Fortis Reports Strong Second Quarter Earnings of $257 million
(firmenpresse) - ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwired) -- 07/28/17 -- Fortis Inc. ("Fortis" or the "Corporation") (TSX: FTS)(NYSE: FTS), a leader in the North American regulated electric and gas utility industry, released its second quarter results today.
"Two clear goals for us in 2017 were realizing the economic benefit of the acquisition of ITC, which remains nicely accretive, and securing a reasonable outcome in our first large rate case in Arizona since the announcement of the UNS Energy acquisition in 2013. Achievement of these two goals was a factor in delivering strong second quarter results," said Barry Perry, President and Chief Executive Officer, Fortis.
Reported Net Earnings
The Corporation reported second quarter net earnings attributable to common equity shareholders of $257 million, or $0.62 per common share, compared to $107 million, or $0.38 per common share, for the same period of 2016. On a year-to-date basis, reported net earnings attributable to common equity shareholders were $551 million, or $1.34 per common share, compared to $269 million, or $0.95 per common share, for the same period of 2016.
Adjusted Net Earnings(1)
On an adjusted basis, net earnings attributable to common equity shareholders for the second quarter were $253 million, or $0.61 per common share, an increase of $0.16 per common share over the same period of 2016. On a year-to-date basis, adjusted net earnings attributable to common equity shareholders were $540 million, or $1.31 per common share, an increase of $0.18 per common share over the same period of 2016. Adjusted net earnings no longer excludes mark-to-market adjustments related to derivative instruments, which occur in the normal course of business, as comparative information is now presented in reported net earnings.
Capital expenditure plan on track and supported by strong cash flow
Capital expenditures for the first half of 2017 were $1.4 billion and the Corporation's consolidated capital expenditure plan of $3.1 billion for 2017 is on track.
Cash flow from operating activities totalled $1.2 billion for the first half of 2017, an increase of 28% over the same period of 2016. The increase reflects higher earnings, driven by UNS Energy and ITC, partially offset by timing differences in working capital.
(1)Non-US GAAP Measures
Fortis uses financial measures that do not have a standardized meaning under generally accepted accounting principles in the United States of America ("US GAAP") and may not be comparable to similar measures presented by other entities. Fortis calculated the non-US GAAP measures by adjusting certain US GAAP measures for specific items that impact comparability but which the Corporation does not consider part of normal, ongoing operations. Refer to the Financial Highlights section of the Corporation's Management Discussion and Analysis for further discussion of these items.
Execution of growth strategy
The Corporation's capital program continues to address the energy infrastructure needs of customers. The Corporation's five-year consolidated capital expenditures through 2021 are expected to be approximately $13 billion, including more than $3.5 billion of capital expenditures at ITC.
Construction of the Tilbury liquefied natural gas ("LNG") facility expansion in British Columbia, the Corporation's largest ongoing capital project, is nearing completion. The total cost of the project is estimated at approximately $400 million, before allowance for funds used during construction and development costs. The facility is expected to be in service in the third quarter of 2017.
The Corporation continues to invest in four Multi-Value Projects ("MVPs") at ITC, which are regional electric transmission projects that have been identified by the Midcontinent Independent System Operator to address system capacity needs and reliability in various states. Approximately $228 million (US$176 million) was invested in the MVPs from the date of acquisition of ITC and an additional $135 million (US$102 million) is expected to be spent in the remainder of 2017. Three of the MVPs are expected to be completed by the end of 2018, with the fourth scheduled for completion in 2023.
In addition to the Corporation's base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. Specifically, two significant electric transmission opportunities are being pursued. The Wataynikaneyap Power project in Northwestern Ontario, which involves construction of new transmission lines to connect remote First Nation communities to the electricity grid, and the Lake Erie Connector project at ITC, which would connect the Province of Ontario to the PJM electricity market. During the quarter noteworthy milestones were achieved with respect to the Lake Erie Connector project. In May ITC completed the major permit process in Pennsylvania upon receipt of two required permits from the Pennsylvania Department of Environmental Protection, and in June approval was received from Canada's Governor in Council and the Certificate of Public Convenience and Necessity was issued by the National Energy Board.
Furthermore, the Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including the potential pipeline expansion to the proposed Woodfibre LNG export facility and further expansion of the Tilbury LNG facility. Fortis and its utilities are focused on achieving key milestones in 2017 to further advance these opportunities.
In May 2017 Fortis entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia, for $1.2 billion. Closing of the transaction is subject to customary conditions, including receipt of certain approvals and consents. In addition, BC Hydro, which owns the remaining one-third ownership interest, has a right of first offer with respect to the sale by Teck. Providing BC Hydro does not exercise its right to purchase Teck's two-thirds interest in the dam, the transaction is expected to close in the fourth quarter of 2017.
"At Fortis our portfolio of utilities is well diversified and provides numerous growth opportunities. We continue to make progress on our $13 billion five-year base capital plan with more than $3 billion to be spent throughout 2017," continued Mr. Perry. "This plan coupled with incremental opportunities for investment in our service territories, including our intention to purchase a stake in the Waneta Dam hydroelectric facility, provides high quality low risk growth for the Corporation."
Outlook
The Corporation's results for 2017 will continue to benefit from the acquisition of ITC and the impact of the rate case settlement at UNS Energy. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital plan, the balance and strength of its diversified portfolio of utility businesses, as well as growth opportunities within its service territories.
Over the five-year period through 2021, the Corporation's capital program is expected to be approximately $13 billion, increasing rate base to almost $30 billion in 2021. Fortis expects this long-term sustainable growth in rate base to support continuing growth in earnings and dividends.
Fortis has targeted average annual dividend growth of approximately 6% through 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation's utilities, the successful execution of the five-year capital expenditure program, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence.
"As we look past 2017, we are seeing upside to our five-year base capital plan at our utility businesses. The opportunities we are identifying will enhance our ability to serve customers safely and reliably, grow our rate base, and support our 6% average annual dividend growth target while maintaining a conservative payout ratio," concluded Mr. Perry.
Interim Management Discussion and Analysis
For the three and six months ended June 30, 2017
Dated July 27, 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 six months ended June 30, 2017 and the MD&A and audited consolidated financial statements for the year ended December 31, 2016 included in the Corporation's 2016 Annual Report. Financial information contained in the MD&A has been prepared in accordance with accounting principles generally accepted in the United States of America ("US GAAP") and is presented in Canadian dollars unless otherwise specified.
Fortis includes "forward-looking information" in the MD&A within the meaning of applicable Canadian securities laws and "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995, collectively referred to as "forward-looking information". Forward-looking information included in the MD&A reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities. Wherever possible, words such as "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking information, which include, without limitation: the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas ("LNG") facility and Multi-Value Projects, and additional opportunities including the pipeline expansion to the Woodfibre LNG site, the Lake Erie Connector Project and the Wataynikaneyap Project; the Corporation's forecast gross consolidated and segmented capital expenditures for 2017 and from 2017 to 2021; statements related to the acquisition of an interest in the Waneta Dam and related transmission assets, including the expected timing and benefits thereof, total expected consideration and adjustments, the expected financing of the acquisition and conditions precedent to the closing, including receipt of certain approvals and consents; the expectation that the Corporation's 2017 results will continue to benefit from the acquisition of ITC and the impact of Tucson Electric Power Company's general rate case;
the Corporation's forecast rate base over the five-year period through 2021; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; target average annual dividend growth through 2021; the expectation that subsidiary operating expenses and interest costs will be paid out of subsidiary operating cash flows; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis; the expectation that maintaining the targeted capital structure of the Corporation's regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; the expectation that cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions will be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt and advances from minority investors; expected consolidated fixed-term debt maturities and repayments over the next five years; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants throughout 2017; the intent of management to refinance certain borrowings under Corporation's and subsidiaries' long-term committed credit facilities with long-term permanent financing; the expectation that long-term debt will not be settled prior to maturity; the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements; and the expectation that any liability from current legal proceedings and claims will not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows.
Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking information, including, without limitation: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; no material capital project and financing cost overrun related to any of the Corporation's capital projects; the realization of additional opportunities; the Board of Directors exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; no significant changes in tax laws; no significant counterparty defaults; the continued competitiveness of natural gas pricing when compared with electricity and other alternative sources of energy; the continued availability of natural gas, fuel, coal and electricity supply; continuation and regulatory approval of power supply and capacity purchase contracts; the ability to fund defined benefit pension plans, earn the assumed long-term rates of return on the related assets and recover net pension costs in customer rates; no significant changes in government energy plans, environmental laws and regulations that may materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the continued tax deferred treatment of earnings from the Corporation's Caribbean operations; continued maintenance of information technology infrastructure and no material breach of cybersecurity; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital program.
Forward-looking information involves significant risks, uncertainties and assumptions. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking information. These factors should be considered carefully and undue reliance should not be placed on the forward-looking information. Risk factors which could cause results or events to differ from current expectations are detailed under the heading "Business Risk Management" in this MD&A and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2017 include, but are not limited to: uncertainty regarding the outcome of regulatory proceedings at the Corporation's utilities; uncertainty of the impact a continuation of a low interest rate environment may have on the allowed rate of return on common shareholders' equity at the Corporation's regulated utilities; the impact of fluctuations in foreign exchange rates; uncertainty related to proposed tax reform in the United States; risk associated with the impacts of less favourable economic conditions on the Corporation's results of operations; risk that the expected benefits of the acquisition of ITC may fail to materialize, or may not occur within the time periods anticipated; risk associated with the Corporation's ability to comply with Section 404(a) of the Sarbanes-Oxley Act of 2002 and the related rules of the U.S. Securities and Exchange Commission and the Public Company Accounting Oversight Board; risk associated with the completion of the Corporation's 2017 capital expenditures plan, including completion of major capital projects in the timelines anticipated and at the expected amounts; and uncertainty in the timing and access to capital markets to arrange sufficient and cost-effective financing to finance, among other things, capital expenditures and the repayment of maturing debt.
All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, Fortis disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
CORPORATE OVERVIEW
Fortis is a leader in the North American regulated electric and gas utility business, with total assets of approximately $48 billion and fiscal 2016 revenue of $6.8 billion. More than 8,000 employees of the Corporation serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.
Year-to-date June 30, 2017, the Corporation's electricity systems met a combined peak demand of 31,671 megawatts ("MW") and its gas distribution systems met a peak day demand of 1,567 terajoules. For additional information on the Corporation's regulated operations and business segments, refer to Note 1 to the Corporation's unaudited condensed consolidated interim financial statements for the three and six months ended June 30, 2017 and to the "Corporate Overview" section of the 2016 Annual MD&A.
SIGNIFICANT ITEMS
Pending Acquisition of an Interest in Waneta Dam: In May 2017 Fortis entered into an agreement with Teck Resources Limited ("Teck") to acquire a two-thirds ownership interest in the Waneta Dam and related transmission assets in British Columbia for a purchase price of $1.2 billion (the "Waneta Acquisition"), subject to certain adjustments. The Waneta Acquisition will be funded by a combination of cash on hand, debt and equity. The Waneta Dam is a renewable energy facility that is currently operated and maintained by FortisBC Inc. Under the purchase agreement, Teck Metals Ltd. will be granted a 20-year lease, with an option to extend for a further 10 years, to use the two-thirds interest in the Waneta Dam to produce power for its industrial operations in Trail, British Columbia. BC Hydro, the owner of the remaining one-third ownership interest in the Waneta Dam, has a right of first offer. Closing of the Waneta Acquisition will also be subject to certain customary conditions, including receipt of certain approvals and consents from Canadian and U.S. governmental authorities. Provided BC Hydro does not exercise its right to purchase Teck's two-thirds interest in the Waneta Dam, the transaction is expected to close in the fourth quarter of 2017.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of long-term profitable growth with the primary measure of financial performance being earnings per common share. Key financial highlights for the second quarter and year-to-date periods ended June 30, 2017 and 2016 are provided in the following table.
Revenue
The increase in revenue for the quarter was driven by the acquisition of ITC in October 2016, the impact of the rate case settlement and higher electricity sales at UNS Energy, the flow through in customer rates of higher overall energy supply costs, and favourable foreign exchange associated with the translation of US dollar-denominated revenue. Also contributing to the increase in revenue was the reversal of transmission refund accruals of $7 million ($4 million after tax), in the second quarter of 2017, due to the United States Federal Energy Regulatory Commission ("FERC") ending its investigation into the late-filed transmission service agreements at UNS Energy.
The increase in revenue year to date was driven by the same factors discussed above for the quarter, as well as $18 million ($11 million after tax) in FERC ordered transmission refunds, recognized in the first quarter of 2016, associated with late-filed transmission service agreements at UNS Energy.
Energy Supply Costs
The increase in energy supply costs for the quarter and year to date was mainly due to higher overall commodity costs. Unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs also contributed to the increase for the quarter.
Operating Expenses
The increase in operating expenses for the quarter and year to date was primarily due to the acquisition of ITC and general inflationary and employee-related cost increases. The increase was partially offset by acquisition-related transaction costs of $19 million ($15 million after tax) and $35 million ($29 million after tax) for the second quarter and year-to-date 2016, respectively, associated with the acquisition of ITC. Unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses also contributed to the increase for the quarter.
Depreciation and Amortization
The increase in depreciation and amortization for the quarter and year to date was primarily due to the acquisition of ITC and continued investment in energy infrastructure at the Corporation's other regulated utilities.
Other Income, Net
The increase in other income, net of expenses, for the quarter and year to date was primarily due to the acquisition of ITC. The favourable settlement of matters at UNS Energy pertaining to FERC ordered transmission refunds of $11 million ($7 million after tax), in the first quarter of 2017, also contributed to the year-to-date increase.
Finance Charges
The increase in finance charges for the quarter and year to date was primarily due to the acquisition of ITC, including interest expense on debt issued to complete the financing of the acquisition. The increase was partially offset by acquisition-related transaction costs of $10 million ($7 million after tax) and $14 million ($10 million after tax) for the second quarter and year-to-date 2016, respectively, associated with the acquisition of ITC.
Income Tax Expense
The increase in income tax expense for the quarter and year to date was driven by the acquisition of ITC and higher earnings before taxes. ITC's higher federal and state jurisdictional tax rates increased the total effective tax rate of Fortis.
Net Earnings Attributable to Common Equity Shareholders and Basic Earnings per Common Share
The increase in net earnings attributable to common equity shareholders for the quarter was driven by earnings of $93 million at ITC, which was acquired in October 2016. The increase for the quarter was also due to: (i) strong performance at UNS Energy, largely due to the impact of the rate case settlement and higher electricity sales; (ii) lower Corporate and Other expenses, primarily due to $22 million in acquisition-related transaction costs associated with ITC recognized in the second quarter of 2016; (iii) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives quarter over quarter; and (iv) favourable foreign exchange associated with the translation of US dollar-denominated earnings. The increase was partially offset by higher finance charges associated with the acquisition of ITC.
The increase in net earnings attributable to common equity shareholders year to date was driven by earnings of $184 million at ITC. The year-to-date increase was also due to: (i) strong performance at UNS Energy, as discussed above for the quarter; (ii) the overall favourable impact of $22 million associated with FERC ordered refunds on late-filed transmission service agreements at UNS Energy; (iii) lower Corporate and Other expenses, primarily due to $39 million in acquisition-related transaction costs associated with ITC recognized year-to-date 2016; and (iv) higher earnings from Aitken Creek related to the unrealized gain on the mark-to-market of derivatives period over period and contribution from the first quarter of 2017. The increase was partially offset by: (i) higher finance charges associated with the acquisitions of ITC and Aitken Creek; (ii) lower contribution from FortisAlberta, mainly due to lower customer rates and higher operating expenses; and (iii) lower contribution from the Caribbean, mainly due to higher finance charges and lower equity income from Belize Electricity Limited ("Belize Electricity").
Earnings per common share for the quarter and year to date were $0.24 and $0.39 higher, respectively, compared to the same periods in 2016. The impact of the above-noted items on net earnings attributable to common equity shareholders were partially offset by an increase in the weighted average number of common shares outstanding associated with the financing of the acquisition of ITC and the Corporation's dividend reinvestment and share plans.
Adjusted Net Earnings Attributable to Common Equity Shareholders and Adjusted Basic Earnings per Common Share
Fortis supplements the use of US GAAP financial measures with non-US GAAP financial measures, including adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share. The Corporation refers to these measures as non-US GAAP financial measures since they are not required by, or presented in accordance with, US GAAP. The most directly comparable US GAAP measures to adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share are net earnings attributable to common equity shareholders and basic earnings per common share, respectively.
The Corporation calculates adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes are not reflective of the underlying operations of the business. For the quarter and year-to-date periods ended June 30, 2017 and 2016, the Corporation adjusted net earnings attributable to common equity shareholders for: (i) acquisition-related transactions costs; and (ii) cumulative adjustments for regulatory decisions pertaining to prior periods considered to be outside the normal course of business for the periods presented. The Corporation no longer excludes mark-to-market adjustments related to derivative instruments at Aitken Creek, which occur in the normal course of Aitken Creek's business, in its calculation of adjusted net earnings attributable to common equity shareholders as comparative information is now presented in reported net earnings.
The adjusting items described above do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar adjustments presented by other companies.
The Corporation calculates adjusted basic earnings per common share by dividing adjusted net earnings attributable to common equity shareholders by the weighted average number of common shares outstanding.
The following table provides a reconciliation of the non-US GAAP financial measures and each of the adjusting items are discussed in the segmented results of operations for the respective reporting segments.
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 residential and commercial retail electricity sales due to warmer temperatures that increased air conditioning load. The increase was partially offset by lower short-term wholesale sales due to unplanned generation outages and lower long-term wholesale sales due to the expiration of a large contract as compared to the same period in 2016. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings.
The increase in electricity sales year to date was primarily due to the same factors discussed above for the quarter and higher short-term wholesale sales in the first quarter of 2017 as a result of more favourable commodity prices.
Gas volumes were comparable with the same periods in 2016.
Revenue
The increase in revenue for the quarter was primarily due to the impact of the rate settlement effective February 27, 2017, higher retail electricity sales, as discussed above, and approximately $22 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue. Also contributing to the increase was the reversal of $7 million (US$5 million), or $4 million (US$3 million) after-tax, in transmission refund accruals due to FERC ending its investigation into TEP's late-filed transmission agreements in the second quarter of 2017. The increase was partially offset by lower revenue related to a decrease in cost recovery rates, which has no impact on earnings.
The increase in revenue year to date was due to the same factors discussed above for the quarter, as well as approximately $18 million (US$13 million), or $11 million (US$8 million) after tax, in FERC ordered transmission refunds in the first quarter of 2016 and higher short-term wholesale sales. Also contributing to the increase year to date was approximately $5 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue.
Earnings
The increase in earnings for the quarter was primarily due to the impact of the rate case settlement, higher retail electricity sales, and the reversal of $4 million (US$3 million) in transmission refund accruals, all discussed above. Also contributing to the increase was more favourably priced long-term wholesale contracts and approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, partially offset by higher deferred income taxes.
The increase in earnings year to date was due to the same factors discussed above for the quarter, as well as approximately $11 million (US$8 million) in FERC ordered transmission refunds in the first quarter of 2016 and approximately $7 million (US$5 million) related to the favourable settlement of matters pertaining to FERC ordered transmission refunds in the first quarter of 2017. Also contributing to the increase was approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings.
CENTRAL HUDSON
Electricity Sales & Gas Volumes
The decrease in electricity sales for the quarter and year to date was primarily due to lower average consumption in the second quarter of 2017 as a result of cooler temperatures. Also contributing to the year-to-date decrease was lower average consumption in the first quarter of 2017, as a result of warmer temperatures. Gas volumes were comparable with the same periods in 2016.
Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result, do not have a material impact on annual revenue and earnings.
Revenue
The increase in revenue for the quarter and year to date was due to higher delivery revenue from increases in base electricity rates effective July 1, 2016 and the recovery from customers of higher commodity costs. Also contributing to the increase for the quarter was favourable foreign exchange of approximately $8 million associated with the translation of US dollar-denominated revenue.
Earnings
The decrease in earnings for the quarter and year to date was primarily due to the timing of unbilled revenue, which is not subject to the operation of the decoupling mechanism. Also contributing to the decrease was higher operating costs, partially offset by increases in delivery revenue. Higher-than-expected storm restoration costs incurred in the first quarter of 2017 also contributed to the decrease year to date.
REGULATED GAS UTILITY - CANADIAN
FORTISBC ENERGY
Gas Volumes
The increase in gas volumes for the quarter and year to date was primarily due to growth in the number of customers and higher average consumption by residential and commercial customers as a result of colder temperatures. Also contributing to the increase was higher volumes for transportation customers due to additional customers switching to natural gas compared to alternative fuel sources.
Revenue
The increase in revenue for the quarter and year to date was primarily due to higher gas volumes and a higher commodity cost of natural gas charged to customers, partially offset by an increase in flow-through adjustments owing to customers.
Earnings
The decrease in earnings for the quarter was primarily due to the timing of quarterly revenue and operating expenses compared to the same period in 2016 and higher operating expenses, partially offset by higher allowance for funds used during construction ("AFUDC").
The increase in earnings year to date was primarily due to higher AFUDC and the timing of quarterly revenue and operating expenses as compared to the same period in 2016, partially offset by higher operating expenses.
FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery of natural gas. As a result of the operation of regulatory deferral mechanisms, changes in consumption levels and the cost of natural gas do not materially affect earnings.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
Energy Deliveries
The increase in energy deliveries for the quarter and year to date was primarily due to higher average consumption by oil and gas customers in the second quarter of 2017 and growth in the number of residential and commercial customers. The increase year to date was partially offset by lower oil and gas activity in the first quarter of 2017.
Revenue
The increase in revenue for the quarter and year to date was primarily due to an increase in capital tracker revenue. Higher revenue related to the flow through of costs to customers and higher energy deliveries, due to customer growth and higher average consumption, also contributed to the increase, partially offset by a decrease in customer rates effective January 1, 2017 based on a combined inflation and productivity factor of negative 1.9%.
Earnings
The increase in earnings for the quarter was primarily due to an increase in capital tracker revenue and customer growth, partially offset by higher operating costs, mainly due to timing, and lower customer rates, as discussed above.
The decrease in earnings year to date was mainly due to higher operating expenses and timing differences related to certain operating expenses. Lower customer rates, partially offset by an increase in capital tracker revenue and customer growth, also contributed to the decrease year to date.
FORTISBC ELECTRIC (1)
Electricity Sales
The increase in electricity sales for the quarter and year to date was primarily due to higher average consumption as a result of favourable weather conditions.
Revenue
The increase in revenue for the quarter and year to date was primarily due to higher electricity sales and an increase in base electricity rates effective January 1, 2017, partially offset by higher flow-through adjustments owing to customers.
Earnings
The increase in earnings for the quarter and year to date was due to lower operating expenses.
Variances from regulated forecasts used to set rates for electricity revenue and power purchase costs are flowed back to customers in future rates through approved regulatory deferral mechanisms and, therefore, these variances do not have an impact on earnings.
EASTERN CANADIAN ELECTRIC UTILITIES (1)
Electricity Sales
The increase in electricity sales for the quarter and year to date was due to higher average consumption and growth in the number of customers.
Revenue
The increase in revenue for the quarter and year to date was primarily due to higher electricity sales and an increase in customer electricity rates.
Earnings
The increase in earnings for the quarter and year to date was due to lower-than-anticipated finance costs, an increase in customer electricity rates, and higher electricity sales. The recognition of the cumulative impact of a decrease in the allowed return on equity ("ROE") at Newfoundland Power, effective January 1, 2016, in the second quarter of 2016 also had a favourable impact on earnings quarter over quarter.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
Electricity Sales
Electricity sales for the quarter and year to date were comparable with the same periods in 2016.
Revenue
The increase in revenue for the quarter and year to date was mainly due to the flow through in customer electricity rates of higher fuel costs. Also contributing to the increase for the quarter is approximately $3 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue.
Earnings
The decrease in earnings for the quarter and year to date was due to higher finance costs, primarily due to lower capitalized interest, partially offset by lower operating costs. Also contributing to the decrease year to date was lower equity income from Belize Electricity.
NON-REGULATED - ENERGY INFRASTRUCTURE (1)
Energy Sales
Energy sales for the quarter and year to date were comparable with the same periods in 2016.
Revenue
The decrease in revenue for the quarter was primarily due to Aitken Creek. The increase in revenue year to date was driven by the acquisition of Aitken Creek in April 2016.
Earnings
The increase in earnings for the quarter and year to date was primarily due to higher earnings from Aitken Creek associated with the unrealized gains on the mark-to-market of derivatives period over period. Earnings from Aitken Creek in the first quarter of 2017 also contributed to the year-to-date increase.
CORPORATE AND OTHER (1)
The decrease in Corporate and Other for the quarter and year to date was primarily due to lower operating expenses, a higher income tax recovery and lower preference share dividends, partially offset by an increase in finance charges.
The decrease in operating expenses for the quarter and year to date was primarily due to acquisition-related transaction costs, including investment banking, legal, consulting and other fees, associated with the acquisition of ITC totalling approximately $19 million ($15 million after tax) and $35 million ($29 million after tax) for the second quarter and year-to-date 2016, respectively. The decrease was partially offset by higher compensation-related expenditures, general inflationary increases and ancillary expenses to support the acquisition of ITC and the Corporation's listing on the New York Stock Exchange.
The increase in finance charges for the quarter and year to date was mainly due to the acquisition of ITC in October 2016, partially offset by fees associated with the Corporation's acquisition credit facilities totalling approximately $10 million ($7 million after tax) and $14 million ($10 million after tax) for the second quarter and year-to-date 2016, respectively. Finance charges associated with the acquisition of Aitken Creek in April 2016 also contributed to the year-to-date increase.
The higher income tax recovery for the quarter and year to date was mainly due to the increase in finance charges, partially offset by lower acquisition-related transaction costs.
The decrease in preference share dividends for the quarter and year to date was due to the redemption of First Preference Shares, Series E in September 2016.
REGULATORY HIGHLIGHTS
The nature of regulation associated with each of the Corporation's regulated electric and gas utilities is generally consistent with that disclosed in the 2016 Annual MD&A. The following summarizes the significant ongoing regulatory proceedings and significant decisions and applications for the Corporation's regulated utilities in the first half of 2017.
ITC
ROE Complaints
Since 2013 two third-party complaints were filed with FERC requesting that FERC find the Midcontinent Independent System Operator ("MISO") regional base ROE for all MISO transmission owners, including some of ITC's operating subsidiaries, for the periods November 2013 through February 2015 (the "Initial Refund Period" or "Initial Complaint") and February 2015 through May 2016 (the "Second Refund Period" or "Second Complaint") to no longer be just and reasonable. In September 2016 FERC issued an order affirming the presiding Administrative Law Judge's ("ALJ") initial decision for the Initial Refund Period and setting the base ROE for the Initial Refund Period at 10.32%, with a maximum ROE of 11.35%. Additionally, the rates established by the September 2016 order will be used prospectively from the date of the order until a new approved rate is established for the Second Refund Period. FERC's September 2016 order regarding the Initial Complaint is currently under appeal by the MISO transmission owners. In June 2016 the presiding ALJ issued an initial decision for the Second Refund Period, which recommended a base ROE of 9.70%, with a maximum ROE of 10.68%, which is a recommendation to FERC.
The total estimated refund for the Initial Complaint was $158 million (US$118 million), including interest, as at December 31, 2016. The true-up of the net refund was substantially finalized in the second quarter of 2017 and paid during the first half of 2017. The total amount of the refund, including interest and the associated true-up, for the Initial Complaint was not materially different from the amount recorded as at December 31, 2016.
An order has not yet been issued by FERC in connection with the Second Complaint; however, it is expected that FERC will establish a new base ROE and range of reasonableness to calculate the refund liability for the Second Refund Period and future ROEs for ITC's operating subsidiaries. As at June 30, 2017, the estimated range of refunds for the Second Refund Period was between US$104 million to US$142 million and ITC has recognized an aggregated estimated regulatory liability of $184 million (US$142 million).
The estimated regulatory liabilities were accrued by ITC before its acquisition by Fortis. There is uncertainty regarding the final outcome of the Initial and Second Complaints and the timing of the completion of these matters. This is due, in part, to a recent court decision requiring FERC to further justify the methodology used to establish new ROEs. It is possible that the outcome of these matters could differ materially from the estimated range of refunds.
UNS Energy
General Rate Application
In February 2017 the Arizona Corporation Commission issued a rate order for new rates that took effect February 27, 2017 ("2017 Rate Order"). Provisions of the 2017 Rate Order include: (i) an increase in non-fuel base revenue of $108 million (US$81.5 million), including $20 million (US$15 million) of operating costs related to the 50.5% undivided interest in Unit 1 of Springerville Generating Station purchased by TEP in September 2016; (ii) a 7.04% return on original cost rate base, including a cost of equity of 9.75% and an embedded cost of long-term debt of 4.32%; (iii) a common equity component of capital structure of approximately 50%; and (iv) the adoption of proposed depreciation rates which reflect a reduction in the depreciable life for Unit 1 of San Juan Generating Station. Certain aspects of the general rate application, including net metering and rate design for new distributed generation customers, have been deferred to a second phase of TEP's rate case proceeding, which is currently expected to be completed in the first quarter of 2018. TEP cannot predict the outcome of this proceeding.
FERC Order
In May 2017 FERC informed TEP that no further enforcement actions were necessary regarding TEP's transmission refunds and closed the related investigation. As a result, TEP reversed the remaining $7 million (US$5 million) provision related to potential time-value refunds.
Central Hudson
General Rate Application
In July 2017 Central Hudson will file a rate case with the New York Public Service Commission ("PSC") requesting an increase in electric and nature gas rates. Included in the rate case will be a request to increase the allowed ROE to 9.5% from 9.0% and the equity component of the capital structure to 50% from 48%. An order from the PSC is expected in June 2018 with the new rates to become effective no later than July 1, 2018.
FortisAlberta
Capital Tracker Applications
In January 2017 the Alberta Utilities Commission ("AUC") issued its decision on FortisAlberta's 2015 True-Up Application approving the 2015 capital tracker revenue as filed, pending the approval of the Company's Compliance Filing, filed in February 2017. The AUC approved the Compliance Filing in May 2017. In June 2017 the Company filed its 2016 True-Up Application for 2016 capital tracker revenue and a decision is expected in the first quarter of 2018. There was no material adjustment to capital tracker revenue resulting from this application.
Generic Cost of Capital
In July 2017 the AUC established a process to determine an ROE and capital structure for 2018, 2019 and 2020. The process will commence in October 2017, with an oral hearing in March 2018. A decision is expected in the third quarter of 2018.
Next Generation Performance-Based Rate-Setting Proceeding
In December 2016 the AUC issued its decision outlining the manner in which distribution rates will be determined during the second performance-based rate-setting ("PBR") term, being the five-year period from 2018 through 2022. FortisAlberta filed a rebasing application in April 2017 to establish the going-in revenue requirement for the second PBR term, which will be used to determine the going-in rates upon which the PBR formula will be applied to establish distribution rates for 2018. A decision on this application is expected in the first quarter of 2018.
Significant Regulatory Proceedings
The following table summarizes significant ongoing regulatory proceedings, including filing dates and expected timing of decisions for the Corporation's utilities.
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between June 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 second quarter and year-to-date periods ended June 30, 2017 compared to the same periods in 2016, followed by a discussion of the nature of the variances in cash flows.
Operating Activities: Cash flow provided by operating activities was $201 million higher quarter over quarter and $259 million higher year to date compared to the same period in 2016. The increase was primarily due to higher cash earnings, driven by ITC and UNS Energy. The year-to-date increase was partially offset by timing differences in working capital, mainly due to the payment of the Initial Refund Period ROE complaint at ITC in the first quarter of 2017.
Investing Activities: Cash used in investing activities was $21 million lower quarter over quarter. The decrease was primarily due to the acquisition of Aitken Creek in the second quarter of 2016 for a net cash purchase price of $318 million, largely offset by an increase in capital expenditures. The increase in capital expenditures was driven by capital spending at ITC along with higher capital spending at most of the Corporation's regulated utilities.
Cash used in investing activities was $285 million higher year to date compared to the same period in 2016. The increase was primarily due to an increase in capital expenditures, partially offset by the acquisition of Aitken Creek, as discussed above for the quarter.
Financing Activities: Cash provided by financing activities was $353 million lower quarter over quarter. The decrease was primarily due to higher net repayments under committed credit facilities, partially offset by lower net repayments of short-term borrowings at FortisBC Energy.
Cash provided by financing activities was $79 million lower year to date compared to the same period in 2016. The decrease was primarily due to higher net repayments under both committed credit facilities and short-term borrowings. The decrease was partially offset by higher proceeds from the issuance of long-term debt, largely at ITC.
In the first quarter of 2017 approximately 12.2 million common shares of Fortis were issued to an institutional investor for proceeds of $500 million. The proceeds were used to repay short-term borrowings.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net (repayments) borrowings under committed credit facilities for the quarter and year to date compared to the same periods last year are summarized in the following tables.
Borrowings under credit facilities by the utilities are primarily in support of their respective capital expenditure programs and/or for working capital requirements. Repayments are primarily financed through the issuance of long-term debt, cash from operations and/or equity injections from Fortis. From time to time, proceeds from preference share, common share and long-term debt offerings are used to repay borrowings under the Corporation's committed credit facility.
Common share dividends paid in the second quarter of 2017 were $104 million, net of $63 million of dividends reinvested, compared to $70 million, net of $36 million of dividends reinvested, paid in the second quarter of 2016. Common share dividends paid year-to-date 2017 were $202 million, net of $125 million of dividends reinvested, compared to $147 million, net of $65 million of dividends reinvested, paid year-to-date 2016. The dividend paid per common share for each of the first and second quarters of 2017 was $0.40 compared to $0.375 for each of the first and second quarters of 2016. The weighted average number of common shares outstanding for the second quarter and year-to-date 2017 was 416.8 million and 411.5 million, respectively, compared to 283.7 million and 283.0 million for the same periods in 2016.
CONTRACTUAL OBLIGATIONS
There were no material changes in the nature and amount of the Corporation's contractual obligations during the three and six months ended June 30, 2017 from those disclosed in the 2016 Annual MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated electric and gas utilities require ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings, and advances from minority investors. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in their customer rates.
The consolidated capital structure of Fortis is presented in the following table.
Including amounts related to non-controlling interests, the Corporation's capital structure as at June 30, 2017 was 56.1% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 35.0% common shareholders' equity and 4.7% non-controlling interests (December 31, 2016 - 57.8% total debt and capital lease and finance obligations (net of cash), 4.2% preference shares, 33.3% common shareholders' equity and 4.7% non-controlling interests). The change in the Corporation's capital structure was mainly due to an increase in common equity at the Corporation due to the issuance of $500 million of common shares in March 2017, used to repay short-term borrowings.
CREDIT RATINGS
The Corporation's credit ratings are as follows.
The above-noted credit ratings reflect the Corporation's low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company. In May 2017 S&P and DBRS affirmed the Corporation's long-term corporate and unsecured debt credit ratings as presented above.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $1,428 million in gross consolidated capital expenditures by segment year-to-date 2017 is provided in the following table.
Planned capital expenditures are based on detailed forecasts of energy demand, weather, cost of labour and materials, as well as other factors, including economic conditions, which could change and cause actual expenditures to differ from those forecast.
Gross consolidated capital expenditures for 2017 are forecast to be approximately $3.1 billion. There have been no material changes in the overall expected level, nature and timing of the Corporation's significant capital projects from those that were disclosed in the 2016 Annual MD&A, with the exception of those noted below for UNS Energy and FortisBC Energy.
Capital expenditures at UNS Energy are expected to be higher than the original forecast, primarily due to capital spending related to investment in natural gas-fired facilities and distribution modernization projects. At FortisBC Energy capital expenditures are expected to be higher than the original forecast, primarily due to advancing the capital spend for the Lower Mainland System Upgrade to 2017 from 2018.
At ITC approximately $228 million (US$176 million) was invested in the Multi-Value Projects ("MVPs") from the date of acquisition and an additional $135 million (US$102 million) is expected to be spent in the second half of 2017. The MVPs consist of four regional electric transmission projects that have been identified by MISO to address system capacity needs and reliability in various states.
The Tilbury liquefied natural gas ("LNG") facility expansion ("Tilbury LNG Facility Expansion") by FortisBC Energy in British Columbia is nearing completion. Approximately $439 million, including AFUDC and development costs, has been invested to the end of the second quarter of 2017. The total cost of the project scope that is currently under construction is estimated at approximately $470 million, including approximately $70 million of AFUDC and development costs, which could be impacted depending on the date the project is considered in service for rate-making purposes. The facility includes a second LNG tank and a new liquefier, both expected to be in service in the third quarter of 2017. Key activities during the first half of 2017 included commissioning of the LNG storage tank and the continued installation of the liquefaction process area piping insulation, electrical and instrumentation cable and terminations.
Beginning with the first Order in Council ("OIC") in 2013, the Government of British Columbia has continued to support the Tilbury LNG Facility Expansion. The most recent OIC issued in March 2017 further facilitates the expansion of the facility by increasing the capital cost limit to $425 million from $400 million, before AFUDC and development costs. This latest OIC also provides greater discretion around when certain projects approved pursuant to previous OICs, including the Tilbury LNG Facility Expansion, could be added to rate base.
Over the five-year period 2017 through 2021, gross consolidated capital expenditures are expected to be approximately $13 billion. The breakdown of the capital spending has not changed materially from that disclosed in the 2016 Annual MD&A.
ADDITIONAL INVESTMENT OPPORTUNITIES
In addition to the Corporation's base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories. These additional investment opportunities, as discussed below, are not included in the Corporation's base capital expenditure forecast.
The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including a pipeline expansion to the proposed Woodfibre LNG site and a further expansion of Tilbury.
FortisBC Energy's potential pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG export facility. FortisBC Energy received an OIC from the Government of British Columbia effectively exempting this project from further regulatory approval by the British Columbia Utilities Commission. Woodfibre LNG has obtained an export license from the National Energy Board ("NEB"), which was recently extended from 25 to 40 years, and received environmental assessment approvals from the Squamish First Nation, the British Columbia Environmental Assessment Office, and the Canadian Environmental Assessment Agency. FortisBC Energy also received environmental assessment approval from the Squamish First Nation and provincial environmental assessment approval in 2016. The potential pipeline expansion was initially estimated at a total project cost, before any customer contribution, of up to $600 million; however, this estimate will be updated for final scoping, detailed construction estimates and scheduling. In November 2016 Woodfibre LNG announced the approval from its parent company, Pacific Oil & Gas Limited, which is part of the Singapore-based RGE group of companies, of the funds necessary to complete the project. This project may move forward pending additional approvals and a final investment decision by Woodfibre LNG but is not expected to be in service any earlier than 2020.
The Corporation's Tilbury LNG facility is uniquely positioned to meet customer demand for clean-burning natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment, and is relatively close to international shipping lanes. Fortis continues to have discussions with a number of potential export customers.
In January 2017 ITC received approval of a Presidential Permit from the U.S. Department of Energy for the Lake Erie Connector transmission line, which is a required approval for international border-crossing projects. Also in January, ITC received a report from Canada's NEB recommending the issuance of a Certificate of Public Convenience and Necessity ("CPCN") with prescribed conditions for the transmission line. In May 2017 ITC completed the major permit process in Pennsylvania upon receipt of two required permits from the Pennsylvania Department of Environmental Protection. In June 2017 ITC received approval from Canada's Governor in Council and the CPCN was issued by the NEB. The Lake Erie Connector project is a proposed 1,000 MW, bi-directional, high-voltage direct current underwater transmission line that would provide the first direct link between the markets of the Ontario Independent Electricity System Operator and PJM Interconnection, LLC. The project would enable transmission customers to more efficiently access energy, capacity and renewable energy credit opportunities in both markets. The project continues to advance through regulatory, operational, and economic milestones. Remaining key milestones include: receiving approval from the U.S. Army Corps of Engineers of a joint application, of which approval by the Pennsylvania Department of Environmental Protection was received in May 2017; completing project cost refinements; and securing favourable transmission service agreements with prospective counterparties. Pending achievement of key milestones, the expected in-service date for the project is late 2020.
The Wataynikaneyap Power Project continues to advance in Ontario. Wataynikaneyap Power consists of a partnership between 22 First Nations and FortisOntario, with a mandate to develop new transmission lines to connect remote First Nations communities to the electricity grid in Ontario. In 2016 the Government of Ontario designated Wataynikaneyap Power as the licensed transmission company to complete this project. FortisOntario reached an agreement with Renewable Energy Systems Canada in December 2016 to acquire its ownership interest in the Wataynikaneyap Partnership. The transaction was approved by the Ontario Energy Board ("OEB") and closed in March 2017. As a result, FortisOntario's ownership interest in the Wataynikaneyap Partnership has increased to 49%, with the remaining 51% ownership interest held by the 22 First Nations communities. The total estimated capital cost for the project, subject to final cost estimation, is approximately $1.35 billion and is expected to contribute to significant savings for the First Nations communities and result in a significant reduction in greenhouse gas emissions. In March 2017 the project reached a significant milestone with the approval by the OEB of a deferral account to recognize development costs incurred between November 2010 and the commencement of construction. In addition to environmental assessme
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