Fortis Reports First Quarter Earnings of $294 million
(firmenpresse) - ST. JOHN'S, NEWFOUNDLAND AND LABRADOR -- (Marketwired) -- 05/02/17 -- Fortis Inc. ("Fortis" or the "Corporation") (TSX: FTS)(NYSE: FTS), a leader in the North American regulated electric and gas utility industry, released its first quarter results today. The Corporation's net earnings attributable to common equity shareholders for the first quarter of 2017 were $294 million, or $0.72 per common share, compared to $162 million, or $0.57 per common share, for the first quarter of 2016. The quarterly results were heavily influenced by the addition of electric transmission company ITC Holdings Corp. ("ITC"), acquired in October 2016.
On an adjusted basis, net earnings attributable to common equity shareholders for the first quarter were $281 million, or $0.69 per common share, an increase of $0.02 per common share over the first quarter of 2016. A reconciliation of adjusted net earnings and adjusted earnings per common share is provided in the Corporation's Interim Management Discussion and Analysis for the three months ended March 31, 2017.
"We had good first quarter earnings and remain on plan for the year," said Barry Perry, President and Chief Executive Officer, Fortis. "Increased earnings at UNS, driven by the rate settlement, and accretion from ITC will contribute to strong results for the remainder of 2017."
"The integration of ITC is going well. The final piece of permanent financing was put in place during the first quarter as we raised $500 million in common equity through a private placement. In addition, we are on track to deliver our capital plan for the year," said Mr. Perry.
Strong first quarter adjusted earnings per share and cash flow; capital expenditure plan on track
Execution of growth strategy
The Corporation's capital program continues to address the 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 continues on the Tilbury liquefied natural gas ("LNG") facility expansion in British Columbia, the Corporation's largest ongoing capital project, at an estimated capital cost of $400 million, before allowance for funds used during construction and development costs. During the quarter the LNG storage tank was commissioned and key components continue to be installed, with an expected in-service date of mid-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 US$119 million was invested in the MVPs from the date of acquisition of ITC and an additional US$159 million is expected to be spent in 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, 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 its Tilbury LNG facility.
Two significant electric transmission investment opportunities are being pursued. The Lake Erie Connector project at ITC would connect the Ontario and PJM Interconnection, LLC grids for the first time, and the Wataynikaneyap Power project in Northwestern Ontario involves construction of new transmission lines to connect remote First Nation communities to the electricity grid. During the quarter a significant milestone was achieved with respect to the Wataynikaneyap Power project with the approval by the Ontario Energy Board of a deferral account to recognize development costs incurred between November 2010 and the commencement of construction. Fortis and its utilities are focused on achieving key milestones in 2017 to further advance these opportunities.
Regulatory proceedings
Fortis is focused on maintaining constructive regulatory relationships and outcomes across its utilities.
During the first quarter, Tucson Electric Power Company ("TEP") received a rate order that approved new rates that took effect February 27, 2017 and included an increase in non-fuel base revenue of US$81.5 million, an allowed rate of return on common shareholder's equity ("ROE") of 9.75%, and a common equity component of capital structure of approximately 50%.
Outlook
The Corporation's results for 2017 will continue to benefit from the addition of ITC and the impact of the TEP rate case. 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 franchise regions.
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.
"Our diversified portfolio of utilities and highly executable capital plan allow us to deliver low-risk growth," commented Mr. Perry. "We remain focused on continuing to achieve strong operational and financial performance in 2017 while we continue to execute on our strategy and integrate ITC into our business."
Interim Management Discussion and Analysis
For the three months ended March 31, 2017
Dated May 1, 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 interim unaudited consolidated financial statements and notes thereto for the three months ended March 31, 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 ("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 securities laws including the Private Securities Litigation Reform Act of 1995. 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 as of May 1, 2017. 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 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 gross consolidated and segmented capital expenditures for 2017 and from 2017 to 2021; 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 Wataynikaneyap Project and the Lake Erie Connector Project; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; expected consolidated fixed-term debt maturities and repayments over the next five years; 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 borrowings under credit facilities may be required from time to time to support seasonal working capital requirements; 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; the expectation that borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends; 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 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 Corporation and its subsidiaries will remain compliant with debt covenants throughout 2017; 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 ITC shareholder litigation settlement, if approved, will not have a significant impact on the financial condition or results of operation of ITC Holdings; target average annual dividend growth through 2021; the Corporation's forecast rate base over the five-year period through 2021; and the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements.
Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking statements, 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 including natural gas related infrastructure and generation; 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 cyber-security; 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 statements involve 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 statements. These factors should be considered carefully and undue reliance should not be placed on the forward-looking statements. 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 March 31, 2017, the Corporation's electricity systems met a combined peak demand of 23,919 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 interim unaudited consolidated financial statements for the three months ended March 31, 2017 and to the "Corporate Overview" section of the 2016 Annual MD&A.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of long-term profitable growth with the primary measures of financial performance being earnings per common share and total shareholder return. Key financial highlights for the first quarters ended March 31, 2017 and 2016 are provided in the following table.
Revenue
The increase in revenue was driven by the acquisition of ITC in October 2016, contribution from Aitken Creek, the flow through in customer rates of higher overall energy supply costs, and higher electricity rates at UNS Energy, Central Hudson and FortisBC Electric. The increase was partially offset by unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.
Energy Supply Costs
The increase in energy supply costs was mainly 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 was primarily due to the acquisition of ITC and general inflationary and employee-related cost increases. The increase was partially offset by favourable foreign exchange associated with the translation of US dollar-denominated operating expenses.
Depreciation and Amortization
The increase in depreciation and amortization was primarily due to the acquisition of ITC and continued investment in energy infrastructure at the Corporation's other regulated utilities.
Other Income (Expenses), Net
The increase in other income, net of expenses, was primarily due to the acquisition of ITC and $11 million (US$8 million), or $7 million (US$5 million) after tax, related to the favourable settlement of matters pertaining to the United States Federal Energy Regulatory Commission ("FERC") ordered transmission refunds in the first quarter of 2017.
Finance Charges
The increase in finance charges was primarily due to the acquisition of ITC, including interest expense on debt issued to complete the financing of the acquisition.
Income Tax Expense
The increase in income tax expense was primarily due to the acquisition of ITC. ITC's higher federal and state jurisdictional tax rate increased the total effective tax rate of Fortis.
Net Earnings Attributable to Common Equity Shareholders and 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 Corporation defines: (i) adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes help investors better evaluate results of operations; and (ii) adjusted basic earnings per common share as adjusted net earnings attributable to common equity shareholders divided by the weighted average number of common shares outstanding. 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.
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. The adjusting items 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 measures presented by other companies.
The increase in adjusted net earnings attributable to common equity shareholders was driven by earnings of $91 million at ITC, acquired in October 2016. The increase was also due to: (i) strong performance at UNS Energy, largely due to higher retail rates as approved pursuant to its 2017 general rate case; (ii) contribution from Aitken Creek; and (iii) the timing of quarterly revenue and operating expenses as compared to the same period in 2016 and higher allowance for funds used during construction ("AFUDC") at FortisBC Energy. The increase was partially offset by: (i) lower contribution from FortisAlberta, mainly due to lower customer rates and higher operating expenses; (ii) higher Corporate and Other expenses, largely due to finance charges associated with the acquisitions of ITC and Aitken Creek; and (iii) unfavourable foreign exchange associated with US dollar-denominated earnings.
Adjusted earnings per common share were $0.02 per common share higher than the first quarter of 2016. The impact of the above-noted items on adjusted 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.
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
ITC derives the majority of its revenue from providing transmission, scheduling, control and dispatch services over its transmission systems to its customers and other entities that provide electricity to end-use customers. Revenue for the first quarter was US$298 million compared to US$280 million for the same period in 2016. The increase was primarily due to growth in rate base, partially offset by lower return on equity ("ROE").
Earnings
Earnings contribution from ITC was US$68 million ($91 million) for the first quarter of 2017.
ITC's operating earnings for the first quarter were US$80 million compared to US$65 million for the same period in 2016. Earnings for the first quarter of 2016 were reduced by US$7 million in after-tax acquisition-related expenses. Excluding the acquisition-related expenses, earnings of ITC increased by US$8 million. The increase was primarily due to growth in rate base and the unfavourable impact in the first quarter of 2016 of bonus depreciation, partially offset by a decrease in ROE.
UNS ENERGY (1)
Electricity Sales & Gas Volumes
The increase in electricity sales was primarily due to higher short-term wholesale sales as a result of more favourable commodity prices 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 was partially offset by lower residential and commercial retail electricity sales due to warmer temperatures that reduced space heating.
Gas volumes were comparable with the same period in 2016.
Revenue
The increase in revenue was mainly due to 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, an increase in retail electricity rates effective February 27, 2017, and higher short-term wholesale electricity sales. The increase was partially offset by the flow through to customers of lower purchased power and fuel supply costs, and approximately $17 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.
Earnings
The increase in earnings was primarily due to approximately $11 million (US$8 million) in FERC ordered transmission refunds in the first quarter of 2016, 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, and higher retail electricity rates as discussed above. Also contributing to the increase was more favourably priced long-term wholesale sales and lower operating expenses, partially offset by 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 was primarily due to lower average consumption as a result of warmer temperatures. Gas volumes were comparable with the same period 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 revenue and earnings.
Revenue
The increase in revenue was due to higher delivery revenue from increases in base electricity rates effective July 1, 2016 and the recovery from customers of higher gas commodity costs, partially offset by approximately $9 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue.
Earnings
The decrease in earnings was primarily due to approximately $1 million of unfavourable foreign exchange associated with the translation of US dollar-denominated earnings and higher-than-expected storm restoration costs incurred in the first quarter of 2017, partially offset by increases in delivery revenue.
REGULATED GAS UTILITY - CANADIAN
FORTISBC ENERGY
Gas Volumes
The increase in gas volumes 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 was primarily due to higher gas volumes and a higher commodity cost of natural gas charged to customers.
Earnings
The increase in earnings was primarily due to the timing of quarterly revenue and operating expenses as compared to the same period in 2016. Also contributing to the increase was higher AFUDC.
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 decrease in energy deliveries was primarily due to lower average consumption by oil and gas customers as a result of decreased oil and gas activity in Alberta. The decrease was largely offset by higher average consumption by residential, commercial and farm customers as a result of colder temperatures and growth in the numbers of customers.
Revenue
The increase in revenue was primarily due to an increase in capital tracker revenue 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 based on a combined inflation and productivity factor of negative 1.9% and lower average consumption.
Earnings
The decrease in earnings was primarily due to a decrease in customer rates, as discussed above, and higher operating expenses, partially offset by an increase in capital tracker revenue.
FORTISBC ELECTRIC (1)
Electricity Sales
The increase in electricity sales was primarily due to higher average consumption as a result of colder temperatures.
Revenue
The increase in revenue 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 were comparable with the same period in 2016.
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 was due to higher average consumption and growth in the number of customers.
Revenue
The increase in revenue was due to higher electricity sales and an increase in customer rates effective July 1, 2016 at Newfoundland Power, partially offset by the flow through in customer electricity rates of lower energy supply costs.
Earnings
Earnings were comparable with the same period in 2016.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
Electricity Sales
Electricity sales were comparable with the same period in 2016.
Revenue
The decrease in revenue was mainly due to approximately $3 million of unfavourable foreign exchange associated with the translation of US dollar-denominated revenue and the flow through in customer electricity rates of lower fuel costs.
Earnings
The decrease in earnings was primarily due to a decrease in equity income from Belize Electricity.
NON-REGULATED - ENERGY INFRASTRUCTURE (1)
Energy Sales
The decrease in energy sales was primarily due to decreased production in Belize due to lower rainfall.
Revenue
The increase in revenue was driven by the acquisition of Aitken Creek in April 2016, with revenue of $26 million recognized in the first quarter of 2017.
Earnings
The increase in earnings was driven by earnings contribution of $13 million from Aitken Creek, which includes an after-tax $6 million unrealized gain on the mark-to-market of derivatives.
CORPORATE AND OTHER (1)
Net Corporate and Other expenses in the first quarter of 2016 were impacted by acquisition-related expenses associated with ITC totalling $20 million ($17 million after tax). Acquisition-related expenses included: (i) investment banking, legal, consulting and other fees totalling approximately $16 million ($14 million after tax), which were included in operating expenses; and (ii) fees associated with the Corporation's acquisition credit facilities totalling approximately $4 million ($3 million after tax), which were included in finance charges.
Excluding the above-noted items, net Corporate and Other expenses were $47 million for the first quarter of 2017 compared to $34 million for the same period last year. The increase was primarily due to higher finance charges, a decrease in other income, and higher operating expenses, partially offset by a higher income tax recovery and lower preference share dividends.
The increase in finance charges was mainly due to the acquisitions of ITC and Aitken Creek in October 2016 and April 2016, respectively. The decrease in other income was primarily due to the release of provisions on the wind-up of a partnership in the first quarter of 2016. The increase in operating expenses was mainly due to 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 higher income tax recovery was mainly related to the increase in Corporate and Other finance charges. The decrease in preference share dividends 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 quarter 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.
During the first quarter of 2017, ITC provided a refund of US$121 million, including interest, for the Initial Refund Period. This refund is subject to a final true-up pursuant to the refund process which is expected to be finalized during the second quarter of 2017. As at March 31, 2017, the estimated range of refunds for the Second Refund Period was between US$103 million to US$140 million and ITC has recognized an aggregated estimated regulatory liability of US$140 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 US$81.5 million, including 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 expected to be completed by the end of 2017. TEP cannot predict the outcome of this proceeding.
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. A decision is expected in the second half of 2017. The Company is required by the AUC to file its 2016 Capital Tracker True-Up Application in June 2017.
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. The parameters of the second PBR term are generally consistent with the first PBR term except for: (i) the productivity factor, which is set at 0.3% for the second PBR term, as compared to 1.16% for the first PBR term; and (ii) the capital tracker mechanism, which will be replaced by two incremental capital funding mechanisms in the second PBR term. The capital funding mechanisms will include a capital tracker mechanism similar to the first PBR term for incremental capital not previously included in FortisAlberta's rate base, and a K-bar mechanism, submitted annually through the annual rates application, for all capital included in FortisAlberta's going-in rate base. 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 second half of 2017.
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 March 31, 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 three months ended March 31, 2017 compared to the same period in 2016, followed by a discussion of the nature of the variances in cash flows.
Operating Activities: Cash flow provided by operating activities was $58 million higher quarter over quarter. The increase was primarily due to higher earnings, driven by the acquisition of ITC, partially offset by changes in working capital. The net decrease in working capital was mainly due to the payment of US$121 million related to the Initial Refund Period ROE complaint.
Investing Activities: Cash used in investing activities was $306 million higher quarter over quarter. The increase was driven by capital expenditures at ITC. Higher capital spending at FortisAlberta and FortisBC Energy also contributed to the increase.
Financing Activities: Cash provided by financing activities was $274 million higher quarter over quarter. The increase was driven by higher proceeds from the issuance of long-term debt, largely at ITC.
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.
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 compared to the same period 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 first quarter of 2017 totalled $98 million, net of $62 million of dividends reinvested, compared to $77 million, net of $29 million of dividends reinvested, paid in the first quarter of 2016. The dividend paid per common share was $0.40 in the first quarter of 2017 compared to $0.375 in the first quarter of 2016. The weighted average number of common shares outstanding for the first quarter of 2017 was 406.2 million compared to 282.4 million for the first quarter of 2016.
CONTRACTUAL OBLIGATIONS
The Corporation's consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter, as at March 31, 2017, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2016 Annual MD&A. There were no material changes in the nature and amount of the Corporation's contractual obligations during the three months ended March 31, 2017 from those disclosed in the 2016 MD&A.
For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program not included in the preceding Contractual Obligations table, refer to the "Capital Expenditure Program" section of this 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 March 31, 2017 was 56.5% total debt and capital lease and finance obligations (net of cash), 4.1% preference shares, 34.7% 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, used to repay short-term borrowings.
CREDIT RATINGS
As at March 31, 2017, the Corporation's credit ratings were 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.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $709 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 $3.0 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.
At ITC approximately US$119 million was invested in the Multi-Value Projects ("MVPs") from the date of acquisition and an additional US$159 million is expected to be spent in 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.
FortisBC Energy's construction of the Tilbury liquefied natural gas ("LNG") facility expansion ("Tilbury LNG Facility Expansion") in British Columbia is ongoing. Approximately $424 million, including AFUDC and development costs, has been invested to the end of the first 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 to be in service in mid-2017. Key activities during the first quarter 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 continues 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 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 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 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 National Energy Board recommending the issuance of a Certificate of Public Convenience and Necessity ("CPCN") with prescribed conditions for the transmission line. The Lake Erie Connector project at ITC 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 ("PJM"). 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. Key milestones for 2017 include: receiving final approval of the CPCN from Canada's Governor in Council with a decision expected on or before June 30, 2017; receiving approval from the U.S. Army Corps of Engineers and Pennsylvania Department of Environmental Protection in a joint application; completing project cost refinements; and securing favourable transmission service agreements with prospective counterparties. Pending achievement of key milestones, the expected in-service date for the project is late 2020.
The Wataynikaneyap Power Project continues to advance in Ontario. Wataynikaneyap Power consists of a partnership between 22 First Nations and FortisOntario, with a mandate to develop new transmission lines to connect remote First Nations communities to the electricity grid in Ontario. In 2016 the Government of Ontario designated Wataynikaneyap Power as the licensed transmission company to complete this project. FortisOntario reached an agreement with Renewable Energy Systems Canada in December 2016 to acquire its ownership interest in the Wataynikaneyap Partnership. The transaction was approved by the Ontario Energy Board ("OEB") and closed in March 2017. As a result, FortisOntario's ownership interest in the Wataynikaneyap Partnership has increased to 49%, with the remaining 51% ownership interest held by the 22 First Nations communities. The total estimated capital cost for the project, subject to final cost estimation, is approximately $1.35 billion and is expected to contribute to significant savings for the First Nations communities and result in a significant reduction in greenhouse gas emissions. In March 2017 the project reached a significant milestone with the approval by the OEB of a deferral account to recognize development costs incurred between November 2010 and the commencement of construction. In addition to environmental assessments underway, other regulatory approvals are currently being sought and the next regulatory milestone will be the preparation and filing of the leave to construct with the OEB. Construction will commence pending the receipt of permits, approvals and a cost-sharing agreement between the federal and provincial government.
The Corporation also has other significant opportunities that have not yet been included in the Corporation's capital expenditure forecast including, but not limited to: transmission investment opportunities at ITC; investment opportunities in New York Transco, LLC to address electric transmission constraints in New York State at CH Energy; renewable energy alternatives, gas-fired generation and transmission investments at UNS Energy; and further gas infrastructure opportunities at FortisBC Energy.
CASH FLOW REQUIREMENTS
At the subsidiary level, it is expected that operating expenses and interest costs will generally be paid out of subsidiary operating cash flows, with varying levels of residual cash flows available for subsidiary capital expenditures and/or dividend payments to Fortis. Borrowings under credit facilities may be required from time to time to support seasonal working capital requirements. Cash required to complete subsidiary capital expenditure programs is also expected to be financed from a combination of borrowings under credit facilities, long-term debt offerings and equity injections from Fortis.
The Corporation's ability to service its debt obligations and pay dividends on its common and preference shares is dependent on the financial results of the operating subsidiaries and the related cash payments from these subsidiaries. Certain regulated subsidiaries may be subject to restrictions that may limit their ability to distribute cash to Fortis. These include restrictions by certain regulators limiting the amount of annual dividends and restrictions by certain lenders limiting the amount of debt to total capitalization at the subsidiaries. In addition, there are practical limitations on using the net assets of each of the Corporation's regulated operating subsidiaries to pay dividends based on management's intent to maintain the regulator-approved capital structures for each of its regulated operating subsidiaries. The Corporation does not expect that maintaining the targeted capital structures of its regulated operating subsidiaries will have an impact on its ability to pay dividends in the foreseeable future.
Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt, and advances from minority investors. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends.
In November 2016 Fortis filed a short-form base shelf prospectus, under which the Corporation may issue common or preference shares, subscription receipts or debt securities in an aggregate principal amount of up to $5 billion during the 25-month life of the base shelf prospectus. In March 2017 Fortis issued $500 million common equity and in December 2016 issued $500 million unsecured notes at 2.85%, both under the base shelf prospectus.
In April 2017 ITC issued 30-year US$200 million 4.16% secured first mortgage bonds. The net proceeds from the issuance was used to repay credit facility borrowings and for general corporate purposes.
As at March 31, 2017, management expects consolidated fixed-term debt maturities and repayments to average approximately $740 million annually over the next five years. The combination of available credit facilities and manageable annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
Fortis and its subsidiaries were in compliance with debt covenants as at March 31, 2017 and are expected to remain compliant throughout 2017.
CREDIT FACILITIES
As at March 31, 2017, the Corporation and its subsidiaries had consolidated credit facilities of approximately $5.4 billion, of which approximately $3.8 billion was unused, including $909 million unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with large banks in Canada and the United States, with no one bank holding more than 20% of these facilities. Approximately $5.0 billion of the total credit facilities are committed facilities with maturities ranging from 2017 through 2021.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
As at March 31, 2017 and December 31, 2016, certain borrowings under the Corporation's and subsidiaries' long-term committed credit facilities were classified as long-term debt. It is management's intention to refinance these borrowings with long-term permanent financing during future periods. The only significant change in credit facilities from that disclosed in the Corporation's 2016 Annual MD&A is as follows.
In March 2017 the Corporation repaid short-term borrowings using net proceeds from the issuance of common shares.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $119 million as at March 31, 2017 (December 31, 2016 - $119 million), the Corporation had no off-balance sheet arrangements that are reasonably likely to materially affect liquidity or the availability of, or requirements for, capital resources.
BUSINESS RISK MANAGEMENT
Year-to-date 2017, the business risks of the Corporation were generally consistent with those disclosed in the Corporation's 2016 Annual MD&A, including certain risks, as disclosed below, and an update to those risks, where applicable.
Regulatory Risk: For further information, refer to the "Regulatory Highlights" section of this MD&A.
Capital Resources and Liquidity Risk - Credit Ratings: In April 2017 S&P upgraded TEP's unsecured debt rating to 'A-' from 'BBB+' with a stable outlook. For a discussion on the Corporation's credit ratings refer to the "Liquidity and Capital Resources" section of this MD&A.
Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at March 31, 2017, the fair value of the Corporation's consolidated defined benefit pension and other post-employment benefit plan assets was $2,975 million compared to $2,899 million as at December 31, 2016.
CHANGES IN ACCOUNTING POLICIES
The interim consolidated financial statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation's 2016 annual audited consolidated financial statements, except as described below.
Simplifying the Test for Goodwill Impairment
Effective January 1, 2017, the Corporation adopted Accounting Standards Update ("ASU") No. 2017-04, Simplifying the Test for Goodwill Impairment. The amendments in this update simplify the subsequent measurement of goodwill by eliminating step two in the current two-step goodwill impairment test. An entity will apply a one-step quantitative test and record the amount of goodwill impairment as the excess of a reporting unit's carrying amount over its fair value, not to exceed the total amount of goodwill allocated to the reporting unit. The new guidance does not amend the optional qualitative assessment of goodwill impairment. The above-noted ASU was applied prospectively and did not impact the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 2017.
FUTURE ACCOUNTING PRONOUNCEMENTS
The Corporation considers the applicability and impact of all ASUs issued by the Financial Accounting Standards Board ("FASB"). The following updates have been issued by FASB, but have not yet been adopted by Fortis. Any ASUs not included below were assessed and determined to be either not applicable to the Corporation or are not expected to have a material impact on the consolidated financial statements.
Revenue from Contracts with Customers
ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification ("ASC") Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and can be applied consistently across various transactions, industries and capital markets. In 2016 a number of additional ASUs were issued that clarify implementation guidance in ASC Topic 606. This standard, and all related ASUs, is effective for annual and interim periods beginning after December 15, 2017. Early adoption is permitted for annual and interim periods beginning after December 15, 2016. The Corporation has elected not to early adopt.
The new guidance permits two methods of adoption: (i) the full retrospective method, under which comparative periods would be restated, and the cumulative impact of applying the standard would be recognized as at January 1, 2017, the earliest period presented; and (ii) the modified retrospective method, under which comparative periods would not be restated and the cumulative impact of applying the standard would be recognized at the date of initial adoption, January 1, 2018. The Corporation expects to use the modified retrospective approach; however, it continues to monitor interpretative issues that remain outstanding. Any significant developments in interpretative issues could change the Corporation's expected method of adoption.
The majority of the Corporation's revenue is generated from energy sales to retail customers based on published tariff rates, as approved by the respective regulators, and from transmission services and is considered to be in the scope of ASU No. 2014-09. Fortis does not expect that the adoption of this standard, and all related ASUs, will have a material impact on the recognition of revenue; however, the Corporation does expect it will impact its required disclosures. Certain specific interpretative issues remain outstanding and the conclusions reached, if different than currently anticipated, could have a material impact on the Corporation's consolidated financial statements and related disclosures. Fortis continues to closely monitor developments related to the new standard.
Recognition and Measurement of Financial Assets and Financial Liabilities
ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial asset. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Leases
ASU No. 2016-02 was issued in February 2016 and the amendments in this update create ASC Topic 842, Leases, and supersede lease requirements in ASC To
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