ST. JOHN–S, NEWFOUNDLAND AND LABRADOR — (Marketwired) — 11/03/17 — Fortis Inc. (“Fortis” or the “Corporation”) (TSX: FTS)(NYSE: FTS), a leader in the North American regulated electric and gas utility industry, released its third quarter results today.
“Strong third quarter results continue to demonstrate the benefit of the acquisition of electric transmission company, ITC Holdings Corp., and the reasonable outcome in our first rate case in Arizona,” said Barry Perry, President and Chief Executive Officer, Fortis.
Reported Net Earnings
The Corporation reported third quarter net earnings attributable to common equity shareholders of $278 million, or $0.66 per common share, compared to $127 million, or $0.45 per common share, for the same period in 2016. On a year-to-date basis, net earnings attributable to common equity shareholders were $829 million, or $2.00 per common share, compared to $396 million, or $1.40 per common share, for the same period in 2016.
Adjusted Net Earnings(1)
On an adjusted basis, third quarter net earnings attributable to common equity shareholders were $254 million, or $0.61 per common share, an increase of $0.07 per common share over the same period in 2016. On a year-to-date basis, adjusted net earnings attributable to common equity shareholders were $794 million, or $1.92 per common share, an increase of $0.26 per common share over the same period in 2016.
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.
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 , , or .
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.
Interim Management Discussion and Analysis
For the three and nine months ended September 30, 2017
Dated November 2, 2017
FORWARD-LOOKING INFORMATION
The following Fortis Inc. (“Fortis” or the “Corporation”) Management Discussion and Analysis (“MD&A”) has been prepared in accordance with National Instrument 51-102 – Continuous Disclosure Obligations. The MD&A should be read in conjunction with the 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.
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.
SEGMENTED RESULTS OF OPERATIONS
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
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)
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
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
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
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)
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)
(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)
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)
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)
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.
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between September 30, 2017 and December 31, 2016.
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.
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.
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.
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.
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.
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 o