | 145 | | - | | | (4 | ) | | - | | | - | | | - | | | 141 | |
| Stock-based compensation | | - | | - | | | 2 | | | - | | | - | | | - | | | 2 | |
| Advances from non-controlling interests | | - | | - | | | - | | | - | | | - | | | 2 | | | 2 | |
| Foreign currency translation impacts | | - | | - | | | - | | | - | | | - | | | (7 | ) | | (7 | ) |
| Subsidiary dividends paid to non-controlling interests | | - | | - | | | - | | | - | | | - | | | (33 | ) | | (33 | ) |
| Redemption of preference shares | | - | | (197 | ) | | - | | | - | | | - | | | - | | | (197 | ) |
| Dividends declared on common shares ($1.15 per share) | | - | | - | | | - | | | - | | | (328 | ) | | - | | | (328 | ) |
| Dividends declared on preference shares | | - | | - | | | - | | | - | | | (59 | ) | | - | | | (59 | ) |
| Adoption of new accounting policy | | - | | - | | | - | | | - | | | 16 | | | - | | | 16 | |
| As at September 30, 2016 | $ | 6,012 | $ | 1,623 | | $ | 12 | | $ | 565 | | $ | 1,472 | | $ | 468 | | $ | 10,152 | |
See accompanying Notes to Condensed Consolidated Interim Financial Statements
1. DESCRIPTION OF BUSINESS
NATURE OF OPERATIONS
Fortis Inc. ("Fortis" or the "Corporation") is principally an international electric and gas utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated energy infrastructure, which is treated as a separate segment. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes profit and loss responsibility and is accountable for its own resource allocation.
The Corporation's reportable segments and basis of segmentation are consistent with those disclosed in the Corporation's 2016 annual audited consolidated financial statements.
REGULATED UTILITIES
The Corporation's interests in regulated electric and gas utilities are as follows:
- Regulated Electric Transmission Utility - United States: Comprised of ITC Holdings Corp. and the electric transmission operations of its regulated operating subsidiaries, which include International Transmission Company, Michigan Electric Transmission Company, LLC, ITC Midwest LLC and ITC Great Plains, LLC, (collectively "ITC"). ITC was acquired by Fortis in October 2016, with Fortis owning 80.1% of ITC and an affiliate of GIC Private Limited ("GIC") owning a 19.9% minority interest (Note 17).
- 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").
- Regulated Gas Utility - Canadian: Represents FortisBC Energy Inc. ("FortisBC Energy").
- Regulated Electric Utilities - Canadian: Comprised of FortisAlberta Inc. ("FortisAlberta"), FortisBC Inc. ("FortisBC Electric"), and Eastern Canadian Electric Utilities. Eastern Canadian Electric Utilities is comprised of Newfoundland Power Inc., Maritime Electric Company, Limited and FortisOntario Inc., and the Corporation's 49% equity investment in Wataynikaneyap Power Limited Partnership.
- Regulated Electric Utilities - Caribbean: Comprised of Caribbean Utilities Company, Ltd. ("Caribbean Utilities"), in which Fortis holds an approximate 60% controlling interest, two wholly owned utilities in the Turks and Caicos Islands, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively "Fortis Turks and Caicos"), and also includes the Corporation's 33% equity investment in Belize Electricity Limited ("Belize Electricity").
NON-REGULATED - ENERGY INFRASTRUCTURE
Non-Regulated - Energy Infrastructure is primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility ("Aitken Creek") in British Columbia. Aitken Creek was acquired by Fortis in April 2016 (Note 17).
CORPORATE AND OTHER
The Corporate and Other segment captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments.
The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These condensed consolidated interim financial statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") for interim financial statements. As a result, these condensed consolidated interim financial statements do not include all of the information and disclosures required in the annual consolidated financial statements and should be read in conjunction with the Corporation's 2016 annual audited consolidated financial statements. In management's opinion, the condensed consolidated interim financial statements include all adjustments that are of a normal recurring nature and necessary to present fairly the consolidated financial position of the Corporation.
Interim results will fluctuate due to the seasonal nature of electricity and gas demand, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel, purchased power and natural gas, which are flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters due to space-heating requirements. Earnings for the electric utilities in the United States are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.
The preparation of the condensed consolidated interim financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances.
Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary they are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.
All amounts are presented in Canadian dollars unless otherwise stated.
These condensed consolidated interim financial statements are comprised of the accounts of Fortis and its wholly owned subsidiaries and controlling ownership interests. All inter-company balances and transactions have been eliminated on consolidation, except as disclosed in Note 4.
These condensed consolidated interim financial statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation's 2016 annual audited consolidated financial statements, except as described below.
New Accounting Policies
Simplifying the Test for Goodwill Impairment
Effective January 1, 2017, the Corporation adopted Accounting Standards Update ("ASU") No. 2017-04, Simplifying the Test for Goodwill Impairment. The amendments in this update simplify the subsequent measurement of goodwill by eliminating step two in the current two-step goodwill impairment test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. The above-noted ASU was applied prospectively and did not impact the Corporation's condensed consolidated interim financial statements for the three and nine months ended September 30, 2017.
3. FUTURE ACCOUNTING PRONOUNCEMENTS
The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board ("FASB"). The following updates have been issued by FASB, but have not yet been adopted by Fortis. Any ASUs not included below were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements.
Revenue from Contracts with Customers
ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and can be applied consistently across various transactions, industries and capital markets. In 2016 a number of additional ASUs were issued that clarify implementation guidance in ASC Topic 606. This standard, and all related ASUs, is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted for annual and interim periods beginning after December 15, 2016. The Corporation has elected not to early adopt.
The new guidance permits two methods of adoption: (i) the full retrospective method; and (ii) the modified retrospective method. The Corporation expects to adopt the guidance using the modified retrospective method, under which comparative periods would not be restated and the cumulative impact of applying the standard would be recognized at the date of initial adoption, January 1, 2018.
More than 90% of the Corporation's revenue is generated from energy sales to retail and wholesale customers based on published tariff rates, as approved by the respective regulators. Fortis has assessed retail and wholesale tariff revenue and expects that the adoption of this standard will not change the Corporation's accounting policy for recognizing retail and wholesale tariff revenue and, therefore, will not have an impact on earnings. Fortis is finalizing its assessment on whether this standard will have an impact on its remaining revenue streams. The Corporation has not disclosed the expected impact of adoption on its consolidated financial statements as it is not expected to be material.
Alternative revenue programs of rate regulated utilities are outside the scope of this standard as they are not considered contracts with customers. Revenues arising from alternative revenue programs will be presented separately from revenues in scope of the new guidance. The Corporation also expects to add additional disclosures to address the requirements to provide more information regarding the nature, amount, timing and uncertainty of revenue and cash flows. Fortis is in the process of drafting these required disclosures.
As part of its effort to adopt the new revenue recognition standard, Fortis is monitoring its adoption process under its existing internal controls over financial reporting ("ICFR"), including accounting processes and the gathering and evaluation of information used in assessing the required disclosures. As the implementation process continues, Fortis will assess any necessary changes to ICFR.
Recognition and Measurement of Financial Assets and Financial Liabilities
ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial instrument. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Leases
ASU No. 2016-02 was issued in February 2016 and the amendments in this update create ASC Topic 842, Leases, and supersede lease requirements in ASC Topic 840, Leases. The main provision of ASC Topic 842 is the recognition of lease assets and lease liabilities on the balance sheet by lessees for those leases that were previously classified as operating leases. For operating leases, a lessee is required to do the following: (i) recognize a right-of-use asset and a lease liability, initially measured at the present value of the lease payments, on the balance sheet; (ii) recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and (iii) classify all cash payments within operating activities in the statement of cash flows. These amendments also require qualitative disclosures along with specific quantitative disclosures. This update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Measurement of Credit Losses on Financial Instruments
ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost
ASU No. 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Postretirement Benefit Cost, was issued in March 2017 and the amendments in this update require that an employer disaggregate the current service cost component of net benefit cost and present it in the same statement of earnings line item(s) as other employee compensation costs arising from services rendered. The other components of net benefit cost are required to be presented separately from the service cost component and outside of operating income. Additionally, the amendments allow only the service cost component to be eligible for capitalization when applicable. This update is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted. The amendments in this update should be applied retrospectively for the presentation of the net periodic benefit costs and prospectively, on and after the effective date, for the capitalization in assets of only the service cost component of net periodic benefit costs. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Targeted Improvements to Accounting for Hedging Activities
ASU No. 2017-12, Targeted Improvements to Accounting for Hedging Activities, was issued in August 2017 and the amendments in this update better align risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and presentation of hedge results. This update is effective for annual and interim periods beginning after December 15, 2018. Early adoption is permitted. The amendments in this update should be reflected as of the beginning of the fiscal year of adoption. For cash flow and net investment hedges existing at the date of adoption, the amendments should be applied as a cumulative-effect adjustment related to eliminating the separate measurement of ineffectiveness to accumulated other comprehensive income with a corresponding adjustment to the opening balance of retained earnings. Amended presentation and disclosure guidance is required only prospectively. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
4. SEGMENTED INFORMATION
Information by reportable segment is as follows:
| | REGULATED | NON-REGULATED | | | | |
| Quarter Ended | United States | Canada | | | | | | | | | |
September 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 |
| Inter-segment
eliminations |
|
Total |
| Revenue | 376 | 599 | 197 | 156 | | 153 | | 93 | 206 | | 77 | 1,857 | 47 | - | | (3 | ) | 1,901 |
| Energy supply costs | - | 199 | 54 | 38 | | - | | 33 | 117 | | 37 | 478 | - | - | | - | | 478 |
| Operating expenses | 103 | 145 | 95 | 64 | | 47 | | 21 | 32 | | 11 | 518 | 12 | (23 | ) | (3 | ) | 504 |
| Depreciation and amortization | 54 | 62 | 16 | 49 | | 47 | | 16 | 24 | | 14 | 282 | 8 | - | | - | | 290 |
| Operating income | 219 | 193 | 32 | 5 | | 59 | | 23 | 33 | | 15 | 579 | 27 | 23 | | - | | 629 |
| Other income (expenses), net | 10 | 2 | 3 | 5 | | (1 | ) | 1 | (1 | ) | 1 | 20 | 1 | 2 | | - | | 23 |
| Finance charges | 63 | 24 | 10 | 28 | | 23 | | 10 | 14 | | 4 | 176 | 2 | 47 | | - | | 225 |
| Income tax expense (recovery) | 58 | 59 | 10 | (4 | ) | - | | 3 | 6 | | - | 132 | 2 | (28 | ) | - | | 106 |
| Net earnings (loss) | 108 | 112 | 15 | (14 | ) | 35 | | 11 | 12 | | 12 | 291 | 24 | 6 | | - | | 321 |
| Non-controlling interests | 19 | - | - | 1 | | - | | - | - | | 4 | 24 | 3 | - | | - | | 27 |
| Preference share dividends | - | - | - | - | | - | | - | - | | - | - | - | 16 | | - | | 16 |
| Net earnings (loss) attributable to common equity shareholders | 89 | 112 | 15 | (15 | ) | 35 | | 11 | 12 | | 8 | 267 | 21 | (10 | ) | - | | 278 |
| Goodwill | 7,655 | 1,724 | 563 | 913 | | 227 | | 235 | 67 | | 177 | 11,561 | 27 | - | | - | | 11,588 |
| Identifiable assets | 9,694 | 6,739 | 2,470 | 5,353 | | 4,061 | | 1,942 | 2,334 | | 1,113 | 33,706 | 1,551 | 72 | | (72 | ) | 35,257 |
| Total assets | 17,349 | 8,463 | 3,033 | 6,266 | | 4,288 | | 2,177 | 2,401 | | 1,290 | 45,267 | 1,578 | 72 | | (72 | ) | 46,845 |
| Gross capital expenditures | 213 | 99 | 53 | 132 | | 109 | | 26 | 39 | | 29 | 700 | 6 | - | | - | | 706 |
| | | | | | | | | | | | | | | | | | | |
| Quarter Ended | | | | | | | | | | | | | | | | | | |
| September 30, 2016 | | | | | | | | | | | | | | | | | | |
| ($ millions) | | | | | | | | | | | | | | | | | | |
| Revenue | - | 604 | 208 | 151 | | 143 | | 88 | 211 | | 79 | 1,484 | 44 | 2 | | (2 | ) | 1,528 |
| Energy supply costs | - | 214 | 66 | 29 | | - | | 32 | 123 | | 35 | 499 | 3 | - | | 1 | | 503 |
| Operating expenses | - | 148 | 96 | 69 | | 46 | | 20 | 32 | | 11 | 422 | 12 | 8 | | (3 | ) | 439 |
| Depreciation and amortization | - | 65 | 15 | 49 | | 45 | | 15 | 23 | | 13 | 225 | 8 | 1 | | - | | 234 |
| Operating income (loss) | - | 177 | 31 | 4 | | 52 | | 21 | 33 | | 20 | 338 | 21 | (7 | ) | - | | 352 |
| Other income (expenses), net | - | 2 | 1 | 4 | | - | | 1 | - | | 1 | 9 | - | 1 | | - | | 10 |
| Finance charges | - | 24 | 10 | 33 | | 21 | | 9 | 15 | | 4 | 116 | 1 | 47 | | - | | 164 |
| Income tax expense (recovery) | - | 53 | 8 | (6 | ) | 1 | | 2 | 4 | | - | 62 | - | (22 | ) | - | | 40 |
| Net earnings (loss) | - | 102 | 14 | (19 | ) | 30 | | 11 | 14 | | 17 | 169 | 20 | (31 | ) | - | | 158 |
| Non-controlling interests | - | - | - | - | | - | | - | - | | 4 | 4 | 5 | - | | - | | 9 |
| Preference share dividends | - | - | - | - | | - | | - | - | | - | - | - | 22 | | - | | 22 |
| Net earnings (loss) attributable to common equity shareholders | - | 102 | 14 | (19 | ) | 30 | | 11 | 14 | | 13 | 165 | 15 | (53 | ) | - | | 127 |
| Goodwill | - | 1,812 | 591 | 913 | | 227 | | 235 | 67 | | 186 | 4,031 | 27 | - | | - | | 4,058 |
| Identifiable assets | - | 6,826 | 2,479 | 5,089 | | 3,789 | | 1,899 | 2,255 | | 1,137 | 23,474 | 1,465 | 280 | | (86 | ) | 25,133 |
| Total assets | - | 8,638 | 3,070 | 6,002 | | 4,016 | | 2,134 | 2,322 | | 1,323 | 27,505 | 1,492 | 280 | | (86 | ) | 29,191 |
| Gross capital expenditures | - | 198 | 59 | 86 | | 94 | | 15 | 50 | | 19 | 521 | 1 | - | | - | | 522 |
| | | | | | | | | | | | | | | | | | | |
| | REGULATED | NON-REGULATED | | | | |
| Year-to-Date | United States | Canada | | | | | | | | |
September 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 | | Inter-segment
eliminations | |
Total |
| Revenue | 1,179 | 1,609 | 661 | 832 | 448 | 291 | 789 | 227 | 6,036 | 162 | 1 | | (9 | ) | 6,190 |
| Energy supply costs | - | 545 | 203 | 292 | - | 100 | 511 | 105 | 1,756 | 1 | - | | (1 | ) | 1,756 |
| Operating expenses | 330 | 442 | 305 | 208 | 147 | 65 | 100 | 34 | 1,631 | 35 | (1 | ) | (8 | ) | 1,657 |
| Depreciation and amortization | 164 | 195 | 50 | 149 | 142 | 47 | 71 | 42 | 860 | 24 | 1 | | - | | 885 |
| Operating income | 685 | 427 | 103 | 183 | 159 | 79 | 107 | 46 | 1,789 | 102 | 1 | | - | | 1,892 |
| Other income (expenses), net | 31 | 17 | 7 | 14 | 1 | 1 | - | 3 | 74 | 1 | 4 | | (1 | ) | 78 |
| Finance charges | 193 | 76 | 31 | 86 | 69 | 28 | 42 | 14 | 539 | 4 | 144 | | (1 | ) | 686 |
| Income tax expense (recovery) | 190 | 126 | 31 | 22 | - | 10 | 17 | - | 396 | 9 | (91 | ) | - | | 314 |
| Net earnings (loss) | 333 | 242 | 48 | 89 | 91 | 42 | 48 | 35 | 928 | 90 | (48 | ) | - | | 970 |
| Non-controlling interests | 60 | - | - | 1 | - | - | - | 10 | 71 | 21 | - | | - | | 92 |
| Preference share dividends | - | - | - | - | - | - | - | - | - | - | 49 | | - | | 49 |
| Net earnings (loss) attributable to common equity shareholders | 273 | 242 | 48 | 88 | 91 | 42 | 48 | 25 | 857 | 69 | (97 | ) | - | | 829 |
| Goodwill | 7,655 | 1,724 | 563 | 913 | 227 | 235 | 67 | 177 | 11,561 | 27 | - | | - | | 11,588 |
| Identifiable assets | 9,694 | 6,739 | 2,470 | 5,353 | 4,061 | 1,942 | 2,334 | 1,113 | 33,706 | 1,551 | 72 | | (72 | ) | 35,257 |
| Total assets | 17,349 | 8,463 | 3,033 | 6,266 | 4,288 | 2,177 | 2,401 | 1,290 | 45,267 | 1,578 | 72 | | (72 | ) | 46,845 |
| Gross capital expenditures | 725 | 347 | 156 | 329 | 304 | 72 | 102 | 86 | 2,121 | 13 | - | | - | | 2,134 |
| | | | | | | | | | | | | | | | |
| Year-to-Date | | | | | | | | | | | | | | | |
| September 30, 2016 | | | | | | | | | | | | | | | |
| ($ millions) | | | | | | | | | | | | | | | |
| Revenue | - | 1,534 | 642 | 758 | 429 | 275 | 785 | 225 | 4,648 | 139 | 7 | | (9 | ) | 4,785 |
| Energy supply costs | - | 570 | 199 | 204 | - | 93 | 511 | 101 | 1,678 | 20 | - | | - | | 1,698 |
| Operating expenses | - | 447 | 289 | 209 | 142 | 63 | 101 | 35 | 1,286 | 28 | 61 | | (8 | ) | 1,367 |
| Depreciation and amortization | - | 197 | 46 | 149 | 134 | 43 | 68 | 39 | 676 | 21 | 3 | | - | | 700 |
| Operating income (loss) | - | 320 | 108 | 196 | 153 | 76 | 105 | 50 | 1,008 | 70 | (57 | ) | (1 | ) | 1,020 |
| Other income (expenses), net | - | 6 | 3 | 11 | 2 | 1 | 1 | 5 | 29 | 1 | 5 | | - | | 35 |
| Finance charges | - | 75 | 30 | 97 | 63 | 28 | 43 | 10 | 346 | 3 | 109 | | (1 | ) | 457 |
| Income tax expense (recovery) | - | 81 | 31 | 29 | 1 | 8 | 15 | - | 165 | 1 | (56 | ) | - | | 110 |
| Net earnings (loss) | - | 170 | 50 | 81 | 91 | 41 | 48 | 45 | 526 | 67 | (105 | ) | - | | 488 |
| Non-controlling interests | - | - | - | - | - | - | - | 11 | 11 | 22 | - | | - | | 33 |
| Preference share dividends | - | - | - | - | - | - | - | - | - | - | 59 | | - | | 59 |
| Net earnings (loss) attributable to common equity shareholders | - | 170 | 50 | 81 | 91 | 41 | 48 | 34 | 515 | 45 | (164 | ) | - | | 396 |
| Goodwill | - | 1,812 | 591 | 913 | 227 | 235 | 67 | 186 | 4,031 | 27 | - | | - | | 4,058 |
| Identifiable assets | - | 6,826 | 2,479 | 5,089 | 3,789 | 1,899 | 2,255 | 1,137 | 23,474 | 1,465 | 280 | | (86 | ) | 25,133 |
| Total assets | - | 8,638 | 3,070 | 6,002 | 4,016 | 2,134 | 2,322 | 1,323 | 27,505 | 1,492 | 280 | | (86 | ) | 29,191 |
| Gross capital expenditures | - | 416 | 177 | 252 | 260 | 53 | 113 | 83 | 1,354 | 17 | 10 | | - | | 1,381 |
| | | | | | | | | | | | | | | | |
Related-party and inter-company transactions
Related-party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. There were no material related-party transactions for the three and nine months ended September 30, 2017 and 2016.
Inter-company balances and inter-company transactions, including any related inter-company profit, are eliminated on consolidation, except for certain inter-company transactions between non-regulated and regulated entities in accordance with accounting standards for rate-regulated entities. The significant inter-company transactions are summarized in the following table.
| | Quarter Ended | Year-to-Date |
| | September 30 | September 30 |
| ($ millions) | 2017 | 2016 | 2017 | 2016 |
| Sale of capacity from Waneta Expansion to FortisBC Electric (Note 19) | 11 | 14 | 30 | 32 |
| Sale of energy from Belize Electric Company Limited to Belize Electricity | 11 | 12 | 25 | 26 |
| Lease of gas storage capacity and gas sales from Aitken Creek to FortisBC Energy (Note 19) | 5 | 4 | 18 | 9 |
| | | | | |
As at September 30, 2017, accounts receivable on the Corporation's condensed consolidated interim balance sheet included approximately $16 million due from Belize Electricity (December 31, 2016 - $16 million), in which Fortis holds a 33% equity investment.
5. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided below. For a detailed description of the nature of the Corporation's regulatory assets and liabilities, refer to Note 8 to the Corporation's 2016 annual audited consolidated financial statements.
| | As at | |
| | September 30, | | December 31, | |
| ($ millions) | 2017 | | 2016 | |
| Regulatory assets | | | | |
| Deferred income taxes | 1,271 | | 1,260 | |
| Employee future benefits | 523 | | 576 | |
| Deferred energy management costs | 192 | | 178 | |
| Deferred lease costs | 109 | | 97 | |
| Generation early retirement costs (1) | 103 | | - | |
| Rate stabilization accounts | 100 | | 183 | |
| Deferred operating overhead costs | 88 | | 78 | |
| Manufactured gas plant site remediation deferral | 75 | | 107 | |
| Natural gas for transportation incentives | 36 | | 40 | |
| Other regulatory assets | 393 | | 414 | |
| Total regulatory assets | 2,890 | | 2,933 | |
| Less: current portion | (270 | ) | (313 | ) |
| Long-term regulatory assets | 2,620 | | 2,620 | |
| | | | | |
| | As at | |
| | September 30, | | December 31, | |
| ($ millions) | 2017 | | 2016 | |
| Regulatory liabilities | | | | |
| Non-asset retirement obligation removal cost provision | 1,081 | | 1,194 | |
| Rate stabilization accounts | 245 | | 230 | |
| Return on equity refund liability | 179 | | 346 | |
| Energy efficiency liability | 74 | | 49 | |
| Renewable energy surcharge | 63 | | 53 | |
| Electric and gas moderator account | 58 | | 71 | |
| Employee future benefits | 44 | | 42 | |
| Other regulatory liabilities | 181 | | 198 | |
| Total regulatory liabilities | 1,925 | | 2,183 | |
| Less: current portion | (463 | ) | (492 | ) |
| Long-term regulatory liabilities | 1,462 | | 1,691 | |
| | | | | |
| (1) | Generation early retirement costs |
| | |
| | UNS Energy holds an undivided interest in the jointly owned Navajo Generating Station ("Navajo"), located on a site leased from the Navajo Nation with an initial lease term through December 2019. In June 2017 the Navajo Nation approved a land-lease extension that allows TEP and the co-owners of Navajo to continue operations through December 2019 and begin decommissioning activities thereafter. Retirement costs related to Navajo are currently being recovered through to 2030. |
| | |
| | UNS Energy owns the Sundt Generating Facility ("Sundt") and in August 2017 TEP submitted an application related to a generation modernization project at the facility, which will add generation capacity in the form of gas-fired reciprocating engines. As part of the application, TEP plans to early retire Sundt Units 1 and 2 by the end of 2020. Capital and operating costs related to Sundt Units 1 and 2 are currently being recovered through to 2028 and 2030, respectively. |
| | |
| | As a result of the planned early retirement of Navajo and Sundt Units 1 and 2, the net book value and other related retirement costs were reclassified from capital assets to regulatory assets, and as at September 30, 2017 the net book value of these assets was $103 million (US$83 million). |
| | |
6. LONG-TERM DEBT
| | | As at | |
| | | September 30, | | December 31, | |
| ($ millions) | 2017 | | 2016 | |
| Long-term debt | 20,096 | | 20,246 | |
| Long-term classification of credit facility borrowings (Note 16) | 538 | | 973 | |
| Total long-term debt (Note 15) | 20,634 | | 21,219 | |
| Less: Deferred financing costs and debt discounts | (142 | ) | (151 | ) |
| Less: Current installments of long-term debt | (997 | ) | (251 | ) |
| | 19,495 | | 20,817 | |
In March 2017 ITC entered into 1-year and 2-year unsecured term loan credit agreements at floating interest rates of a one-month LIBOR plus a spread of 0.90% and 0.65%, respectively. As at September 30, 2017, borrowings under the term loan credit agreements were US$200 million ($250 million) and US$50 million ($62 million), respectively, representing the maximum amounts available under the agreements. The net proceeds from these borrowings were used to repay credit facility borrowings and for general corporate purposes.
In April 2017 ITC issued 30-year US$200 million ($250 million) secured first mortgage bonds at 4.16%. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.
In March and May 2017, Caribbean Utilities issued US$60 million ($75 million) of unsecured notes in a dual tranche of 15-year US$40 million ($50 million) at 3.90% and 30-year US$20 million ($25 million) at 4.64%, respectively. The net proceeds from the issuances were used to finance capital expenditures and repay short-term borrowings.
In June 2017 Newfoundland Power issued 40-year $75 million first mortgage sinking fund bonds at 3.815%. The net proceeds from the issuance were used to repay credit facility borrowings and for general corporate purposes.
In August 2017 Central Hudson issued 30-year US$30 million ($37 million) unsecured notes at 4.05% and 40-year US$30 million ($37 million) unsecured notes at 4.20%. The net proceeds from the issuances were used to repay maturing long-term debt and for general corporate purposes.
In September 2017 FortisAlberta issued 30-year $200 million unsecured debentures at 3.67%. The net proceeds from the issuance were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes.
In October 2017 FortisBC Energy issued $175 million of unsecured debentures at 3.69%. The net proceeds from the issuance were used to repay short-term borrowings.
7. COMMON SHARES
Common shares issued during the period were as follows.
| | Quarter Ended | Year-to-Date |
| | September 30, 2017 | September 30, 2017 |
| | Number | | Number | |
| | of Shares | Amount | of Shares | Amount |
| | (in thousands) | ($ millions) | (in thousands) | ($ millions) |
| Balance, beginning of period | 417,885 | 11,435 | 401,486 | 10,762 |
| | Private Offering | - | - | 12,195 | 500 |
| | Dividend Reinvestment Plan | 1,368 | 61 | 4,323 | 187 |
| | Stock Option Plans | 107 | 5 | 1,062 | 39 |
| | Employee Share Purchase Plan | 83 | 4 | 360 | 16 |
| | Consumer Share Purchase Plan | 6 | - | 21 | 1 |
| | Conversion of Convertible Debentures | - | - | 2 | - |
| Balance, end of period | 419,449 | 11,505 | 419,449 | 11,505 |
| | | | | |
Private Offering
In March 2017 Fortis issued approximately 12.2 million common shares to an institutional investor, representing share consideration of $500 million at a price of $41.00 per share. The net proceeds were used to repay short-term borrowings (Note 16).
8. PREFERENCE SHARES
In September 2016 the Corporation redeemed all of the issued and outstanding $200 million 4.9% First Preference Shares, Series E at a redemption price of $25.3063 per share, being equal to $25.00 plus the amount of accrued and unpaid dividends per share. Upon redemption, approximately $3 million of after-tax issuance costs associated with the First Preference Shares, Series E were recognized in net earnings attributable to preference equity shareholders.
9. STOCK-BASED COMPENSATION PLANS
For the three and nine months ended September 30, 2017, stock-based compensation expense of approximately $4 million and $28 million, respectively, was recognized ($3 million and $18 million for the three and nine months ended September 30, 2016, respectively).
Stock Options
In February 2017 the Corporation granted 774,924 options to purchase common shares under its 2012 Stock Option Plan ("2012 Plan") at the five-day volume weighted average trading price immediately preceding the date of grant of $42.36. The options granted under the 2012 Plan are exercisable for a period not to exceed 10 years from the date of grant, expire no later than three years after the termination, death or retirement of the optionee and vest evenly over a four-year period on each anniversary of the date of grant. Directors are not eligible to receive grants of options under the 2012 Plan.
The accounting fair value of each option granted was $3.22 per option. The accounting fair value was estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions:
| | | | | Dividend yield (%) | 3.8 |
| | | | | Expected volatility (%) | 16.1 |
| | | | | Risk-free interest rate (%) | 1.2 |
| | | | | Weighted average expected life (years) | 5.6 |
| | | | | | |
Directors' Deferred Share Unit Plan
In January 2017, 8,351 Deferred Share Units ("DSUs") were granted to the Corporation's Board of Directors, representing the first quarter equity component of the Directors' annual compensation and, where opted, their first quarter component of annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. The DSUs are fully vested at the date of grant.
In April 2017, 7,846 DSUs were granted to the Corporation's Board of Directors, representing the second quarter equity component of the Directors' annual compensation and, where opted, their second quarter component of annual retainers in lieu of cash.
In July 2017, 7,491 DSUs were granted to the Corporation's Board of Directors, representing the third quarter equity component of the Directors' annual compensation and, where opted, their third quarter component of annual retainers in lieu of cash.
Performance Share Unit Plans
Year-to-date 2017, the Corporation granted 728,552 Performance Share Units ("PSUs") to senior management of the Corporation and its subsidiaries, with the exception of ITC where PSUs were granted to all employees consistent with past practice. The Corporation's PSU Plans represent a component of long-term compensation. Each PSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting and performance period, at which time a cash payment may be made. Each PSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. As at September 30, 2017, the estimated weighted average payout percentages ranged from 74% to 103%.
In the second quarter of 2017, the Corporation paid out 281,794 PSUs at $41.46 per PSU, for a total of approximately $13 million. The payout was made in respect of the PSUs granted in 2014. The payout percentage ranged from 106% to 113% and was based on the Corporation's and subsidiaries' performance over the three-year period, as determined by the respective Human Resources Committees.
Restricted Share Unit Plans
Year-to-date 2017, the Corporation granted 330,686 Restricted Share Units ("RSUs") to senior management of the Corporation and its subsidiaries, with the exception of ITC where RSUs were granted to all employees consistent with past practice. The Corporation's RSU Plan represents a component of long-term compensation. Each RSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting period, at which time a cash payment may be made. Each RSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors.
10. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group Registered Retirement Savings Plans and group 401(k) plans, for employees. The Corporation and certain subsidiaries also offer other post-employment benefit ("OPEB") plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following tables.
| | Quarter Ended September 30 | |
| | | |
| | Defined Benefit
Pension Plans | | OPEB Plans | |
| ($ millions) | 2017 | | 2016 | | 2017 | | 2016 | |
| Components of net benefit cost: | | | | | | | | |
| Service costs | 19 | | 16 | | 6 | | 5 | |
| Interest costs | 27 | | 28 | | 6 | | 5 | |
| Expected return on plan assets | (37 | ) | (36 | ) | (4 | ) | (4 | ) |
| Amortization of actuarial losses | 11 | | 12 | | - | | - | |
| Amortization of past service credits/plan amendments | - | | - | | (3 | ) | (3 | ) |
| Regulatory adjustments | 1 | | 2 | | 2 | | 2 | |
| Net benefit cost | 21 | | 22 | | 7 | | 5 | |
| | | | | | | | | |
| | Year-to-Date September 30 | |
| | | |
| | Defined Benefit
Pension Plans | | OPEB Plans | |
| ($ millions) | 2017 | | 2016 | | 2017 | | 2016 | |
| Components of net benefit cost: | | | | | | | | |
| Service costs | 58 | | 48 | | 20 | | 12 | |
| Interest costs | 85 | | 83 | | 19 | | 16 | |
| Expected return on plan assets | (113 | ) | (107 | ) | (11 | ) | (10 | ) |
| Amortization of actuarial losses | 34 | | 35 | | 1 | | 1 | |
| Amortization of past service credits/plan amendments | - | | 1 | | (9 | ) | (9 | ) |
| Regulatory adjustments | 1 | | 5 | | 4 | | 7 | |
| Net benefit cost | 65 | | 65 | | 24 | | 17 | |
| | | | | | | | | |
For the three and nine months ended September 30, 2017, the Corporation expensed $8 million and $28 million, respectively, ($7 million and $22 million for the three and nine months ended September 30, 2016, respectively) related to defined contribution pension plans.
11. OTHER INCOME, NET
| | Quarter Ended | Year-to-Date |
| | September 30 | September 30 |
| ($ millions) | 2017 | | 2016 | 2017 | 2016 |
| Equity component of allowance for funds used during construction ("AFUDC") | 19 | | 7 | 55 | 20 |
| Interest income | 4 | | 1 | 11 | 5 |
| Equity income - Belize Electricity | 1 | | 1 | 2 | 4 |
| Other | (1 | ) | 1 | 10 | 6 |
| | 23 | | 10 | 78 | 35 |
| | | | | | |
12. FINANCE CHARGES
| | Quarter Ended | | Year-to-Date | |
| | September 30 | | September 30 | |
| ($ millions) | 2017 | | 2016 | | 2017 | | 2016 | |
| Interest: | | | | | | | | |
| | Long-term debt and capital lease and finance obligations | 231 | | 147 | | 702 | | 436 | |
| | Short-term borrowings | 4 | | 1 | | 12 | | 5 | |
| Acquisition credit facilities | - | | 21 | | - | | 35 | |
| Debt component of AFUDC | (10 | ) | (5 | ) | (28 | ) | (19 | ) |
| | 225 | | 164 | | 686 | | 457 | |
| | | | | | | | | |
13. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the "if-converted" method for convertible securities.
EPS was as follows.
| | Quarter Ended September 30 |
| | 2017 | 2016 |
| | Net Earnings | Weighted | | Net Earnings | Weighted | |
| | to Common | Average | | to Common | Average | |
| | Shareholders | Shares | | Shareholders | Shares | |
| | ($ millions) | (# millions) | EPS | ($ millions) | (# millions) | EPS |
| Basic EPS | 278 | 418.6 | $ | 0.66 | 127 | 285.0 | $ | 0.45 |
| Effect of potential dilutive securities: | | | | | | | | |
| | Stock Options | - | 0.7 | | | - | 0.7 | | |
| | Preference Shares | - | - | | | 2 | 3.8 | | |
| Diluted EPS | 278 | 419.3 | $ | 0.66 | 129 | 289.5 | $ | 0.45 |
| | | | | | | | | |
| | Year-to-Date September 30 |
| | 2017 | 2016 |
| | Net Earnings | Weighted | | Net Earnings | Weighted | |
| | to Common | Average | | to Common | Average | |
| | Shareholders | Shares | | Shareholders | Shares | |
| | ($ millions) | (# millions) | EPS | ($ millions) | (# millions) | EPS |
| Basic EPS | 829 | 413.9 | $ | 2.00 | 396 | 283.7 | $ | 1.40 |
| Effect of potential dilutive securities: | | | | | | | | |
| | Stock Options | - | 0.7 | | | - | 0.7 | | |
| | Preference Shares | - | - | | | 7 | 5.0 | | |
| Diluted EPS | 829 | 414.6 | $ | 2.00 | 403 | 289.4 | $ | 1.39 |
| | | | | | | | | |
14. SUPPLEMENTARY INFORMATION TO CONDENSED CONSOLIDATED INTERIM STATEMENTS OF CASH FLOWS
| | Quarter Ended | | Year-to-Date | |
| | September 30 | | September 30 | |
| ($ millions) | 2017 | | 2016 | | 2017 | | 2016 | |
| Change in working capital: | | | | | | | | |
| Accounts receivable and other current assets | 23 | | 43 | | 29 | | 127 | |
| Prepaid expenses | (61 | ) | (30 | ) | (50 | ) | (37 | ) |
| Inventories | (36 | ) | (39 | ) | (25 | ) | 6 | |
| Regulatory assets - current portion | 15 | | 4 | | 2 | | 4 | |
| Accounts payable and other current liabilities | 14 | | 85 | | (7 | ) | 21 | |
| Regulatory liabilities - current portion | 25 | | - | | (151 | ) | 16 | |
| | (20 | ) | 63 | | (202 | ) | 137 | |
| | | | | | | | | |
| Non-cash investing and financing activities: | | | | | | | | |
| Accrued capital expenditures | 295 | | 152 | | 295 | | 152 | |
| Common share dividends reinvested | 61 | | 37 | | 186 | | 102 | |
| Transfer of deposit on business acquisition (Note 17) | - | | - | | - | | 38 | |
| Contributions in aid of construction | 32 | | 6 | | 32 | | 6 | |
| Exercise of stock options into common shares | - | | 1 | | 4 | | 4 | |
15. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS
Fair value is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value.
The three levels of the fair value hierarchy are defined as follows:
| | Level 1: | Fair value determined using unadjusted quoted prices in active markets; |
| | Level 2: | Fair value determined using pricing inputs that are observable; and |
| | Level 3: | Fair value determined using unobservable inputs only when relevant observable inputs are not available. |
The fair values of the Corporation's financial instruments, including derivatives, reflect point-in-time estimates based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future consolidated earnings or cash flows.
The following table presents, by level within the fair value hierarchy, the Corporation's assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement and there were no transfers between the levels in the periods presented. For derivative instruments, the Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions.
| | | As at | |
| | Fair value | September 30, | | December 31, | |
| ($ millions) | hierarchy | 2017 | | 2016 | |
| Assets | | | | | |
| Energy contracts subject to regulatory deferral (1) (2) (3) | Levels 1/2/3 | 5 | | 19 | |
| Energy contracts not subject to regulatory deferral (1) (2) (4) | Levels 2/3 | 13 | | 3 | |
| Interest rate swaps (5) | Level 2 | 13 | | 11 | |
| Other investments (6) | Level 1 | 80 | | 69 | |
| Total gross assets | | 111 | | 102 | |
| Less: Counterparty netting not offset on the balance sheet (7) | | (4 | ) | (9 | ) |
| Total net assets | | 107 | | 93 | |
| | | | | | |
| Liabilities | | | | | |
| Energy contracts subject to regulatory deferral (1) (2) (8) | Levels 2/3 | 37 | | 26 | |
| Energy contracts not subject to regulatory deferral (1) (2) (9) | Level 2/3 | 1 | | 9 | |
| Interest rate and total return swaps (5) | Level 2 | 7 | | 3 | |
| Total gross liabilities | | 45 | | 38 | |
| Less: Counterparty netting not offset on the balance sheet (7) | | (4 | ) | (9 | ) |
| Total net liabilities | | 41 | | 29 | |
| | | | | | |
| (1) | The fair value of the Corporation's energy contracts is recognized in accounts receivable and other current assets, long-term other assets, accounts payable and other current liabilities and long-term other liabilities. Unrealized gains and losses arising from changes in fair value of these contracts are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates as permitted by the regulators, with the exception of wholesale trading contracts and certain gas swap contracts. |
| (2) | Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude and direction of the change for each input. The impacts of changes in fair value are subject to regulatory recovery, with the exception of wholesale trading contracts and certain gas swap contracts. |
| (3) | As at September 30, 2017, includes - $3 million - level 2 and $2 million - level 3 (December 31, 2016 - $1 million - level 1, $13 million - level 2 and $5 million - level 3) |
| (4) | As at September 30, 2017, includes - $8 million - level 2 and $5 million - level 3 (December 31, 2016 - $3 million - level 3) |
| (5) | The fair value of the Corporation's interest rate and total return swaps is recognized in accounts receivable and other current assets, accounts payable and other current liabilities and long-term other liabilities. |
| (6) | Included in long-term other assets on the consolidated balance sheet. |
| (7) | Certain energy contracts are subject to legally enforceable master netting arrangements to mitigate credit risk and are netted by counterparty where the intent and legal right to offset exists. |
| (8) | As at September 30, 2017, includes $26 million - level 2 and $11 million - level 3 (December 31, 2016 - $21 million - level 2 and $5 million - level 3). |
| (9) | As at September 30, 2017, includes $1 million - level 3 (December 31, 2016 - $9 million - level 2). |
| | |
Derivative Instruments
The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments is the estimate of the amounts that the Corporation would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates.
Energy Contracts Subject to Regulatory Deferral
UNS Energy holds electricity power purchase contracts and gas swap contracts to reduce its exposure to energy price risk associated with purchased power and gas requirements. UNS Energy primarily applies the market approach for fair value measurements using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships, transmission costs and line losses. UNS Energy also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
Central Hudson holds swap contracts for electricity and natural gas to minimize price volatility by fixing the effective purchase price for the defined commodities. The fair value of the swap contracts was calculated using forward pricing provided by independent third parties.
FortisBC Energy holds gas supply contracts and fixed-price financial swaps to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The fair value of the natural gas derivatives was calculated using the present value of cash flows based on published market prices and forward curves for natural gas.
As at September 30, 2017, these energy contract derivatives were not designated as hedges; however, any unrealized gains or losses associated with changes in the fair value of the derivatives are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. These unrealized losses and gains would otherwise be recognized in earnings. As at September 30, 2017, unrealized losses of $33 million (December 31, 2016 - $19 million) were recognized in regulatory assets and unrealized gains of $1 million (December 31, 2016 - $12 million) were recognized in regulatory liabilities (Note 5).
Energy Contracts Not Subject to Regulatory Deferral
UNS Energy holds wholesale trading contracts that qualify as derivative instruments. The unrealized gains and losses on these derivative instruments are recognized in earnings, as they do not qualify for regulatory deferral. Ten percent of any realized gains on these contracts are shared with customers through UNS Energy's rate stabilization accounts.
Aitken Creek holds gas swap contracts to manage its exposure to changes in natural gas prices, to capture natural gas price spreads, and to manage the financial risk posed by physical transactions. The fair value of the gas swap contracts was calculated using forward pricing from published market sources. The unrealized gains and losses on these derivative instruments are recognized in earnings.
Interest Rate and Total Return Swaps
As at September 30, 2017, ITC held forward-starting interest rate swaps, effective December 2017 and January 2018, with notional amounts totalling $936 million and with 5-year and 10-year original terms. The agreements include a mandatory early termination provision and will be terminated no later than the effective dates. The interest rate swaps manage the interest rate risk associated with the forecasted future issuance of fixed-rate debt related to the refinancing of long-term debt due in January 2018, and amounts outstanding under the revolving credit facility and commercial paper program.
UNS Energy holds an interest rate swap, expiring in 2020, to mitigate its exposure to volatility in variable interest rates on capital lease obligations.
In August 2017 the Corporation entered into three total return swaps with a combined notional amount of $33 million and terms ranging from one to three years terminating in January 2018, 2019 and 2020. The total return swaps manage the cash flow risk associated with forecasted future cash settlements of the respective DSU and RSU obligations (Note 9).
The unrealized gains and losses on interest rate swaps are recognized in other comprehensive income and reclassified to earnings as a component of interest expense over the life of the hedged debt. The loss expected to be reclassified to earnings within the next twelve months is estimated to be approximately $4 million (net of tax). The unrealized gains and losses on the total return swaps are recognized in earnings. Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows.
Volume of Derivative Activity
As at September 30, 2017, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.
Volume(1) | Maturity
(year) | Contracts
(#) |
2017 |
2018 |
2019 |
2020 |
2021 | There-after |
| Energy contracts subject to regulatory deferral: | | | | | | | | |
| Electricity swap contracts (GWh) | 2019 | 8 | 247 | 832 | 438 | - | - | - |
| Electricity power purchase contracts (GWh) | 2018 | 24 | 458 | 177 | - | - | - | - |
| Gas swap contracts (PJ) | 2020 | 117 | 7 | 45 | 19 | 4 | - | - |
| Gas supply contract premiums (PJ) | 2024 | 125 | 40 | 82 | 31 | 28 | 22 | 43 |
| Energy contracts not subject to regulatory deferral: | | | | | | | | |
| Wholesale trading contracts (GWh) | 2018 | 19 | 1,056 | 2,300 | - | - | - | - |
| Gas swap contracts (PJ) | 2018 | 111 | 6 | 27 | - | - | - | - |
| | | | | | | | | |
| (1) | GWh means gigawatt hours and PJ means petajoules. |
| | |
Financial Instruments Not Carried At Fair Value
The following table discloses the estimated fair value measurements of the Corporation's financial instruments not carried at fair value. The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows.
| | As at |
| | September 30, 2017 | December 31, 2016 |
| ($ millions) | Carrying
Value | Estimated
Fair Value | Carrying
Value | Estimated
Fair Value |
| Long-term debt, including current portion (Note 6) (1) | 20,634 | 22,147 | 21,219 | 22,523 |
| Waneta Partnership promissory note (2) | 62 | 62 | 59 | 61 |
| | |
| (1) | Long-term debt is valued using Level 2 inputs. |
| (2) | Included in long-term other liabilities on the consolidated balance sheet |
| | |
The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.
16. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.
| Credit risk | Risk that a counterparty to a financial instrument might fail to meet its obligations under the terms of the financial instrument. |
| | |
| Liquidity risk | Risk that an entity will encounter difficulty in raising funds to meet commitments associated with financial instruments. |
| | |
| Market risk | Risk that the fair value or future cash flows of a financial instrument will fluctuate due to changes in market prices. The Corporation is exposed to foreign exchange risk, interest rate risk and commodity price risk. |
Credit Risk
For cash equivalents, accounts receivable and other current assets, and long-term other receivables, the Corporation's credit risk is generally limited to the carrying value on the consolidated balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk, which include requiring customer deposits, prepayments and/or credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts.
ITC has a concentration of credit risk as a result of approximately 70% of its revenue being derived from three primary customers. Credit risk is limited as such customers have investment-grade credit ratings. ITC also reduces its exposure to credit risk by requiring a letter of credit or cash deposit equal to the credit exposure, which is determined by a credit-scoring model and other factors.
FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. FortisAlberta reduces its credit risk exposure by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.
UNS Energy, Central Hudson, FortisBC Energy and Aitken Creek may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The Companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist. They also limit credit risk by mostly dealing with counterparties that have investment-grade credit ratings. At UNS Energy, contractual arrangements also contain certain provisions requiring counterparties to derivative instruments to post collateral under certain circumstances.
Liquidity Risk
The Corporation's consolidated financial position could be adversely affected if it, or one of its subsidiaries, fails to arrange sufficient and cost-effective financing to fund, among other things, capital expenditures, acquisitions and the repayment of maturing debt. The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the consolidated results of operations and financial position of the Corporation and its subsidiaries, conditions in capital and bank credit markets, ratings assigned by rating agencies and general economic conditions.
To help mitigate liquidity risk, the Corporation and its regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures, seasonal working capital requirements, and for general corporate purposes. In addition to its credit facilities, ITC uses commercial paper to finance its short-term cash requirements, and may use credit facility borrowings, from time to time, to repay borrowings under its commercial paper program.
The Corporation's committed corporate credit facility is used for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at September 30, 2017, over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $721 million. The combination of available credit facilities and reasonable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
As at September 30, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.3 billion, of which approximately $4.0 billion was unused, including $1.0 billion unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $4.8 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2022.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
| | | | | | As at | |
| | Regulated | | Corporate | | September 30, | | December 31, | |
| ($ millions) | Utilities | | and Other | | 2017 | | 2016 | |
| Total credit facilities (1) | 3,950 | | 1,385 | | 5,335 | | 5,976 | |
| Credit facilities utilized: | | | | | | | | |
| | Short-term borrowings (1) (2) | (668 | ) | - | | (668 | ) | (1,155 | ) |
| | Long-term debt (Note 6) (3) | (266 | ) | (272 | ) | (538 | ) | (973 | ) |
| Letters of credit outstanding | (73 | ) | (55 | ) | (128 | ) | (119 | ) |
| Credit facilities unused | 2,943 | | 1,058 | | 4,001 | | 3,729 | |
| | | | | | | | | |
| (1) | Total credit facilities and short-term borrowings as at September 30, 2017 include $286 million outstanding under ITC's commercial paper program (December 31, 2016 - $195 million). Outstanding commercial paper does not reduce available capacity under the Corporation's consolidated credit facilities. |
| (2) | The weighted average interest rate on short-term borrowings was approximately 1.5% as at September 30, 2017 (December 31, 2016 - 1.7%). |
| (3) | As at September 30, 2017, none of the credit facility borrowings were classified as current installments of long-term debt on the consolidated balance sheet (December 31, 2016 - $61 million). The weighted average interest rate on credit facility borrowings classified as long-term debt was approximately 2.4% as at September 30, 2017 (December 31, 2016 - 1.8%). |
| | |
As at September 30, 2017 and December 31, 2016, certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods. There were no material changes in credit facilities from that disclosed in the Corporation's 2016 annual audited consolidated financial statements except as follows.
In March 2017 the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares (Note 7). In July 2017 the Corporation amended its $1.3 billion unsecured committed revolving credit facility, resulting in an extension of the maturity date to July 2022. The Corporation has the option to increase the facility by $0.5 billion to $1.8 billion and, as at September 30, 2017, that option had not been exercised.
In September 2017 FortisAlberta repaid its $90 million bilateral credit facility using the proceeds from the issuance of long-term debt (Note 6). The bilateral credit facility was terminated upon repayment.
In October 2017 ITC replaced its US$1.0 billion ($1.2 billion) credit facility agreements with US$900 million ($1.1 billion) unsecured committed revolving credit facility agreements, maturing in October 2022.
Market Risk
Foreign Exchange Risk
The reporting currency of ITC, UNS Energy, Central Hudson, Caribbean Utilities, Fortis Turks and Caicos and Belize Electric Company Limited is the US dollar. The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of the Corporation's foreign subsidiaries' earnings.
As at September 30, 2017, the Corporation's corporately issued US$3,383 million (December 31, 2016 - US$3,511 million) long-term debt had been designated as an effective hedge of a portion of the Corporation's foreign net investments. As at September 30, 2017, the Corporation had approximately US$7,671 million (December 31, 2016 - US$7,250 million) in foreign net investments that were unhedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as effective hedges are recorded on the consolidated balance sheet in accumulated other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which gains and losses are also recorded on the consolidated balance sheet in accumulated other comprehensive income.
Consolidated earnings and cash flows of Fortis are impacted by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, it is estimated that a 5 cent increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CAD$1.25 as at September 30, 2017 would increase or decrease earnings per common share of Fortis by approximately 7 cents. In October 2017 the Corporation entered into forward sales contracts, with notional amounts totalling US$125 million, reducing its exposure to approximately 6 cents for every 5 cent change in the US dollar relative to the Canadian dollar. Management also continues to hedge future exchange rate fluctuations related to the Corporation's foreign net investments and US dollar-denominated earnings streams through future US dollar-denominated borrowings, and will continue to monitor the Corporation's exposure to foreign currency fluctuations on a regular basis.
Interest Rate Risk
The Corporation and most of its subsidiaries are exposed to interest rate risk associated with borrowings under variable-rate credit facilities, variable-rate long-term debt and the refinancing of long-term debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk (Note 15).
Commodity Price Risk
UNS Energy is exposed to commodity price risk associated with changes in the market price of gas, purchased power and coal. Central Hudson is exposed to commodity price risk associated with changes in the market price of electricity and gas. FortisBC Energy and Aitken Creek are exposed to commodity price risk associated with changes in the market price of gas. The risks have been reduced by entering into derivative contracts that effectively fix the price of natural gas, power and electricity purchases. These derivative instruments are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, as permitted by the regulators, for recovery from, or refund to, customers in future rates, except at Aitken Creek and wholesale trading contracts at UNS Energy where the changes in fair value are recorded in earnings (Note 15).
17. BUSINESS ACQUISITIONS
2017
Terminated Acquisition of an Interest in Waneta Dam
In May 2017 Fortis had entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia. In August 2017 BC Hydro exercised its right of first offer to acquire Teck's two-thirds interest in the Waneta Dam and the purchase agreement between Fortis and Teck was terminated, resulting in the payment of a $28 million break fee to Fortis, which was recorded in operating expenses.
2016
ITC
On October 14, 2016, Fortis and GIC acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion ($15.7 billion) on closing, including approximately US$4.8 billion ($6.3 billion) of ITC consolidated indebtedness. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC.
Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion ($9.4 billion). The net cash consideration totalled approximately US$3.5 billion ($4.7 billion) and was financed using: (i) net proceeds from the issuance of US$2.0 billion unsecured notes in October 2016; (ii) net proceeds from GIC's US$1.228 billion minority investment, which includes a shareholder note of US$199 million; and (iii) drawings of approximately US$404 million ($535 million) under the Corporation's non-revolving term senior unsecured equity bridge credit facility. On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately US$3.5 billion ($4.7 billion), based on the closing price for Fortis common shares of $40.96 and the closing foreign exchange rate of US$1.00=CAD$1.32 on October 13, 2016. The financing of the acquisition was structured to allow Fortis to maintain investment-grade credit ratings.
The following table summarizes the preliminary allocation of the purchase consideration to the assets and liabilities acquired as at October 14, 2016 based on their fair values, using an exchange rate of US$1.00=CAD$1.32. The purchase price allocation remains preliminary pending final assessment of fair value estimates, income taxes, consideration transferred, and identification of assets and liabilities.
| ($ millions) | Total | |
| | | |
| Share consideration | 4,684 | |
| Cash consideration | 4,658 | |
| Total consideration | 9,342 | |
| | | |
| Purchase consideration for 80.1% of ITC common shares | 7,721 | |
| 19.9% minority shareholder investment and shareholder note | 1,621 | |
| | 9,342 | |
| | | |
| Fair value assigned to net assets: | | |
| Current assets | 319 | |
| Long-term regulatory assets | 319 | |
| Capital assets, net | 8,345 | |
| Intangible assets, net | 392 | |
| Other long-term assets | 71 | |
| Current liabilities | (625 | ) |
| Assumed short-term borrowings | (311 | ) |
| Assumed long-term debt (including current portion) | (5,989 | ) |
| Long-term regulatory liabilities | (327 | ) |
| Deferred income taxes | (926 | ) |
| Other long-term liabilities | (166 | ) |
| | 1,102 | |
| Cash and cash equivalents | 134 | |
| Fair value of net assets acquired | 1,236 | |
| Goodwill | 8,106 | |
| | | |
The acquisition has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing on October 14, 2016.
Acquisition-related transaction costs totalled approximately $118 million ($90 million after tax) in 2016. Acquisition-related transaction costs included: (i) investment banking, legal, consulting and other fees totalling approximately $79 million ($62 million after tax) in 2016, which were included in operating expenses; and (ii) fees associated with the Corporation's acquisition credit facilities and deal-contingent interest rate swap contracts totalling approximately $39 million ($28 million after tax) in 2016, which were included in finance charges. From the date of acquisition, ITC also recognized US$21 million ($27 million) in after-tax expenses associated with the accelerated vesting of the Company's stock-based compensation awards as a result of the acquisition, of which the Corporation's share was US$17 million ($22 million).
Supplemental Pro Forma Data
The unaudited pro forma financial information below gives effect to the acquisition of ITC as if the transaction had occurred at the beginning of 2016. This pro forma data is presented for information purposes only, and does not necessarily represent the results that would have occurred had the acquisition taken place at the beginning of 2016, nor is it necessarily indicative of the results that may be expected in future periods.
| ($ millions) | 2016 |
| Pro forma revenue | 7,995 |
| Pro forma net earnings attributable to common equity shareholders (1) | 919 |
| | |
| (1) | Pro forma net earnings attributable to common equity shareholders exclude all after-tax acquisition-related transaction costs incurred by ITC and the Corporation. A pro forma adjustment has been made to net earnings for the 12 months ended December 31, 2016 to reflect the Corporation's after-tax financing costs associated with the acquisition. |
| | |
Aitken Creek
On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC from Chevron Canada Properties Ltd. for approximately $349 million (US$266 million), plus the cost of working gas inventory. The net cash purchase price was initially financed through US dollar-denominated borrowings under the Corporation's committed revolving credit facility. In December 2015 the Corporation paid a deposit of $38 million (US$29 million) as part of the purchase consideration for the transaction (Note 14).
The allocation of purchase consideration to the assets and liabilities acquired as at April 1, 2016, based on their fair values, resulted in the recognition of approximately $27 million in goodwill, which is associated with deferred income tax liabilities. The acquisition has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing on April 1, 2016. The purchase price allocation was finalized during the first quarter of 2017.
18. COMMITMENTS AND CONTINGENCIES
There were no material changes in the nature and amount of the Corporation's commitments from those disclosed in the Corporation's 2016 annual audited consolidated financial statements.
The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. The following describes the nature of the Corporation's contingencies.
Central Hudson
Prior to and after its acquisition by Fortis, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,367 asbestos cases have been raised, 1,177 remained pending as at September 30, 2017. Of the cases no longer pending against Central Hudson, 2,034 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 156 cases. The Company is presently unable to assess the validity of the outstanding asbestos lawsuits; however, based on information known to Central Hudson at this time, including the Company's experience in the settlement and/or dismissal of asbestos cases, Central Hudson believes that the costs that may be incurred in connection with the remaining lawsuits will not have a material effect on its financial position, results of operations or cash flows and, accordingly, no amount has been accrued in the condensed consolidated interim financial statements.
FHI
In April 2013 FHI and Fortis were named as defendants in an action in the B.C. Supreme Court by the Coldwater Indian Band ("Band"). The claim is in regard to interests in a pipeline right of way on reserve lands. The pipeline on the right of way was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of way and claims damages for wrongful interference with the Band's use and enjoyment of reserve lands. In May 2016 the Federal Court entered a decision dismissing the Coldwater Band's application for judicial review of the ministerial consent. In September 2017 the Federal Court of Appeal set aside the minister's consent and returned the matter to the minister for redetermination. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the condensed consolidated interim financial statements.
Fortis and ITC
Following announcement of the acquisition of ITC in February 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan ("Superior Court") and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified damages and costs, including attorneys' fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In March 2017 an agreement in principle was reached to settle the case, subject to formal documentation and court approval. In September 2017 a final settlement approval hearing was held after which the court entered an order and final judgment approving the settlement. Pursuant to the order and final judgment, the shareholder class action litigation against ITC has been dismissed.
Fortis Turks and Caicos
In September 2017 the Turks and Caicos Islands were struck by Hurricane Irma, resulting in significant damage to Fortis Turks and Caicos' transmission and distribution system. Damaged energy infrastructure interrupted the Company's ability to provide electricity service to its customers, and restoration efforts continue. The Company is currently assessing the total cost of restoration. The possibility exists that the impact of Hurricane Irma could adversely affect future earnings of Fortis Turks and Caicos as well as impair its capital assets and goodwill. The outcome cannot be reasonably determined or estimated at this time and, accordingly, no amount has been accrued in the condensed consolidated interim financial statements.
19. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period presentation. To correct the treatment of related-party transactions to be in accordance with accounting standards for rate-regulated entities, Fortis no longer eliminates related-party transactions between non-regulated and regulated entities. As a result, the sale of energy from the Waneta Expansion to FortisBC Electric and the lease of natural gas storage from Aitken Creek to FortisBC Energy are no longer eliminated, increasing both revenue and energy supply costs for the three and nine months ended September 30, 2016 by $18 million and $41 million, respectively (Note 4).