ST. JOHN'S, NEWFOUNDLAND AND LABRADOR
-- (Marketwired)
-- 05/03/16
Fortis Inc. ("Fortis" or the "Corporation") (TSX:FTS), a leader in the North American electric and gas utility industry, released its first quarter results today. The Corporation's net earnings attributable to common equity shareholders were $162 million, or $0.57 per common share, compared to $198 million, or $0.72 per common share, for the first quarter of 2015.
On an adjusted basis, net earnings attributable to common equity shareholders for the first quarter were $190 million, or $0.67 per common share, an increase of $11 million, or $0.02 per common share, over the first quarter of 2015. 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, 2016.
"We have had a strong start to the year," said Mr. Barry Perry, President and Chief Executive Officer of Fortis. "We continued to make progress on our capital program and business initiatives and our financial results were on track as we reap the benefits of our diversified portfolio of utilities.
"In the first quarter we also announced the acquisition of ITC in an accretive transaction valued at approximately US$11.3 billion. ITC - a high quality transmission business in the heart of the Midwest United States - will increase our earnings growth rate, support our dividend growth guidance and provide further diversification of our utility portfolio," concluded Mr. Perry.
Stable first quarter earnings and cash flow; capital expenditure plan on track
-- Factors that resulted in growth in adjusted earnings included:
-- contribution of $4 million from the Waneta Expansion hydroelectric
generating facility, which came online in early April 2015, and
increased production in Belize due to higher rainfall;
-- the strength of the US dollar relative to the Canadian dollar.
Approximately 45% of Fortis' assets are denominated in US dollars.
On an annual basis, earnings per common share are affected by
approximately $0.01 for each $0.01 change in the US dollar relative
to the Canadian dollar;
-- a higher allowance for funds used during construction at FortisBC
Energy, largely associated with the ongoing construction of the
Tilbury liquefied natural gas ("LNG") facility expansion ("Tilbury
1A") in British Columbia; and
-- strong performance from the utilities in the Caribbean.
-- Earnings growth was tempered by the timing of quarterly earnings at
FortisBC Electric compared to first quarter of 2015, and higher
Corporate and Other expenses.
-- Excluding the impact of foreign exchange, on an adjusted basis, earnings
at UNS Energy were comparable with the first quarter of 2015. The
impacts of higher lost fixed-cost recovery revenue and higher retail
electricity sales due to warmer temperatures were largely offset by an
increase in operating expenses. UNS Energy's utilities operate under
historical test years for setting customer rates and are currently
engaged in regulatory proceedings to reset customer rates.
-- Cash flow from operating activities was $483 million, an increase of 7%
over the first quarter of 2015.
-- Capital expenditures were $426 million, representing almost one quarter
of the consolidated capital expenditure forecast of $1.9 billion for
2016.
Execution of growth strategy
On February 9, 2016, Fortis announced the acquisition of ITC Holdings Corp. ("ITC") in a transaction (the "Acquisition") valued at approximately US$11.3 billion, based on the closing price for Fortis common shares and the foreign exchange rate on February 8, 2016. ITC is the largest independent electric transmission company in the United States. Under the terms of the transaction, ITC shareholders will receive US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$6.9 billion, and Fortis will assume approximately US$4.4 billion of ITC consolidated indebtedness.
In April 2016 Fortis announced that it reached a definitive agreement with an affiliate of GIC Private Limited, Singapore's sovereign wealth fund, to acquire a 19.9% equity interest in ITC for aggregate consideration of US$1.228 billion in cash upon the closing of the Acquisition. This completes a significant component of the ITC Acquisition financing plan. The closing of the Acquisition is subject to ITC and Fortis shareholder approvals, the satisfaction of other customary closing conditions, and certain regulatory, state and federal approvals. The closing of the Acquisition is expected to occur in late 2016.
On April 1, 2016, Fortis completed the acquisition of the Aitken Creek gas storage facility in British Columbia ("Aitken Creek") for approximately US$266 million. Aitken Creek is the only underground gas storage facility in British Columbia and has a total working gas capacity of 77 billion cubic feet. The facility is an integral part of Western Canada's natural gas transmission network.
Construction continues on Tilbury 1A in British Columbia, the Corporation's largest ongoing capital project, at an estimated cost of $440 million. Approximately $352 million has been invested in Tilbury 1A to the end of the first quarter of 2016 and the facility is expected to be in service around the end of 2016.
The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia. Woodfibre LNG has received an export license from the National Energy Board and received various environmental assessment approvals, which are significant milestones. FortisBC Energy's potential pipeline expansion, which is subject to various environmental approvals, is conditional on Woodfibre LNG proceeding with its LNG export facility. A final investment decision by Woodfibre LNG is targeted for late 2016.
Regulatory proceedings
Fortis continues to navigate ongoing regulatory proceedings and is focused on maintaining constructive regulatory relationships and outcomes across its utilities.
The most significant regulatory proceeding underway is Tucson Electric Power Company's ("TEP") general rate application, in which TEP has requested new retail rates to be effective January 1, 2017, using the year ended June 30, 2015 as a historical test year. Since its last approved rate order in 2013, which used a 2011 historical test year, TEP's total rate base has increased by approximately US$0.6 billion and the common equity component of capital structure has increased from 43.5% to approximately 50%. UNS Electric and Newfoundland Power are also awaiting the outcomes of general rate applications. The Corporation's utilities in British Columbia and Alberta are currently participating in generic cost of capital proceedings initiated by the respective regulators.
Outlook
Fortis expects to close the Acquisition of ITC by the end of 2016. The Acquisition is expected to be accretive to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix.
Over the five-year period through 2020, excluding ITC, the Corporation's capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase rate base to more than $20 billion in 2020. Fortis expects long-term sustainable growth in rate base, resulting from investment in its existing utility operations and strategic acquisitions, to support continuing growth in earnings and dividends.
Fortis continues to target 6% average annual dividend growth through 2020. 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 plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence. The Acquisition of ITC supports this dividend guidance.
Teleconference to Discuss First Quarter 2016 Results
A teleconference and webcast will be held on May 3 at 9:00 a.m. (Eastern). Barry Perry, President and Chief Executive Officer, Fortis, and Karl Smith, Executive Vice President, Chief Financial Officer, Fortis, will discuss the Corporation's first quarter 2016 results.
Analysts, members of the media and other interested parties in North America are invited to participate by calling 1.877.223.4471. International participants may participate by calling 647.788.4922. Please dial in 10 minutes prior to the start of the call. No pass code is required.
A live and archived audio webcast of the teleconference will be available on the Corporation's website, www.fortisinc.com.
A replay of the conference will be available two hours after the conclusion of the call until June 3, 2016. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 88662322.
Interim Management Discussion and Analysis
For the three months ended March 31, 2016
Dated May 3, 2016
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, 2016 and the MD&A and audited consolidated financial statements for the year ended December 31, 2015 included in the Corporation's 2015 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 in Canada ("forward-looking information"). The purpose of the forward-looking information is to provide management's expectations regarding the Corporation's future growth, results of operations, performance, business prospects and opportunities, and it may not be appropriate for other purposes. All forward-looking information is given pursuant to the safe harbour provisions of applicable Canadian securities legislation. The words "anticipates", "believes", "budgets", "could", "estimates", "expects", "forecasts", "intends", "may", "might", "plans", "projects", "schedule", "should", "target", "will", "would" and similar expressions are often intended to identify forward-looking information, although not all forward-looking information contains these identifying words. The forward-looking information reflects management's current beliefs based on information currently available. The forward-looking information in the MD&A includes, but is not limited to, statements related to the acquisition of ITC Holdings Corp. ("ITC"), the expected timing and conditions precedent to the closing of the acquisition of ITC, including shareholder approvals of both ITC and Fortis, regulatory approvals, governmental approvals and other customary closing conditions; the expectation that Fortis will borrow funds and sell 19.9% of ITC to a minority investor to satisfy its obligation to pay the cash portion of the purchase price, and will issue securities to pay the balance of the purchase price; the assumption of ITC debt and expected maintenance of investment-grade credit ratings; the impact of the acquisition on the Corporation's earnings, midyear rate base, credit rating and estimated enterprise value; the expectation that the acquisition of ITC will be accretive to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses, and that the acquisition will support the average annual dividend growth target of Fortis; the expectation that the Corporation will become a U.S. Securities and Exchange Commission registrant and have its common shares listed on the New York Stock Exchange in connection with the acquisition of ITC; the annualized 2016 common share dividend; targeted annual dividend growth through 2020; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the expectation that midyear rate base will increase from 2016 to 2020;
the Corporation's forecast gross consolidated capital expenditures for 2016 and total capital spending over the five-year period from 2016 through 2020; the nature, timing and expected costs of certain capital projects including, without limitation, the Tilbury liquefied natural gas ("LNG") facility expansion, the pipeline expansion to the Woodfibre LNG site, the development of a diesel power plant in Grand Cayman and additional opportunities including electric transmission, LNG and renewable-related infrastructure and generation; the expectation that Hawaiian Electric Company would be the primary offtaker of LNG from a further expansion of Tilbury; the expectation that the Corporation's significant capital expenditure program will support continuing growth in earnings and dividends; the expectation that cash required to complete subsidiary capital expenditure programs will be sourced from a combination of cash from operations, borrowings under credit facilities, equity injections from Fortis and long-term debt offerings; the expectation that the Corporation's subsidiaries will be able to source the cash required to fund their 2016 capital expenditure programs, operating and interest costs, and dividend payments; the expected consolidated fixed-term debt maturities and repayments in 2016 and on average annually over the next five years; the expectation that long-term debt will not be settled prior to maturity; the expectation that the Corporation and its subsidiaries will continue to have reasonable access to capital in the near to long terms; the expectation that the combination of available credit facilities and relatively low annual debt maturities and repayments will provide the Corporation and its subsidiaries with flexibility in the timing of access to capital markets; the expectation that the Corporation and its subsidiaries will remain compliant with debt covenants during 2016; the intent of management to hedge future exchange rate fluctuations and monitor its foreign currency exposure; the expectation of FortisAlberta to recognize capital tracker revenue in 2016 and that adjustments to capital tracker revenue will be considered in the 2017 Annual Rates Application; the settlement of Springerville Unit 1 litigation and the timing and conditions precedent to the closing of the settlement, including regulatory approval and satisfaction of closing conditions; the expectation that any liability from current legal proceedings will not have a material adverse effect on the Corporation's consolidated financial position and results of operations; and the expectation that the adoption of future accounting pronouncements will not have a material impact on the Corporation's consolidated financial statements.
The forecasts and projections that make up the forward-looking information are based on assumptions which include, but are not limited to: 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 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 operations and cash flows of the Corporation; no material change in public policies and directions by governments that could materially negatively affect the Corporation; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the ability to report under US GAAP beyond 2018 or the adoption of International Financial Reporting Standards after 2018 that allows for the recognition of regulatory assets and liabilities; the continued tax-deferred treatment of earnings from the Corporation's Caribbean operations; continued maintenance of information technology infrastructure; 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.
The forward-looking information is subject to risks, uncertainties and other factors that could cause actual results to differ materially from historical results or results anticipated by 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. Key risk factors for 2016 include, but are not limited to: uncertainty regarding the completion of the acquisition of ITC, including but not limited to, the receipt of shareholder approvals of ITC and Fortis, the receipt of regulatory and other governmental approvals, the availability of financing sources at the desired time or at all, on cost-efficient or commercially reasonable terms and the satisfaction or waiver of certain other conditions to closing; uncertainty related to the realization of some or all of the expected benefits of the acquisition of ITC; uncertainty regarding the outcome of regulatory proceedings of 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; and risk associated with the impact of less favorable economic conditions on the Corporation's results of operations.
All forward-looking information in the MD&A is qualified in its entirety by the above cautionary statements and, except as required by law, the Corporation undertakes no obligation to revise or update any forward-looking information as a result of new information, future events or otherwise after the date hereof.
CORPORATE OVERVIEW
Fortis is a leader in the North American electric and gas utility business, with total assets of approximately $28 billion and fiscal 2015 revenue of $6.7 billion. The Corporation's asset mix is approximately 96% regulated (70% electric, 26% gas), with the remaining 4% comprised of non-regulated energy infrastructure. The Corporation's regulated utilities serve more than 3 million customers across Canada, the United States and the Caribbean.
Year-to-date March 31, 2016, the Corporation's electricity distribution systems met a combined peak demand of 8,182 megawatts ("MW") and its gas distribution system met a peak day demand of 1,335 terajoules. For additional information on the Corporation's business segments, refer to Note 1 to the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 2016 and to the "Corporate Overview" section of the 2015 Annual MD&A.
The Corporation's main business, utility operations, is highly regulated and the earnings of the Corporation's regulated utilities are determined under cost of service ("COS") regulation and, in certain jurisdictions, performance-based rate-setting ("PBR") mechanisms. Generally, under COS regulation the respective regulatory authority sets customer electricity and/or gas rates to permit a reasonable opportunity for the utility to recover, on a timely basis, estimated costs of providing service to customers, including a fair rate of return on a regulatory deemed or targeted capital structure applied to an approved regulatory asset value ("rate base"). The ability of a regulated utility to recover prudently incurred costs of providing service and earn the regulator-approved rate of return on common shareholders' equity ("ROE") and/or rate of return on rate base assets ("ROA") depends on the utility achieving the forecasts established in the rate-setting processes. If a historical test year is used to set customer rates, there may be regulatory lag between when costs are incurred and when they are reflected in customer rates. When PBR mechanisms are utilized in determining annual revenue requirements and resulting customer rates, a formula is generally applied that incorporates inflation and assumed productivity improvements. The use of PBR mechanisms should allow a utility a reasonable opportunity to recover prudently incurred costs and earn its allowed ROE or ROA.
Earnings of regulated utilities may be impacted by: (i) changes in the regulator-approved allowed ROE and/or ROA and common equity component of capital structure; (ii) changes in rate base; (iii) changes in energy sales or gas delivery volumes; (iv) changes in the number and composition of customers; (v) variances between actual expenses incurred and forecast expenses used to determine revenue requirements and set customer rates; (vi) regulatory lag in the case of a historical test year; and (vii) timing differences within an annual financial reporting period between when actual expenses are incurred and when they are recovered from customers in rates. When future test years are used to establish revenue requirements and set base customer rates, these rates are not adjusted as a result of the actual COS being different from that which is estimated, other than for certain prescribed costs that are eligible to be deferred on the balance sheet. In addition, the Corporation's regulated utilities, where applicable, are permitted by their respective regulatory authority to flow through to customers, without markup, the cost of natural gas, fuel and/or purchased power through base customer rates and/or the use of rate stabilization and other mechanisms.
SIGNIFICANT ITEMS
Pending Acquisition of ITC Holdings Corp.: On February 9, 2016, Fortis and ITC Holdings Corp. ("ITC") (NYSE:ITC) entered into an agreement and plan of merger pursuant to which Fortis will acquire ITC in a transaction (the "Acquisition") valued at approximately US$11.3 billion, based on the closing price for Fortis common shares and the foreign exchange rate on February 8, 2016. Under the terms of the transaction, ITC shareholders will receive US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$6.9 billion, and Fortis will assume approximately US$4.4 billion of ITC consolidated indebtedness.
ITC is the largest independent electric transmission company in the United States. ITC owns and operates high-voltage transmission facilities in Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma, serving a combined peak load exceeding 26,000 MW along approximately 15,700 circuit miles of transmission line. In addition, ITC is a public utility limited to transmission ownership in Wisconsin. ITC's tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC"), which has been one of the most consistently supportive utility regulators in North America providing reasonable returns and equity ratios. Rates are set using a forward-looking rate-setting mechanism with an annual true-up, which provides timely cost recovery and reduces regulatory lag.
The closing of the Acquisition is subject to ITC and Fortis shareholder approvals, the satisfaction of other customary closing conditions, and certain regulatory, state and federal approvals including, among others, those of FERC, the Committee on Foreign Investment in the United States, and the United States Federal Trade Commission/Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act. The closing of the Acquisition is expected to occur in late 2016.
The pending Acquisition is expected to be accretive to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix. On a pro forma basis, 2016 forecast midyear rate base of Fortis is expected to increase by approximately $8 billion to approximately $26 billion, as a result of the Acquisition. Following the Acquisition, Fortis will be one of the top 15 North American public utilities ranked by enterprise value.
The financing of the Acquisition has been structured to allow Fortis to maintain investment-grade credit ratings and maintain the Corporation's existing capital structure. Financing of the cash portion of the Acquisition purchase price will be achieved primarily through the issuance of approximately US$2 billion of Fortis debt and the sale of 19.9% of ITC to a minority investor. In April 2016 Fortis announced that it reached a definitive agreement with an affiliate of GIC Private Limited ("GIC"), Singapore's sovereign wealth fund, to acquire a 19.9% equity interest in ITC for aggregate consideration of US$1.228 billion in cash upon the closing of the Acquisition. This completes a significant component of the ITC Acquisition financing plan.
Upon completion of the Acquisition, ITC will become a subsidiary of Fortis and approximately 27% of the common shares of Fortis will be held by ITC shareholders. In connection with the Acquisition, Fortis intends to become a U.S. Securities and Exchange Commission ("SEC") registrant and list its common shares on the New York Stock Exchange. Fortis will continue to have its shares listed on the Toronto Stock Exchange. In March 2016 the Corporation filed with the SEC a registration statement on Form F-4, including a proxy statement of ITC and a prospectus of Fortis, and in April 2016 the Corporation filed Amendment No. 1 to Form F-4. These filings are available at www.sec.gov and under Fortis' issuer profile at www.sedar.com.
Acquisition of Aitken Creek Gas Storage Facility
On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC ("ACGS") from Chevron Canada Properties Ltd. ("Chevron") for approximately US$266 million. For further details on the acquisition refer to the "Subsequent Events" section of this MD&A.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of long-term profitable growth with the primary measures of financial performance being earnings per common share and total shareholder return. The Corporation's business is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets. Key financial highlights for the first quarters ended March 31, 2016 and 2015 are provided in the following table.
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Consolidated Financial Highlights (Unaudited) Quarter Ended March 31
($ millions, except for common share data) 2016 2015 Variance
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Revenue 1,757 1,915 (158)
Energy Supply Costs 692 833 (141)
Operating Expenses 458 473 (15)
Depreciation and Amortization 234 215 19
Other Income (Expenses), Net (4) 17 (21)
Finance Charges 139 134 5
Income Tax Expense 42 57 (15)
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Net Earnings 188 220 (32)
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Net Earnings Attributable to:
Non-Controlling Interests 7 2 5
Preference Equity Shareholders 19 20 (1)
Common Equity Shareholders 162 198 (36)
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Net Earnings 188 220 (32)
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Earnings per Common Share
Basic ($) 0.57 0.72 (0.15)
Diluted ($) 0.57 0.71 (0.14)
Weighted Average Number of Common Shares
Outstanding (# millions) 282.4 276.7 5.7
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Cash Flow from Operating Activities 483 450 33
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Revenue
The decrease in revenue was mainly due to the flow through in customer rates of lower energy supply costs at FortisBC Energy and Central Hudson, and a decrease in non-utility revenue due to the sale of commercial real estate and hotel assets in 2015. The decrease was partially offset by favourable foreign exchange associated with the translation of US dollar-denominated revenue and contribution from the Waneta Expansion hydroelectric generating station ("Waneta Expansion").
Energy Supply Costs
The decrease in energy supply costs was primarily due to lower commodity costs at FortisBC Energy and Central Hudson, partially offset by unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs.
Operating Expenses
The decrease in operating expenses was mainly due to a decrease in non-utility operating expenses due to the sale of commercial real estate and hotel assets. The decrease was partially offset by unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses and general inflationary and employee-related cost increases.
Depreciation and Amortization
The increase in depreciation was primarily due to unfavourable foreign exchange associated with the translation of US dollar-denominated depreciation, continued investment in energy infrastructure at the Corporation's regulated utilities and depreciation associated with the Waneta Expansion. The increase was partially offset by lower non-utility depreciation due to the sale of commercial real estate and hotel assets.
Other Income (Expenses), Net
The decrease in other income, net of expenses, was primarily due to acquisition-related expenses of approximately $20 million ($17 million after tax) recognized in the first quarter of 2016 associated with the pending Acquisition of ITC, and the impact of a foreign exchange gain of $9 million recognized in the first quarter of 2015 associated with the Corporation's previous US dollar-denominated long-term other asset that represented the book value of its expropriated investment in Belize Electricity Limited ("Belize Electricity"). The decrease was partially offset by a higher equity component of allowance for funds used during construction ("AFUDC").
Finance Charges
The increase in finance charges was primarily due to unfavorable foreign exchange associated with the translation of US-dollar denominated interest expense.
Income Tax Expense
The decrease in income tax expense was primarily due to lower earnings before income taxes.
Net Earnings Attributable to Common Equity Shareholders and Basic Earnings Per Common Share
Net earnings attributable to common equity shareholders were impacted by a number of non-recurring items or non-operating factors. These factors, referred to as adjusting items, are reconciled below and discussed in the segmented results of operations for the respective reporting segments. Management believes that adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share provide useful information to investors as it provides increased transparency and predictive value. The adjusting items do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar measures presented by other companies.
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Non-US GAAP Reconciliation (Unaudited) Quarter Ended March 31
($ millions, except for common share data) 2016 2015 Variance
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Net Earnings Attributable to Common Equity
Shareholders 162 198 (36)
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Adjusting Items:
UNS Energy - FERC ordered transmission
refunds 11 - 11
FortisAlberta -
Capital tracker revenue adjustment for
2013 and 2014 - (10) 10
Corporate and Other -
Acquisition-related expenses 17 - 17
Foreign exchange gain - (9) 9
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Adjusted Net Earnings Attributable to
Common Equity Shareholders 190 179 11
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Adjusted Basic Earnings Per Common Share
($) 0.67 0.65 0.02
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Weighted Average Number of Common Shares
Outstanding (# millions) 282.4 276.7 5.7
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The increase in adjusted net earnings attributable to common equity shareholders was mainly due to: (i) contribution of $4 million from the Waneta Expansion, which came online in early April 2015, and increased production in Belize due to higher rainfall; (ii) favourable foreign exchange associated with US dollar-denominated earnings; (iii) a higher AFUDC at FortisBC Energy; and (iv) strong performance from the utilities in the Caribbean. The increase was partially offset by the timing of quarterly earnings at FortisBC Electric compared to the first quarter of 2015, and higher Corporate and Other expenses.
Adjusted earnings per common share were $0.02 per common share higher than the first quarter of 2015. The impact of the above-noted items on adjusted net earnings attributable to common equity shareholders were partially offset by an increase in the weighted average number of common shares outstanding.
SEGMENTED RESULTS OF OPERATIONS
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Segmented Net Earnings Attributable to Common Equity Shareholders
(Unaudited) Quarter Ended March 31
($ millions) 2016 2015 Variance
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Regulated Gas & Electric Utilities -
United States
UNS Energy 12 20 (8)
Central Hudson 24 22 2
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36 42 (6)
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Regulated Gas Utility - Canadian
FortisBC Energy 92 88 4
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Regulated Electric Utilities - Canadian
FortisAlberta 31 41 (10)
FortisBC Electric 15 23 (8)
Eastern Canadian 18 19 (1)
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64 83 (19)
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Regulated Electric Utilities - Caribbean 10 5 5
Non-Regulated - Energy Infrastructure 11 3 8
Non-Regulated - Non-Utility - (2) 2
Corporate and Other (51) (21) (30)
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Net Earnings Attributable to Common
Equity Shareholders 162 198 (36)
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The following is a discussion of the financial results of the Corporation's reporting segments. Refer to the "Material Regulatory Decisions and Applications" section of this MD&A for a discussion pertaining to the Corporation's regulated utilities.
REGULATED ELECTRIC & GAS UTILITIES - UNITED STATES
UNS ENERGY (1)
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Financial Highlights (Unaudited) Quarter Ended March 31
2016 2015 Variance
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Average US:CAD Exchange Rate (2) 1.37 1.24 0.13
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Electricity Sales (gigawatt hours
("GWh")) 3,044 3,397 (353)
Gas Volumes (petajoules ("PJ")) 5 5 -
Revenue ($ millions) 440 435 5
Earnings ($ millions) 12 20 (8)
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(1) Primarily includes Tucson Electric Power Company ("TEP"), UNS Electric,
Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas")
(2) The reporting currency of UNS Energy is the US dollar.
Electricity Sales & Gas Volumes
The decrease in electricity sales was primarily due to lower short-term wholesale and mining retail sales, as a result of less favorable commodity prices compared to the first quarter of 2015. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings. The decrease was partially offset by an increase in residential and commercial retail electricity sales due to warmer temperatures, which increased air conditioning load.
Gas volumes were comparable with the first quarter of 2015.
Revenue
The increase in revenue was due to approximately $41 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, an increase in lost fixed-cost recovery revenue, and higher residential and commercial retail electricity sales. The increase was partially offset by lower wholesale electricity sales and $18 million (US$13 million), or $11 million (US$8 million) after tax, in FERC ordered transmission refunds associated with late-filed transmission service agreements. For details on this regulatory order, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
Earnings
The decrease in earnings was primarily due to $11 million (US$8 million) in FERC ordered transmission refunds, as discussed above, and higher operating expenses. The decrease was partially offset by approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, an increase in lost fixed-cost recovery revenue, and higher residential and commercial retail electricity sales.
CENTRAL HUDSON
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Financial Highlights (Unaudited) Quarter Ended March 31
2016 2015 Variance
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Average US:CAD Exchange Rate (1) 1.37 1.24 0.13
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Electricity Sales (GWh) 1,255 1,415 (160)
Gas Volumes (PJ) 9 11 (2)
Revenue ($ millions) 249 292 (43)
Earnings ($ millions) 24 22 2
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(1) The reporting currency of Central Hudson is the US dollar.
Electricity Sales & Gas Volumes
The decrease in electricity sales and gas volumes was primarily due to warmer temperatures.
Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result, do not have a material impact on revenue and earnings.
Revenue
The decrease in revenue was mainly due to the recovery from customers of lower commodity costs, which were mainly due to lower wholesale prices. The decrease was partially offset by $11 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue and an increase in base electricity rates effective July 1, 2015.
Earnings
The increase in earnings was primarily due to approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings. The impact of an increase in base electricity rates effective July 1, 2015 was largely offset by the timing of operating expenses.
REGULATED GAS UTILITY - CANADIAN
FORTISBC ENERGY
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Financial Highlights (Unaudited) Quarter Ended March 31
2016 2015 Variance
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Gas Volumes (PJ) 68 62 6
Revenue ($ millions) 406 488 (82)
Earnings ($ millions) 92 88 4
----------------------------------------------------------------------------
Gas Volumes
The increase in gas volumes was primarily due to higher average consumption as a result of colder temperatures.
Revenue
The decrease in revenue was primarily due to a lower commodity cost of natural gas charged to customers and the timing of regulatory flow-through deferral amounts. The decrease was partially offset by higher gas volumes.
Earnings
The increase in earnings was primarily due to higher AFUDC and the timing of regulatory flow-through deferral amounts.
FortisBC Energy earns approximately the same margin regardless of whether a customer contracts for the purchase and delivery of natural gas or only for the delivery of natural gas. As a result of the operation of regulatory deferral mechanisms, changes in consumption levels and the cost of natural gas do not materially affect earnings.
REGULATED ELECTRIC UTILITIES - CANADIAN
FORTISALBERTA
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2016 2015 Variance
----------------------------------------------------------------------------
Energy Deliveries (GWh) 4,556 4,667 (111)
Revenue ($ millions) 142 146 (4)
Earnings ($ millions) 31 41 (10)
----------------------------------------------------------------------------
Energy Deliveries
The decrease in energy deliveries was primarily due to lower average consumption by oil and gas customers as a result of low commodity prices for oil and gas, and lower average consumption by residential and farm and irrigation customers, mainly due to warmer temperatures. The decrease was partially offset by higher energy deliveries to residential and commercial customers due to customer growth.
Revenue
As a significant portion of FortisAlberta's distribution revenue is derived from fixed or largely fixed billing determinants, changes in quantities of energy delivered are not entirely correlated with changes in revenue. Revenue is a function of numerous variables, many of which are independent of actual energy deliveries.
The decrease in revenue was primarily due to the impact of a $10 million positive capital tracker revenue adjustment recognized in the first quarter of 2015 that related to 2013 and 2014. The decrease was partially offset by an increase in customer rates effective January 1, 2016 based on a combined inflation and productivity factor of 0.9%, growth in the number of customers and higher revenue related to flow-through costs to customers.
Earnings
The decrease in earnings was mainly due to the $10 million positive capital tracker revenue adjustment recognized in the first quarter of 2015, as discussed above.
FORTISBC ELECTRIC (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2016 2015 Variance
----------------------------------------------------------------------------
Electricity Sales (GWh) 851 839 12
Revenue ($ millions) 104 96 8
Earnings ($ millions) 15 23 (8)
----------------------------------------------------------------------------
(1) Includes the regulated operations of FortisBC Inc. and operating,
maintenance and management services related to the Waneta, Brilliant and
Arrow Lakes hydroelectric generating plants. Excludes the non-regulated
generation operations of FortisBC Inc.'s wholly owned Walden
hydroelectric generating facility, which was sold in February 2016.
Electricity Sales
The increase in electricity sales was mainly due to higher average consumption as a result of colder temperatures.
Revenue
The increase in revenue was driven by increases in base electricity rates, electricity sales growth and surplus capacity sales. Revenue was also favourably impacted by higher contribution from non-regulated operating, maintenance and management services associated with the Waneta Expansion.
Earnings
The decrease in earnings was primarily due to approximately $9 million associated with the timing of quarterly earnings compared to the first quarter of 2015, as a result of the impact of regulatory deferral mechanisms and the timing of power purchase costs in 2015. An increase in base electricity rates effective January 1, 2015 was established to recover higher power purchase costs. These costs commenced in the second quarter of 2015. As a result, net earnings were higher in the first quarter of 2015 and the timing effect reversed in the third and fourth quarters of 2015. The decrease was partially offset by higher earnings from non-regulated operating, maintenance and management services.
EASTERN CANADIAN ELECTRIC UTILITIES (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2016 2015 Variance
----------------------------------------------------------------------------
Electricity Sales (GWh) 2,706 2,759 (53)
Revenue ($ millions) 329 322 7
Earnings ($ millions) 18 19 (1)
----------------------------------------------------------------------------
(1) Comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime
Electric Company, Limited ("Maritime Electric") and FortisOntario Inc.
("FortisOntario"). FortisOntario mainly includes Canadian Niagara Power
Inc., Cornwall Street Railway, Light and Power Company, Limited, and
Algoma Power Inc.
Electricity Sales
The decrease in electricity sales was primarily due to lower average consumption by residential customers in Ontario and on Prince Edward Island due to warmer temperatures.
Revenue
The increase in revenue was mainly due to the flow through in customer electricity rates of higher energy supply costs at Newfoundland Power and FortisOntario, partially offset by lower electricity sales.
Earnings
The decrease in earnings of less than $1 million was primarily due to timing differences at Newfoundland Power.
REGULATED ELECTRIC UTILITIES - CARIBBEAN (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2016 2015 Variance
----------------------------------------------------------------------------
Average US:CAD Exchange Rate (2) 1.37 1.24 0.13
----------------------------------------------------------------------------
Electricity Sales (GWh) 190 180 10
Revenue ($ millions) 75 78 (3)
Earnings ($ millions) 10 5 5
----------------------------------------------------------------------------
(1) Comprised of Caribbean Utilities Company, Ltd. ("Caribbean Utilities")
on Grand Cayman, Cayman Islands, in which Fortis holds an approximate
60% controlling interest, and two wholly owned utilities in the Turks
and Caicos Islands, FortisTCI Limited and Turks and Caicos Utilities
Limited (collectively "Fortis Turks and Caicos"). Also includes the
Corporation's 33% equity investment in Belize Electricity.
(2) The reporting currency of Caribbean Utilities and Fortis Turks and
Caicos is the US dollar.
Electricity Sales
The increase in electricity sales was primarily due to overall warmer temperatures, which increased air conditioning load, and growth in the number of customers as a result of increased economic activity.
Revenue
The decrease in revenue was mainly due to the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities. The decrease was partially offset by approximately $5 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, and electricity sales growth.
Earnings
The increase in earnings was due to approximately $2 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, equity income from Belize Electricity, electricity sales growth, and an increase in capitalized interest at Caribbean Utilities. The increase was partially offset by higher depreciation.
NON-REGULATED - ENERGY INFRASTRUCTURE (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
2016 2015 Variance
----------------------------------------------------------------------------
Energy Sales (GWh) 89 60 29
Revenue ($ millions) 28 7 21
Earnings ($ millions) 11 3 8
----------------------------------------------------------------------------
(1) Primarily comprised of long-term contracted generation assets in British
Columbia and Belize, with a combined generating capacity of 391 MW. In
February 2016 the Corporation sold its 16-MW Walden hydroelectric
generating facility. On April 1, 2016, the Corporation completed the
acquisition of ACGS. The financial results of ACGS will be included in
this segment from the date of acquisition. For further information,
refer to the "Significant Items" and "Subsequent Events" sections of
this MD&A.
Energy Sales
The increase in energy sales was driven by the Waneta Expansion, which commenced production in early April 2015 and reported energy sales of 26 GWh for the first quarter of 2016. Increased production in Belize due to higher rainfall also contributed to the increase.
Revenue
The increase in revenue was driven by the Waneta Expansion, which recognized revenue of $19 million for the first quarter of 2016. Increased production in Belize and favourable foreign exchange associated with the translation of US dollar-denominated revenue of approximately $1 million also contributed to the increase.
Earnings
The increase in earnings was primarily due to earnings contribution of $4 million from the Waneta Expansion, increased production in Belize, and approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings.
NON-REGULATED - NON-UTILITY (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2016 2015 Variance
----------------------------------------------------------------------------
Revenue - 53 (53)
Loss - (2) 2
----------------------------------------------------------------------------
(1) Comprised of Fortis Properties, which completed the sale of its
commercial real estate and hotel assets in June 2015 and October 2015,
respectively.
CORPORATE AND OTHER (1)
----------------------------------------------------------------------------
Financial Highlights (Unaudited) Quarter Ended March 31
($ millions) 2016 2015 Variance
----------------------------------------------------------------------------
Revenue 2 7 (5)
Operating Expenses 9 5 4
Depreciation and Amortization 1 - 1
Other Income (Expenses), Net (17) 9 (26)
Finance Charges 24 21 3
Income Tax Recovery (17) (9) (8)
----------------------------------------------------------------------------
(32) (1) (31)
Preference Share Dividends 19 20 (1)
----------------------------------------------------------------------------
Net Corporate and Other Expenses (51) (21) (30)
----------------------------------------------------------------------------
(1) Includes Fortis net Corporate expenses; non-regulated holding company
expenses of FortisBC Holdings Inc. ("FHI"), CH Energy Group, Inc. and
UNS Energy Corporation; and the financial results of FHI's wholly owned
subsidiary FortisBC Alternative Energy Services Inc.
Net Corporate and Other expenses were impacted by the following items, which were included in other income, net of expenses:
i. Acquisition-related expenses of $20 million ($17 million after tax) in
the first quarter of 2016 associated with the pending Acquisition of
ITC; and
ii. A foreign exchange gain of $9 million in the first quarter of 2015
associated with the Corporation's previous US dollar-denominated long-
term other asset that represented the book value of its expropriated
investment in Belize Electricity.
Excluding the above-noted items, net Corporate and Other expenses were $34 million for the first quarter of 2016 compared to $30 million for the first quarter of 2015. The increase in net Corporate and Other expenses was primarily due to lower revenue and higher operating expenses and finance charges, partially offset by other income associated with the release of provisions on the wind-up of a partnership and a higher income tax recovery.
The decrease in revenue was primarily due to lower related-party interest income, mainly due to the sale of commercial real estate and hotel assets in June 2015 and October 2015, respectively.
The increase in operating expenses was mainly due to higher share-based compensation expenses, largely as a result of share price appreciation, and other general inflationary increases.
The increase in finance charges was primarily due to the impact of no longer capitalizing interest upon the completion of the Waneta Expansion in April 2015. The impact of unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense was largely offset by lower interest on the Corporation's credit facilities.
MATERIAL REGULATORY DECISIONS AND APPLICATIONS
The nature of regulation associated with each of the Corporation's regulated electric and gas utilities is generally consistent with that disclosed in the 2015 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 2016.
UNS Energy
General Rate Applications
In November 2015 TEP, UNS Energy's largest utility, filed a general rate application ("GRA") with the Arizona Corporation Commission requesting new retail rates to be effective January 1, 2017, using the year ended June 30, 2015 as a historical test year. The key provisions of the rate request include: (i) a base retail rate increase of US$110 million, or 12.0%, compared with adjusted test year revenue; (ii) a 7.34% return on original cost rate base of US$2.1 billion; (iii) a common equity component of capital structure of approximately 50%; (iv) a cost of equity of 10.35% and an average cost of debt of 4.32%; and (v) rate design changes that would reduce the reliance on volumetric sales to recover fixed costs, and a new net metering tariff that would ensure that customers who install distributed generation pay an equitable price for their electric service. Since its last approved rate order in 2013, which used a 2011 historical test year, TEP's total rate base has increased by approximately US$0.6 billion and the common equity component of capital structure has increased from 43.5% to approximately 50%. In May 2015 UNS Electric filed a GRA requesting new retail rates to be effective May 1, 2016, using 2014 as a historical test year. A hearing on UNS Electric's application concluded in March 2016 and a decision is expected in the third quarter of 2016. The nature of UNS Electric's GRA was similar to that of TEP. A decision on TEP's application is expected in the fourth quarter of 2016.
FERC Order
In 2015 TEP reported to FERC that it had not filed on a timely basis certain FERC jurisdictional agreements and, at that time, TEP made necessary compliance filings, including the filing of several TEP transmission service agreements entered into between 2003 and 2015 that contained certain deviations from TEP's standard form of service agreement. In April 2016 FERC issued an order relating to late-filed transmission service agreements, which directs TEP to issue time value refunds to the relevant counterparties to the agreements in an amount up to $18 million (US$13 million). The refund was recognized in the first quarter of 2016, resulting in a reduction of earnings of $11 million (US$8 million) after tax. TEP is reviewing the calculation of the ordered refunds to determine if issuing the refunds would cause TEP to have provided service at a loss under each transmission service agreement, in which case the refund amount maybe reduced. Refunds are due to the relevant counterparties within 30 days from the issuance of the FERC order and a refund report must be filed with FERC within 30 days thereafter. TEP can appeal the order within 60 days from the date issued. The results of the compliance filings are still being reviewed by FERC and, as a result, FERC could also impose civil penalties on TEP.
FortisAlberta
Capital Tracker Applications
The funding of capital expenditures during the PBR term is a material aspect of the PBR plan for FortisAlberta. The PBR plan provides a capital tracker mechanism to fund the recovery of costs associated with certain qualifying capital expenditures.
In February 2016 the AUC issued its decision related to FortisAlberta's 2014 True-Up and 2016-2017 Capital Tracker Applications, resulting in a capital tracker revenue adjustment of less than $1 million in the first quarter of 2016. Capital tracker revenue related to 2015 is subject to change and FortisAlberta expects to file a 2015 True-Up Application in the second quarter of 2016, with a decision expected in the first quarter of 2017.
FortisAlberta expects to recognize capital tracker revenue of $65 million for 2016, down $7 million from the amount previously requested in the 2016-2017 Capital Tracker Application to reflect actual capital expenditures and associated financing costs compared to forecast. In April 2016 FortisAlberta filed its Compliance Filing related to the February 2016 capital tracker decision and a decision is expected in the second half of 2016.
FortisAlberta expects that the adjustments to capital tracker revenue, as discussed above, will be considered in the 2017 Annual Rates Application, to be filed in September 2016, and reflected in customer rates effective January 1, 2017.
Utility Asset Disposition Matters
In November 2015 the utilities in Alberta filed an application with the Supreme Court of Canada (the "Supreme Court") seeking leave to appeal the Supreme Court's September 2015 decision, which implied that the shareholder is responsible for the cost of stranded assets. In April 2016 the Supreme Court dismissed the leave to appeal application. This decision has no immediate impact on FortisAlberta's financial position; however, it exposes the Company to the risk that unrecovered costs associated with utility assets deemed by the Alberta Utilities Commission to have been subject to an extraordinary retirement will not be recoverable from customers.
Eastern Canadian Electric Utilities
In October 2015 Newfoundland Power filed a 2016/2017 GRA with the Newfoundland and Labrador Board of Commissioners of Public Utilities to set customer rates effective July 1, 2016. In March 2016 the Company filed a revised 2016/2017 GRA, proposing an overall average increase in electricity rates of 2.5% effective July 1, 2016. The GRA includes a full review of Newfoundland Power's costs, including cost of capital. A public hearing was completed in April 2016 and a decision on the application is expected by the end of the second quarter of 2016.
In October 2015 Maritime Electric filed a GRA with the Island Regulatory and Appeals Commission ("IRAC") to set customer rates effective March 1, 2016, on expiry of the Prince Edward Island Energy Accord. In January 2016 Maritime Electric and the Government of Prince Edward Island entered into a 2016 General Rate Agreement covering the three-year period from March 1, 2016 through February 28, 2019. In February 2016 IRAC issued an order effective March 1, 2016 that reflected the terms of the Agreement. The order provides for an allowed ROE capped at 9.35% on an average common equity component of capital structure of approximately 40% for 2016 through 2018.
Significant Regulatory Proceedings
The following table summarizes significant ongoing regulatory proceedings, including filing dates and expected timing of decisions for the Corporation's regulated utilities.
----------------------------------------------------------------------------
Regulated Utility Application/Procee Filing Date Expected Decision
ding
----------------------------------------------------------------------------
TEP GRA for 2017 November 2015 Fourth quarter of
2016
UNS Electric GRA for 2016 May 2015 Third quarter of
2016
----------------------------------------------------------------------------
Central Hudson Reforming the Not applicable To be determined
Energy Vision
----------------------------------------------------------------------------
FortisBC Energy 2016 Cost of October 2015 Mid-2016
Capital
Application
----------------------------------------------------------------------------
FortisAlberta 2016/2017 GCOC Not applicable Second half of 2016
Proceeding
----------------------------------------------------------------------------
Newfoundland GRA for 2016/2017 October 2015 Second quarter of
Power 2016
----------------------------------------------------------------------------
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between March 31, 2016 and December 31, 2015.
Significant Changes in the Consolidated Balance Sheets (Unaudited) between
March 31, 2016 and December 31, 2015
----------------------------------------------------------------------------
(Decrease)
Balance Sheet Account ($ millions) Explanation
----------------------------------------------------------------------------
Utility capital assets (414) The decrease was mainly due
to the impact of foreign
exchange on the translation
of US dollar-denominated
utility capital assets and
depreciation, partially
offset by utility capital
expenditures.
----------------------------------------------------------------------------
Goodwill (168) The decrease was due to the
impact of foreign exchange
on the translation of US
dollar-denominated goodwill.
----------------------------------------------------------------------------
Accounts payable and other (113) The decrease was primarily
current liabilities due to FortisBC Energy,
mainly associated with a
decrease in the mark-to-
market of natural gas
derivatives, lower natural
gas costs payable and a
reduction in capital
accruals. The impact of
foreign exchange on the
translation of US dollar-
denominated accounts payable
also contributed to the
decrease.
----------------------------------------------------------------------------
Long-term debt (294) The decrease was primarily
(including current portion) due to the impact of foreign
exchange on the translation
of US dollar-denominated
debt and regularly scheduled
debt repayments. The
decrease was partially
offset by higher borrowings
under committed credit
facilities.
----------------------------------------------------------------------------
Shareholders' equity (before (161) The decrease was primarily
non-controlling interests) due to a decrease in
accumulated other
comprehensive income
associated with the
translation of the
Corporation's US dollar-
denominated investment in
subsidiaries, net of hedging
activities and tax. The
decrease was partially
offset by net earnings
attributable to common
equity shareholders for the
three months ended March 31,
2016, less dividends
declared on common shares,
and the issuance of common
shares under the
Corporation's dividend
reinvestment, employee share
purchase and stock option
plans.
----------------------------------------------------------------------------
LIQUIDITY AND CAPITAL RESOURCES
The table below outlines the Corporation's sources and uses of cash for the three months ended March 31, 2016, as compared to the same period in 2015, followed by a discussion of the nature of the variances in cash flows.
----------------------------------------------------------------------------
Summary of Consolidated Cash Flows
(Unaudited) Quarter Ended March 31
($ millions) 2016 2015 Variance
----------------------------------------------------------------------------
Cash, Beginning of Period 242 230 12
Cash Provided by (Used in):
Operating Activities 483 450 33
Investing Activities (413) (553) 140
Financing Activities (66) 156 (222)
Effect of Exchange Rate Changes on
Cash and Cash Equivalents (14) 19 (33)
Less Cash Associated with Assets Held
for Sale - (3) 3
----------------------------------------------------------------------------
Cash, End of Period 232 299 (67)
----------------------------------------------------------------------------
Operating Activities: Cash flow from operating activities was $33 million higher quarter over quarter. The increase was primarily due to favourable changes in long-term regulatory deferrals at FortisBC Energy. The increase was partially offset by unfavourable changes in working capital, mainly associated with accounts payable and current regulatory deferrals at FortisBC Energy and Newfoundland Power.
Investing Activities: Cash used in investing activities was $140 million lower quarter over quarter. The decrease was primarily due to lower capital spending at UNS Energy, FortisBC Energy and FortisAlberta. The decrease in capital spending at UNS Energy was mainly due to the purchase of an additional ownership interest in the Springerville Unit 1 generating facility in the first quarter of 2015 upon expiry of the lease arrangement. The decrease in capital spending at FortisBC Energy was mainly due to lower capital expenditures related to the Tilbury liquefied natural gas facility expansion ("Tilbury 1A"). At FortisAlberta, the decrease was mainly due to lower Alberta Electric System Operator ("AESO") contributions and lower capital expenditures for customer growth.
Financing Activities: Cash provided by financing activities was $222 million lower quarter over quarter. The decrease was primarily due to lower proceeds from the issuance of long-term debt, partially offset by lower repayments of long-term debt and higher net borrowings under committed credit facilities.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net borrowings (repayments) under committed credit facilities for the quarter compared to the same period last year are summarized in the following tables.
----------------------------------------------------------------------------
Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited)
Quarter Ended March 31
($ millions) 2016 2015 Variance
----------------------------------------------------------------------------
UNS Energy (1) - 370 (370)
Central Hudson (2) - 25 (25)
Other (3) - 12 (12)
----------------------------------------------------------------------------
Total - 407 (407)
----------------------------------------------------------------------------
(1) In February 2015 TEP issued 10-year US$300 million 3.05% senior
unsecured notes. Net proceeds were used to repay long-term debt and
credit facility borrowings and to finance capital expenditures.
(2) In March 2015 Central Hudson issued 10-year US$20 million 2.98%
unsecured notes. The net proceeds were used to finance capital
expenditures and for general corporate purposes.
(3) In January 2015 Fortis Turks and Caicos issued 15-year US$10 million
4.75% unsecured notes. The net proceeds were used to finance capital
expenditures and for general corporate purposes.
----------------------------------------------------------------------------
Repayments of Long-Term Debt and Capital Lease and Finance Obligations
(Unaudited)
Quarter Ended March 31
($ millions) 2016 2015 Variance
----------------------------------------------------------------------------
UNS Energy (13) (168) 155
FortisBC Energy (2) (2) -
FortisBC Electric (25) - (25)
----------------------------------------------------------------------------
Total (40) (170) 130
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net Borrowings (Repayments) Under Committed Credit Facilities (Unaudited)
Quarter Ended March 31
($ millions) 2016 2015 Variance
----------------------------------------------------------------------------
UNS Energy 46 (87) 133
FortisAlberta 17 46 (29)
Newfoundland Power 22 19 3
Corporate 7 3 4
----------------------------------------------------------------------------
Total 92 (19) 111
----------------------------------------------------------------------------
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 2016 were $77 million, net of $29 million of dividends reinvested, compared to $60 million, net of $34 million of dividends reinvested, paid in the first quarter of 2015. The dividend paid per common share for the first quarter of 2016 was $0.375 compared to $0.34 for the first quarter of 2015. The weighted average number of common shares outstanding for the first quarter of 2016 was 282.4 million compared to 276.7 million for the first quarter of 2015.
CONTRACTUAL OBLIGATIONS
The Corporation's consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter as at March 31, 2016, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2015 Annual MD&A and below, where applicable.
----------------------------------------------------------------------------
Contractual Obligations (Unaudited)
Due Due
As at March 31, 2016 within Due in Due in Due in Due in after
($ millions) Total 1 year year 2 year 3 year 4 year 5 5 years
----------------------------------------------------------------------------
Long-term debt 10,944 396 68 269 228 855 9,128
Interest obligations
on long-term debt 9,115 510 497 492 480 474 6,662
Capital lease and
finance obligations 2,454 72 73 91 78 61 2,079
Renewable power
purchase
obligations (1) 1,546 90 90 90 90 90 1,096
Power purchase
obligations 1,344 259 197 158 72 31 627
Long-term contracts
- UNS Energy (2) 1,175 170 169 142 135 102 457
Gas purchase
contract
obligations 1,332 278 270 223 154 126 281
Capital cost 483 19 19 19 19 19 388
Operating lease
obligations 170 11 12 11 9 7 120
Renewable energy
credit purchase
agreements 150 12 12 12 12 12 90
Purchase of
Springerville Unit
1 and common
facilities (3) 247 110 49 - - 88 -
Defined benefit
pension funding
contributions 124 42 10 8 8 9 47
Waneta Partnership
promissory note 72 - - - - 72 -
Joint-use asset and
shared service
agreements 53 3 3 3 3 3 38
Other 75 21 13 14 3 - 24
----------------------------------------------------------------------------
Total 29,284 1,993 1,482 1,532 1,291 1,949 21,037
----------------------------------------------------------------------------
(1) UNS Energy is party to renewable power purchase agreements totalling
approximately US$1,190 million as at March 31, 2016, which require UNS
Energy to purchase 100% of the output of certain renewable energy
generation facilities that have achieved commercial operation. In March
2016 one of the facilities achieved commercial operation, increasing
estimated future payments of renewable power purchase contracts by US$58
million as at March 31, 2016.
(2) In January 2016 the ownership of the San Juan generating station was
restructured and a new coal supply agreement came into effect under
which TEP's minimum purchase obligations are US$137 million as at March
31, 2016.
(3) In February 2016 TEP entered into a settlement agreement with third-
party owners of Springerville Unit 1 to purchase the third-party owners'
50.5% undivided interest in Springerville Unit 1 for US$85 million. The
purchase is expected to close in the second quarter of 2016. For a
discussion of the nature of the Springerville Unit 1 litigation, refer
to the "Critical Accounting Estimates" section of this MD&A.
Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2015 Annual MD&A.
For a discussion of the nature and amount of the Corporation's consolidated capital expenditure program not included in the preceding Contractual Obligations table, refer to the "Capital Expenditure Program" section of this MD&A.
CAPITAL STRUCTURE
The Corporation's principal businesses of regulated electric and gas utilities require ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure containing approximately 35% common equity, 65% debt and preferred equity, as well as investment-grade credit ratings. Each of the Corporation's regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in each of the utility's customer rates.
The consolidated capital structure of Fortis is presented in the following table.
----------------------------------------------------------------------------
Capital Structure
(Unaudited) As at
March 31, 2016 December 31, 2015
($ millions) (%) ($ millions) (%)
----------------------------------------------------------------------------
Total debt and capital
lease and finance
obligations (net of cash)
(1) 11,691 54.6 12,022 54.9
Preference shares 1,820 8.5 1,820 8.3
Common shareholders'
equity 7,899 36.9 8,060 36.8
----------------------------------------------------------------------------
Total (2) 21,410 100.0 21,902 100.0
----------------------------------------------------------------------------
(1) Includes long-term debt, capital lease and finance obligations,
including current portion, and short-term borrowings, net of cash.
Excludes deferred financing costs.
(2) Excludes amounts related to non-controlling interests
Excluding capital lease and finance obligations, the Corporation's capital structure as at March 31, 2016 was 53.5% debt, 8.7% preference shares and 37.8% common shareholders' equity (December 31, 2015 - 53.8% debt, 8.5% preference shares and 37.7% common shareholders' equity).
CREDIT RATINGS
The Corporation's credit ratings are as follows:
Standard & Poor's ("S&P") A- / Negative (long-term corporate credit
rating)
BBB+ / Negative (unsecured debt credit rating)
DBRS A (low) / Under Review - Negative Implications
(unsecured debt credit rating)
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 management's commitment to maintaining reasonable levels of debt at the holding company level. In February 2016, after the announcement by Fortis that it had entered into an agreement to acquire ITC, S&P affirmed the Corporation's long-term corporate credit rating at A-, revised its unsecured debt credit rating to BBB+ from A-, and revised its outlook on the Corporation to negative from stable. Similarly, in February 2016 DBRS placed the Corporation's credit rating under review with negative implications.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $426 million in gross consolidated capital expenditures by segment year-to-date 2016 is provided in the following table.
----------------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-Date March 31, 2016
($ millions)
----------------------------------------------------------------------
Regulated Utilities
----------------------------------------------------------------------
UNS Central FortisBC Fortis FortisBC Eastern Electric
Energy Hudson Energy Alberta Electric Canadian Caribbean
----------------------------------------------------------------------
120 58 87 79 19 28 22
----------------------------------------------------------------------
------------------------------------------------------------
Gross Consolidated Capital Expenditures (Unaudited) (1)
Year-to-Date March 31, 2016
($ millions)
------------------------------------------------------------
Non-Regulated
------------------------------
Total
Regulated Energy Corporate
Utilities Infrastructure and Other Total
------------------------------------------------------------
413 11 2 426
------------------------------------------------------------
(1) Relates to cash payments to acquire or construct utility capital assets
and intangible assets, as reflected on the consolidated statement of
cash flows. Excludes the non-cash equity component of AFUDC.
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 2016 are forecast to be approximately $1.9 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 2015 Annual MD&A, with the exception of those noted below for FortisAlberta and UNS Energy.
Capital expenditures at FortisAlberta are expected to be lower than the original forecast of $441 million, primarily due to lower AESO contributions and as a result of the current economic downturn in Alberta. Capital expenditures for 2016 at UNS Energy are expected to be higher than the original forecast, primarily due to a settlement agreement with third-party owners of Springerville Unit 1 to purchase the third-party owners' 50.5% undivided interest in Springerville Unit 1 for US$85 million. The purchase is expected to close in the second quarter of 2016. For a discussion of the nature of the Springerville Unit 1 litigation, refer to the "Critical Accounting Estimates" section of this MD&A.
FortisBC Energy's construction of Tilbury 1A in Delta, British Columbia is ongoing. Key construction activities during the first quarter included completion of the liquefied natural gas ("LNG") storage tank roof, continued construction of the liquefaction process area and commencement of work on the internal LNG storage tank. Tilbury 1A will be included in regulated rate base and is estimated to cost approximately $440 million, including an equity component of AFUDC. It will include a second LNG tank and a new liquefier, both expected to be in service around the end of 2016. Approximately $352 million has been invested in Tilbury 1A to the end of the first quarter of 2016.
Caribbean Utilities was the successful bidder for new generation capacity and entered into a design-build contract agreement to cover the purchase and turnkey installation of two 18.5 MW diesel-generating units, one 2.7 MW waste heat recovery steam turbine and associated auxiliary equipment. Key construction activities during the first quarter focused on preparations to install the two diesel-generating units. The project cost is estimated at US$85 million and the plant is expected to be commissioned by June 2016. Approximately US$62 million has been invested to date.
Over the five-year period through 2020, gross consolidated capital expenditures are expected to be approximately $9 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 39% at U.S. Regulated Electric & Gas Utilities; 37% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 18% at Canadian Regulated Gas Utility; 5% at Caribbean Regulated Electric Utilities; and the remaining 1% at non-regulated operations. Capital expenditures at the regulated utilities are subject to regulatory approval. Over the five-year period, on average annually, the approximate breakdown of the total capital spending to be incurred is as follows: 50% for sustaining capital expenditures, 35% to meet customer growth, and 15% for facilities, equipment, vehicles, information technology and other assets.
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 and also exclude the pending Acquisition of ITC.
The Corporation continues to pursue additional LNG infrastructure investment opportunities in British Columbia, including a pipeline expansion to the proposed Woodfibre LNG site near Squamish, British Columbia and a further expansion of Tilbury. In December 2014 FortisBC Energy received an Order in Council from the Government of British Columbia effectively exempting these projects from further regulatory approval by the British Columbia Utilities Commission.
The pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG export facility. The Woodfibre LNG plant 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. These approvals are significant milestones. In addition, FortisBC Energy's pipeline expansion, at an estimated total project cost of up to $600 million, is subject to various environmental approvals. A final investment decision by Woodfibre LNG is targeted for late 2016.
A further expansion of Tilbury is conditional upon having long-term energy supply contracts in place for the offtake of 70% of the additional liquefaction capacity, on average, for the first 15 years of operation. FortisBC Energy has a conditional agreement with Hawaiian Electric Company that would meet this requirement, subject to the regulatory approval process in Hawaii. The Corporation continues to have discussions with Hawaiian Electric Company, which is expected to be the primary offtaker, regarding the viability and scope of the project. Any resulting agreement would be subject to the approval of the Hawaii Public Utilities Commission.
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, the New York Transco, LLC at Central Hudson to address transmission constraints in New York; renewable energy alternatives at UNS Energy; Wataynikaneyap transmission line to connect remote First Nations communities at FortisOntario; further gas infrastructure opportunities at FortisBC Energy; and potential further consolidation of Rural Electrification Associations at FortisAlberta.
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, equity injections from Fortis and long-term debt offerings.
The Corporation's ability to service its debt obligations and pay dividends on its common shares and preference shares is dependent on the financial results of the operating subsidiaries and the related cash payments from these subsidiaries. The Corporation's 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 structure of its regulated operating subsidiaries will have an impact on its ability to pay dividends in the foreseeable future.
Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation's committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. The subsidiaries expect to be able to source the cash required to fund their 2016 capital expenditure programs. For a discussion of the Corporation's cash flow requirements associated with the pending Acquisition of ITC, refer to the "Significant Items" section of this MD&A.
In April 2015 FortisBC Energy filed a short-form base shelf prospectus to establish a Medium-Term Note Debenture Program, under which the Company may issue debentures in an aggregate principal amount of up to $1 billion during the 25-month life of the shelf prospectus. In April 2016 FortisBC Energy issued $300 million of unsecured debentures in a dual tranche of 10-year $150 million at 2.58% and 30-year $150 million at 3.67% under the base shelf prospectus. The net proceeds will be used to repay credit facility borrowings and finance the Company's capital expenditure program.
As at March 31, 2016, management expects consolidated fixed-term debt maturities and repayments to average approximately $240 million annually over the next five years. The combination of available credit facilities and relatively low 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 compliant with debt covenants as at March 31, 2016 and are expected to remain compliant throughout 2016.
CREDIT FACILITIES
As at March 31, 2016, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.5 billion, of which approximately $2.3 billion was unused, including $590 million unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, as well as large banks in the United States, with no one bank holding more than 20% of these facilities. Approximately $3.3 billion of the total credit facilities are committed facilities with maturities ranging from 2016 through 2020.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
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Credit Facilities (Unaudited) As at
December
Regulated Corporate March 31, 31,
($ millions) Utilities and Other 2016 2015
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Total credit facilities (1) 2,161 1,324 3,485 3,565
Credit facilities utilized:
Short-term borrowings (477) - (477) (511)
Long-term debt (2) (110) (499) (609) (551)
Letters of credit
outstanding (69) (36) (105) (104)
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Credit facilities unused 1,505 789 2,294 2,399
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(1) Total credit facilities exclude a $300 million option to increase the
Corporation's committed corporate credit facility, as discussed below.
(2) As at March 31, 2016, credit facility borrowings classified as long-term
debt included $110 million in current installments of long-term debt on
the consolidated balance sheet (December 31, 2015 - $71 million).
As at March 31, 2016 and December 31, 2015, certain borrowings under the Corporation's and subsidiaries' credit facilities were classified as long-term debt. These borrowings are under long-term committed credit facilities and management's intention is to refinance these borrowings with long-term permanent financing during future periods. The significant changes in credit facilities from that disclosed in the Corporation's 2015 Annual MD&A are as follows.
In April 2016 FortisBC Electric amended its $150 million unsecured committed revolving credit facility to now mature in May 2019.
In April 2016 FHI amended its unsecured committed revolving credit facility resulting in an increase in the facility to $50 million and an extension of the maturity date to April 2019.
In April 2016 the Corporation amended its $1 billion unsecured committed revolving credit facility, resulting in an extension of the maturity date to July 2021. The Corporation has the option to increase the facility to $1.3 billion from $1 billion. As at March 31, 2016, the Corporation has not yet exercised this option.
In connection with the pending Acquisition of ITC, in February 2016 the Corporation obtained commitments of US$2.0 billion from Goldman Sachs Bank USA to bridge the long-term debt financing ("Debt Bridge Facility") and US$1.7 billion from The Bank of Nova Scotia to primarily bridge the sale of the minority investment in ITC ("Equity Bridge Facilities"). These non-revolving term senior unsecured credit facilities are repayable in full on the first anniversary of their advance. Goldman Sachs Bank USA has syndicated 60% of the Debt Bridge Facility to three other financial institutions, each of which have agreed to provide 20% of such facility. The Bank of Nova Scotia may syndicate a portion of the Equity Bridge Facilities. The credit facilities table does not include the US$3.7 billion Acquisition credit facilities.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows:
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Financial Instruments
(Unaudited) As at
March 31, 2016 December 31, 2015
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
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Waneta Partnership
promissory note 57 60 56 59
Long-term debt, including
current portion 10,944 12,015 11,240 12,614
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The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.
Derivative Instruments
The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments are estimates of the amounts that the utilities would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates. The Corporation's derivatives primarily include energy contracts that are subject to regulatory deferral, as permitted by the regulators, as well as certain limited energy contracts that are not subject to regulatory deferral and cash flow hedges.
There were no material changes in the nature and amount of the Corporations' derivative instruments during the three months ended March 31, 2016 from those disclosed in the 2015 Annual MD&A. For details of the Corporation's derivative instruments as at March 31, 2016, refer to Note 15 to the Corporation's interim unaudited consolidated financial statements.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $105 million as at March 31, 2016 (December 31, 2015 - $104 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 2016, the business risks of the Corporation were generally consistent with those disclosed in the Corporation's 2015 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 "Material Regulatory Decisions and Applications" section of this MD&A.
Completion of the Acquisition of ITC: In April 2016 Fortis reached a definitive agreement with GIC to acquire a 19.9% equity interest in ITC upon the closing of the Acquisition. As a result, the risk of not having a minority investor has been mitigated. The closing of the Acquisition of ITC, however, is not conditional upon having a minority investor.
Capital Resources and Liquidity Risk - Credit Ratings: In February 2016, after the announcement by Fortis that it had entered into an agreement to acquire ITC, S&P revised its outlook on TEP, Central Hudson, FortisAlberta, Maritime Electric and Caribbean Utilities to negative from stable. In March 2016 S&P affirmed Maritime Electric's credit rating at 'A' and revised its outlook to stable from negative.
Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at March 31, 2016, the fair value of the Corporation's consolidated defined benefit pension and other post-employment benefit plan assets was $2,594 million, compared to $2,647 million as at December 31, 2015. The decrease was primarily due to the impact of foreign exchange on the translation of US dollar-denominated plan assets.
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 2015 annual audited consolidated financial statements, except as described below.
Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items
Effective January 1, 2016, the Corporation adopted Accounting Standards Update ("ASU") No. 2015-01, Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items. The amendments in this update are part of the Financial Accounting Standards Board's ("FASB") initiative to reduce complexity in accounting standards by eliminating the concept of extraordinary items. 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, 2016.
Amendments to the Consolidation Analysis
Effective January 1, 2016, the Corporation adopted ASU No. 2015-02, Amendments to the Consolidation Analysis. The amendments in this update change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Specifically, the amendments note the following regarding limited partnerships: (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities; and (ii) eliminate the presumption that a general partner should consolidate a limited partnership. The amendments did not materially impact the Corporation's interim unaudited consolidated financial statements. The amendments did, however, change the Corporation's 51% controlling ownership interest in the Waneta Expansion Limited Partnership from a voting interest entity to a variable interest entity, resulting in additional disclosure in Note 16 to the Corporation's interim unaudited consolidated financial statements.
Simplifying the Accounting for Measurement-Period Adjustments
Effective January 1, 2016, the Corporation adopted ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The amendments in this update require that in a business combination, an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Under previous guidance, these adjustments were required to be accounted for retrospectively. ASU No. 2015-16 was applied prospectively and did not have an impact on the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 2016.
FUTURE ACCOUNTING PRONOUNCEMENTS
The Corporation considers the applicability and impact of all ASUs issued by 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 completes a joint effort by FASB and the International Accounting Standards Board to improve financial reporting by creating common revenue recognition guidance for US GAAP and International Financial Reporting Standards that clarifies the principles for recognizing revenue and that can be applied consistently across various transactions, industries and capital markets. This standard was originally effective for annual and interim periods beginning after December 15, 2016 and is to be applied on a full retrospective or modified retrospective basis. ASU No. 2015-14 was issued in August 2015 and the amendments in this update defer the effective date of ASU No. 2014-09 by one year to annual and interim periods beginning after December 15, 2017. Early adoption is permitted as of the original effective date.
ASU No. 2016-08, Principal versus Agent Considerations, was issued in March 2016 and ASU 2016-10, Identifying Performance Obligations and Licensing, was issued in April 2016. Both ASUs clarify implementation guidance in ASC Topic 606. The effective date of these updates is the same as the effective date and transition requirements of ASU No. 2014-09.
The majority of the Corporation's revenue is generated from energy sales to customers based on published tariff rates, as approved by the respective regulators, and is expected to be in the scope of ASU No. 2014-09. Fortis has not yet selected a transition method and is assessing the impact that the adoption of this standard, and all related ASUs, will have on its consolidated financial statements and related disclosures. The Corporation plans to have this assessment substantially complete by the end of 2016.
Recognition and Measurement of Financial Assets and Financial Liabilities
ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial asset. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Leases
ASU No. 2016-02 was issued in February 2016 and the amendments in this update create ASC Topic 842, Leases, and supersede lease requirements in ASC Topic 840, Leases. The main provision of ASC Topic 842 is the recognition of lease assets and lease liabilities on the balance sheet by lessees for those leases that were previously classified as operating leases. For operating leases, a lessee is required to do the following: (i) recognize a right-of-use asset and a lease liability, initially measured at the present value of the lease payments, on the balance sheet; (ii) recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and (iii) classify all cash payments within operating activities in the statement of cash flows. These amendments also require qualitative disclosures along with specific quantitative disclosures. This update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Improvements to Employee Share-Based Payment Accounting
ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, was issued in March 2016 as part of FASB's simplification initiative. The areas for simplification in this update involve several aspects of accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update is effective for annual and interim periods beginning after December 15, 2016. Early adoption is permitted, however, an entity that elects early adoption must adopt all the amendments in the same period. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
CRITICAL ACCOUNTING ESTIMATES
The preparation of the Corporation's interim unaudited consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances. Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.
Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three months ended March 31, 2016 from those disclosed in the 2015 Annual MD&A.
Contingencies: The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows. There were no material changes in the Corporation's contingencies from those disclosed in the 2015 Annual MD&A, with the exception of the Springerville Unit 1 litigation, as described below. For complete details of legal proceedings affecting the Corporation, refer to Note 19 to the Corporation's interim unaudited consolidated financial statements.
UNS Energy
Springerville Unit 1
In February 2016 TEP entered into an agreement with the third-party owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (the "Agreement"). The Agreement provides that TEP will purchase the third-party owners' 50.5% undivided interest in Springerville Unit 1 for US$85 million and the third-party owners will pay TEP US$13 million for operating costs related to Springerville Unit 1 incurred on behalf of the third-party owners. Upon completion of the purchase, all outstanding disputes, pending litigation and arbitration proceedings between TEP and the third-party owners will be dismissed with prejudice.
The purchase of the third-party owners' undivided interest in Springerville Unit 1 is subject to, among other things, FERC approval and satisfaction of other customary closing conditions. TEP expects the purchase to close in the second quarter of 2016. However, there is no assurance that the settlement will be finalized or that the litigation will not continue. Therefore, at this time, TEP cannot predict the outcome of the claims relating to Springerville Unit 1 and, due to the general and non-specific scope and nature of the claims, TEP cannot determine estimates of the range of loss, if any, at this time and, accordingly no amount has been accrued in the consolidated financial statements. Should the litigation matters continue, TEP intends to continue vigorously defending itself against the claims asserted by the third-party owners and to vigorously pursue the claims it has asserted against the owner trustees and co-trustees.
RELATED-PARTY TRANSACTIONS
Related-party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. There were no material changes in the nature of the Corporation's related-party transactions during the three months ended March 31, 2016 from those disclosed in the 2015 Annual MD&A.
Power purchased by FortisBC Electric from the Waneta Expansion in the first quarter of 2016 totalled approximately $15 million. In addition, the Waneta Expansion pays FortisBC Electric for management services associated with the generating station, which totalled approximately $3 million in the first quarter of 2016.
From time to time, the Corporation provides short-term financing to certain of its subsidiaries to support capital expenditure programs, acquisitions and seasonal working capital requirements, bearing interest at rates that approximate the Corporation's cost of short-term borrowing. In addition, the Corporation provided long-term financing to certain of its subsidiaries, bearing interest at rates that approximate the Corporation's cost of long-term debt. As at March 31, 2016, inter-segment loans outstanding totalled $46 million (December 31, 2015 - $48 million) and total interest charged in the first quarter of 2016 was less than $1 million.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the eight quarters ended June 30, 2014 through March 31, 2016. The quarterly information has been obtained from the Corporation's interim unaudited consolidated financial statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.
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Summary of Quarterly Results
(Unaudited) Net Earnings
Attributable
to
Common Equity
Revenue Shareholders Earnings per Common Share
Quarter Ended ($ millions) ($ millions) Basic ($) Diluted ($)
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March 31, 2016 1,757 162 0.57 0.57
December 31, 2015 1,708 135 0.48 0.48
September 30, 2015 1,566 151 0.54 0.54
June 30, 2015 1,538 244 0.88 0.87
March 31, 2015 1,915 198 0.72 0.71
December 31, 2014 1,693 113 0.44 0.43
September 30, 2014 1,197 14 0.06 0.06
June 30, 2014 1,056 47 0.22 0.22
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The summary of the past eight quarters reflects the Corporation's continued organic growth, growth from acquisitions and associated acquisition-related expenses, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of electricity and gas demand and water flows, as well as the timing and recognition of regulatory decisions. Revenue is also affected by the cost of fuel and purchased power and the cost of natural gas, which are flowed through to customers without markup. Given the diversified nature of the Corporation's subsidiaries, seasonality may vary. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters. Earnings for UNS Energy and Central Hudson's electric utilities are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.
March 2016/March 2015: Net earnings attributable to common equity shareholders were $162 million, or $0.57 per common share, for the first quarter of 2016 compared to earnings of $198 million, or $0.72 per common share, for the first quarter of 2015. A discussion of the quarter over quarter variance in financial results is provided in the "Financial Highlights" section of this MD&A.
December 2015/December 2014: Net earnings attributable to common equity shareholders were $135 million, or $0.48 per common share, for the fourth quarter of 2015 compared to earnings of $113 million, or $0.44 per common share, for the fourth quarter of 2014. The increase in earnings was primarily due to: (i) favourable foreign exchange impacts; (ii) an increase in base electricity rates at Central Hudson effective July 1, 2015, combined with the impact of storm restoration and other non-recurring expenses recognized in the fourth quarter of 2014; (iii) earnings contribution of approximately $6 million from the Waneta Expansion; (iv) rate base growth associated with capital expenditures and growth in the number of customers at FortisAlberta; and (v) a higher AFUDC at FortisBC Energy, partially offset by higher operating expenses. The timing of regulatory deferral mechanisms had a favourable impact on FortisBC Energy's earnings for the quarter and an unfavourable impact on FortisBC Electric. The increase in earnings was partially offset by lower earnings contribution due to the sale of commercial real estate and hotel assets and higher Corporate and Other expenses. Corporate and Other expenses included $7 million in acquisition-related expenses in the fourth quarter of 2015 and in the fourth quarter of 2014 included $4 million in interest expense associated with the convertible debentures and a $3 million foreign exchange gain. Excluding these items, the increase in Corporate and Other expenses was mainly due to a lower income tax recovery and lower related-party interest income.
September 2015/September 2014: Net earnings attributable to common equity shareholders were $151 million, or $0.54 per common share, for the third quarter of 2015 compared to earnings of $14 million, or $0.06 per common share, for the third quarter of 2014. Earnings for the third quarter of 2015 were favourably impacted by a $5 million gain on the sale of non-regulated generation assets in Ontario and a $5 million positive adjustment associated with the sale of hotel assets, and were reduced by a $9 million loss on the settlement of expropriation matters related to the Corporation's investment in Belize Electricity. Earnings for the third quarter of 2014 were reduced by a total of $58 million due to acquisition-related expenses associated with UNS Energy. Excluding these items, the increase in earnings was driven by contribution of $97 million at UNS Energy compared to $37 million for the third quarter of 2014. Earnings contribution of $5 million from the Waneta Expansion also contributed to the increase. Performance was also driven by the Corporation's other regulated utilities, including rate base growth associated with capital expenditures and customer growth at FortisAlberta; improved performance at Central Hudson; and favourable foreign exchange associated with US dollar-denominated earnings. Earnings at FortisBC Energy and FortisBC Electric were unfavourably impacted by the timing of regulatory deferral mechanisms; however, FortisBC Energy's earnings were favourably impacted by lower operating expenses and higher AFUDC. The increase was partially offset by higher preference share dividends and finance charges in the Corporate and Other segment, largely associated with the acquisition of UNS Energy.
June 2015/June 2014: Net earnings attributable to common equity shareholders were $244 million, or $0.88 per common share, for the second quarter of 2015 compared to earnings of $47 million, or $0.22 per common share, for the second quarter of 2014. The increase was driven by a net gain of $123 million on the sale of commercial real estate, hotel and non-regulated generation assets. The increase was also due to earnings contribution of $52 million from UNS Energy and $12 million from the Waneta Expansion, representing the Corporation's 51% controlling ownership. Performance was also driven by the Corporation's regulated utilities, including rate base growth associated with capital expenditures, customer growth and a decrease in depreciation and amortization at FortisAlberta; increases at FortisBC Electric, largely due to timing of quarterly earnings compared to the same period last year, resulting from the impact of regulatory deferral mechanisms; and improved performance at Central Hudson. The increase was partially offset by a $5 million decrease in earnings at FortisBC Energy due to the timing of regulatory flow-through deferral amounts, and higher preference share dividends and finance charges in the Corporate and Other segment associated with the acquisition of UNS Energy.
OUTLOOK
Fortis expects to close the Acquisition of ITC by the end of 2016. The Acquisition is expected to be accretive to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses. The Acquisition represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix.
Over the five-year period through 2020, excluding ITC, the Corporation's capital program is expected to be approximately $9 billion. This investment in energy infrastructure is expected to increase rate base to more than $20 billion in 2020. Fortis expects long-term sustainable growth in rate base, resulting from investment in its existing utility operations and strategic acquisitions, to support continuing growth in earnings and dividends.
Fortis continues to target 6% average annual dividend growth through 2020. 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 plan, and management's continued confidence in the strength of the Corporation's diversified portfolio of utilities and record of operational excellence. The Acquisition of ITC supports this dividend guidance.
SUBSEQUENT EVENTS
Acquisition of Aitken Creek Gas Storage Facility
On April 1, 2016, Fortis acquired ACGS from Chevron for approximately US$266 million. The net purchase price was primarily financed through US dollar-denominated credit facility borrowings under the Corporation's committed revolving credit facility.
ACGS owns 93.8% of the Aitken Creek gas storage site ("Aitken Creek"), with the remaining share owned by BP Canada Energy Company. Aitken Creek is the only underground natural gas storage facility in British Columbia and has a total working gas capacity of 77 billion cubic feet. The facility is an integral part of Western Canada's natural gas transmission network. ACGS also owns 100% of the North Aitken Creek gas storage site which offers future expansion potential. The financial results of ACGS will be included in the Corporation's consolidated results from the date of acquisition and will be included in the Non-Regulated - Energy Infrastructure reporting segment.
FERC Order at TEP
In April 2016 FERC issued an order relating to late-filed transmission service agreements, which directs TEP to issue time value refunds on revenue collected from relevant counterparties to the agreements in an amount up to $18 million (US$13 million). The refund was recognized in the first quarter of 2016, resulting in a reduction of earnings of $11 million (US$8 million) after tax. For details on this regulatory order, refer to the "Material Regulatory Decisions and Applications" section of this MD&A.
OUTSTANDING SHARE DATA
As at May 2, 2016, the Corporation had issued and outstanding approximately 283.1 million common shares; 8.0 million First Preference Shares, Series E; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation's First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether or not such dividends have been declared.
The number of common shares of Fortis that would be issued if all outstanding stock options and First Preference Shares, Series E were converted as at May 2, 2016 is as follows.
----------------------------------------------------------------------------
Conversion of Securities into Common Shares(Unaudited)
As at May 2, 2016 Number of
Common
Shares
Security (millions)
----------------------------------------------------------------------------
Stock Options 4.6
First Preference Shares, Series E 5.3
----------------------------------------------------------------------------
Total 9.9
----------------------------------------------------------------------------
Additional information, including the Fortis 2015 Annual Information Form, Management Information Circular and Annual Report, is available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.
FORTIS INC.
Interim Consolidated Financial Statements
For the three months ended March 31, 2016 and 2015
(Unaudited)
Prepared in accordance with accounting principles generally accepted in the United States
Fortis Inc.
Consolidated Balance Sheets (Unaudited)
As at
(in millions of Canadian dollars)
March 31, December 31,
2016 2015
----------------------------------------------------------------------------
----------------------------------------------------------------------------
ASSETS
Current assets
Cash and cash equivalents $ 232 $ 242
Accounts receivable and other current assets 877 964
Prepaid expenses 80 68
Inventories 271 337
Regulatory assets (Note 5) 247 246
---------------------------
1,707 1,857
Other assets 356 352
Regulatory assets (Note 5) 2,239 2,286
Utility capital assets 19,181 19,595
Intangible assets 528 541
Goodwill 4,005 4,173
---------------------------
$ 28,016 $ 28,804
----------------------------------------------------------------------------
----------------------------------------------------------------------------
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities
Short-term borrowings (Note 17) $ 477 $ 511
Accounts payable and other current liabilities 1,306 1,419
Regulatory liabilities (Note 5) 285 298
Current installments of long-term debt (Note 6) 396 384
Current installments of capital lease and finance
obligations 27 26
---------------------------
2,491 2,638
Other liabilities 1,122 1,152
Regulatory liabilities (Note 5) 1,289 1,340
Deferred income taxes 1,978 2,050
Long-term debt (Note 6) 10,478 10,784
Capital lease and finance obligations 475 487
---------------------------
17,833 18,451
---------------------------
Shareholders' equity
Common shares (1)(Note 7) 5,917 5,867
Preference shares 1,820 1,820
Additional paid-in capital 13 14
Accumulated other comprehensive income 525 791
Retained earnings 1,444 1,388
---------------------------
9,719 9,880
Non-controlling interests 464 473
---------------------------
10,183 10,353
---------------------------
$ 28,016 $ 28,804
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(1) No par value. Unlimited authorized shares; 283.1 million and 281.6
million issued and outstanding as at March 31, 2016 and December 31,
2015, respectively
Commitments and Contingencies (Notes 18 and 19, respectively)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Earnings (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars, except per share amounts)
Quarter Ended
2016 2015
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Revenue $ 1,757 $ 1,915
--------------------------
Expenses
Energy supply costs 692 833
Operating 458 473
Depreciation and amortization 234 215
--------------------------
1,384 1,521
--------------------------
Operating income 373 394
Other income (expenses), net (Note 10) (4) 17
Finance charges (Note 11) 139 134
--------------------------
Earnings before income taxes 230 277
Income tax expense (Note 12) 42 57
--------------------------
Net earnings $ 188 $ 220
--------------------------
Net earnings attributable to:
Non-controlling interests $ 7 $ 2
Preference equity shareholders 19 20
Common equity shareholders 162 198
--------------------------
$ 188 $ 220
--------------------------
Earnings per common share (Note 13)
Basic $ 0.57 $ 0.72
Diluted $ 0.57 $ 0.71
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Comprehensive Income (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2016 2015
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Net earnings $ 188 $ 220
---------------------------
Other comprehensive (loss) income
Unrealized foreign currency translation (losses)
gains, net of hedging activities and tax (269) 298
Unrealized gains on available-for-sale
investment, net of tax 3 -
Unrealized employee future benefits losses, net
of tax - (1)
---------------------------
(266) 297
---------------------------
Comprehensive income $ (78) $ 517
---------------------------
Comprehensive income attributable to:
Non-controlling interests $ 7 $ 2
Preference equity shareholders 19 20
Common equity shareholders (104) 495
---------------------------
$ (78) $ 517
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Cash Flows (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Quarter Ended
2016 2015
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Operating activities
Net earnings $ 188 $ 220
Adjustments to reconcile net earnings to net
cash provided by operating activities:
Depreciation - capital assets 209 193
Amortization - intangible assets 18 16
Amortization - other 7 6
Deferred income tax expense (recovery) 2 (9)
Accrued employee future benefits 13 3
Equity component of allowance for funds used
during construction (Note 10) (7) (4)
Other 21 (4)
Change in long-term regulatory assets and
liabilities 2 (48)
Change in non-cash operating working capital
(Note 14) 30 77
-----------------------------
483 450
-----------------------------
Investing activities
Change in other assets and other liabilities (8) (15)
Capital expenditures - utility capital assets (409) (530)
Capital expenditures - non-utility capital
assets - (4)
Capital expenditures - intangible assets (17) (20)
Contributions in aid of construction 11 15
Proceeds on sale of assets 10 1
-----------------------------
(413) (553)
-----------------------------
Financing activities
Change in short-term borrowings (32) -
Proceeds from long-term debt, net of issue
costs - 407
Repayments of long-term debt and capital lease
and finance obligations (40) (170)
Net advances (repayments) under committed
credit facilities 92 (19)
Advances from non-controlling interests - 5
Issue of common shares, net of costs and
dividends reinvested 19 17
Dividends
Common shares, net of dividends reinvested (77) (60)
Preference shares (19) (20)
Subsidiary dividends paid to non-controlling
interests (9) (4)
-----------------------------
(66) 156
-----------------------------
Effect of exchange rate changes on cash and
cash equivalents (14) 19
-----------------------------
Change in cash and cash equivalents (10) 72
Less cash associated with assets held for sale - (3)
Cash and cash equivalents, beginning of period 242 230
-----------------------------
Cash and cash equivalents, end of period $ 232 $ 299
----------------------------------------------------------------------------
----------------------------------------------------------------------------
Supplementary Information to Consolidated Statements of Cash Flows (Note
14)
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Accumulated
Additional Other
Common Preference Paid-in Comprehensive
Shares Shares Capital Income (Loss)
----------------------------------------------------------------------------
----------------------------------------------------------------------------
(Note 7)
As at January 1, 2016 $ 5,867 $ 1,820 $ 14 $ 791
Net earnings - - - -
Other comprehensive loss - - - (266)
Common share issues 50 - (2) -
Stock-based compensation - - 1 -
Foreign currency translation
impacts - - - -
Subsidiary dividends paid to
non-controlling interests - - - -
Dividends declared on common
shares ($0.375 per share) - - - -
Dividends declared on
preference shares - - - -
------------------------------------------------
As at March 31, 2016 $ 5,917 $ 1,820 $ 13 $ 525
----------------------------------------------------------------------------
As at January 1, 2015 $ 5,667 $ 1,820 $ 15 $ 129
Net earnings - - - -
Other comprehensive income - - - 297
Common share issues 52 - (2) -
Stock-based compensation - - 1 -
Advances from non-
controlling interests - - - -
Foreign currency translation
impacts - - - -
Subsidiary dividends paid to
non-controlling interests - - - -
Dividends declared on common
shares ($0.34 per share) - - - -
Dividends declared on
preference shares - - - -
------------------------------------------------
As at March 31, 2015 $ 5,719 $ 1,820 $ 14 $ 426
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
Fortis Inc.
Consolidated Statements of Changes in Equity (Unaudited)
For the three months ended March 31
(in millions of Canadian dollars)
Non-
Retained Controlling Total
Earnings Interests Equity
----------------------------------------------------------------------------
----------------------------------------------------------------------------
As at January 1, 2016 $ 1,388 $ 473 $ 10,353
Net earnings 181 7 188
Other comprehensive loss - - (266)
Common share issues - - 48
Stock-based compensation - - 1
Foreign currency translation
impacts - (7) (7)
Subsidiary dividends paid to
non-controlling interests - (9) (9)
Dividends declared on common
shares ($0.375 per share) (106) - (106)
Dividends declared on
preference shares (19) - (19)
------------------------------------------------
As at March 31, 2016 $ 1,444 $ 464 $ 10,183
----------------------------------------------------------------------------
As at January 1, 2015 $ 1,060 $ 421 $ 9,112
Net earnings 218 2 220
Other comprehensive income - - 297
Common share issues - - 50
Stock-based compensation - - 1
Advances from non-
controlling interests - 5 5
Foreign currency translation
impacts - 10 10
Subsidiary dividends paid to
non-controlling interests - (4) (4)
Dividends declared on common
shares ($0.34 per share) (94) - (94)
Dividends declared on
preference shares (20) - (20)
------------------------------------------------
As at March 31, 2015 $ 1,164 $ 434 $ 9,577
----------------------------------------------------------------------------
----------------------------------------------------------------------------
See accompanying Notes to Interim Consolidated Financial Statements
FORTIS INC.
NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS
For the three months ended March 31, 2016 and 2015 (unless otherwise stated)
(Unaudited)
1. DESCRIPTION OF THE BUSINESS
NATURE OF OPERATIONS
Fortis Inc. ("Fortis" or the "Corporation") is principally an international electric and gas utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated energy infrastructure, which is treated as a separate segment. The Corporation's reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes profit and loss responsibility and is accountable for its own resource allocation.
The following outlines each of the Corporation's reportable segments and is consistent with the basis of segmentation as disclosed in the Corporation's 2015 annual audited consolidated financial statements.
REGULATED UTILITIES
The Corporation's interests in regulated electric and gas utilities are as follows:
a. Regulated Electric & Gas Utilities - United States: Comprised of UNS
Energy, which primarily includes Tucson Electric Power Company ("TEP"),
UNS Electric, Inc. ("UNS Electric") and UNS Gas, Inc. ("UNS Gas"), and
Central Hudson Gas & Electric Corporation ("Central Hudson").
b. Regulated Gas Utility - Canadian: Primarily includes FortisBC Energy
Inc. ("FortisBC Energy").
c. Regulated Electric Utilities - Canadian: Comprised of FortisAlberta Inc.
("FortisAlberta"), FortisBC Inc. ("FortisBC Electric"), and Eastern
Canadian Electric Utilities. Eastern Canadian Electric Utilities is
comprised of Newfoundland Power Inc. ("Newfoundland Power"), Maritime
Electric Company, Limited ("Maritime Electric") and FortisOntario Inc.
("FortisOntario"). FortisOntario mainly includes Canadian Niagara Power
Inc., Cornwall Street Railway, Light and Power Company, Limited and
Algoma Power Inc.
d. Regulated Electric Utilities - Caribbean: Comprised of Caribbean
Utilities Company, Ltd. ("Caribbean Utilities"), in which Fortis holds
an approximate 60% controlling interest, two wholly owned utilities in
the Turks and Caicos Islands, FortisTCI Limited and Turks and Caicos
Utilities Limited (collectively "Fortis Turks and Caicos"), and also
includes the Corporation's 33% equity investment in Belize Electricity
Limited ("Belize Electricity").
NON-REGULATED - ENERGY INFRASTRUCTURE
Non-Regulated - Energy Infrastructure is primarily comprised of long-term contracted generation assets in British Columbia and Belize. In February 2016 the Corporation sold its Walden hydroelectric generating facility in British Columbia for gross proceeds of approximately $9 million. On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC ("ACGS") from Chevron Canada Properties Ltd. ("Chevron") for approximately US$266 million (Note 20). Financial results of ACGS will be included in this segment from the date of acquisition.
NON-REGULATED - NON-UTILITY
The Non-Utility segment previously included Fortis Properties Corporation ("Fortis Properties"). Fortis Properties completed the sale of its commercial real estate and hotel assets in June 2015 and October 2015, respectively.
CORPORATE AND OTHER
The Corporate and Other segment captures expense and revenue items not specifically related to any reportable segment and those business operations that are below the required threshold for reporting as separate segments.
The Corporate and Other segment includes net corporate expenses of Fortis and non-regulated holding company expenses of FortisBC Holdings Inc. ("FHI"), CH Energy Group, Inc. and UNS Energy Corporation. Also included in the Corporate and Other segment are the financial results of FortisBC Alternative Energy Services Inc. ("FAES"). FAES is a wholly owned subsidiary of FHI that provides alternative energy solutions, including thermal-energy and geo-exchange systems.
PENDING ACQUISITION
ITC Holdings Corp.
On February 9, 2016, Fortis and ITC Holdings Corp. ("ITC") (NYSE:ITC) entered into an agreement and plan of merger pursuant to which Fortis will acquire ITC in a transaction (the "Acquisition") valued at approximately US$11.3 billion, based on the closing price for Fortis common shares and the foreign exchange rate on February 8, 2016. Under the terms of the transaction, ITC shareholders will receive US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$6.9 billion, and Fortis will assume approximately US$4.4 billion of ITC consolidated indebtedness.
ITC is the largest independent electric transmission company in the United States. ITC owns and operates high-voltage transmission facilities in Michigan, Iowa, Minnesota, Illinois, Missouri, Kansas and Oklahoma, serving a combined peak load exceeding 26,000 megawatts along approximately 15,700 circuit miles of transmission line. In addition, ITC is a public utility limited to transmission ownership in Wisconsin. ITC's tariff rates are regulated by the United States Federal Energy Regulatory Commission ("FERC"), which has been one of the most consistently supportive utility regulators in North America providing reasonable returns and equity ratios. Rates are set using a forward-looking rate-setting mechanism with an annual true-up, which provides timely cost recovery and reduces regulatory lag.
The closing of the Acquisition is subject to ITC and Fortis shareholder approvals, the satisfaction of other customary closing conditions, and certain regulatory, state and federal approvals including, among others, those of FERC, the Committee on Foreign Investment in the United States, and the United States Federal Trade Commission/Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act. The closing of the Acquisition is expected to occur in late 2016.
In April 2016 Fortis announced that it reached a definitive agreement with an affiliate of GIC Private Limited, Singapore's sovereign wealth fund, to acquire a 19.9% equity interest in ITC for aggregate consideration of US$1.228 billion in cash upon the closing of the Acquisition.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
These interim consolidated financial statements have been prepared in accordance with accounting principles generally accepted in the United States ("US GAAP") for interim financial statements. As a result, these interim consolidated financial statements do not include all of the information and disclosures required in the annual consolidated financial statements and should be read in conjunction with the Corporation's 2015 annual audited consolidated financial statements. In management's opinion, the interim consolidated financial statements include all adjustments that are of a recurring nature and necessary to present fairly the consolidated financial position of the Corporation.
Interim results will fluctuate due to the seasonal nature of electricity and gas demand and water flows, as well as the timing and recognition of regulatory decisions. Given the diversified group of companies, seasonality may vary. Most of the annual earnings of the gas utilities are realized in the first and fourth quarters. Earnings for UNS Energy and Central Hudson's electric utilities are generally highest in the second and third quarters due to the use of air conditioning and other cooling equipment.
The preparation of the consolidated financial statements in accordance with US GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities and the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenue and expenses during the reporting periods. Estimates and judgments are based on historical experience, current conditions and various other assumptions believed to be reasonable under the circumstances.
Additionally, certain estimates and judgments are necessary since the regulatory environments in which the Corporation's regulated utilities operate often require amounts to be recognized at estimated values until these amounts are finalized pursuant to regulatory decisions or other regulatory proceedings. Due to changes in facts and circumstances, and the inherent uncertainty involved in making estimates, actual results may differ significantly from current estimates. Estimates and judgments are reviewed periodically and, as adjustments become necessary, are recognized in earnings in the period in which they become known. In the event that a regulatory decision is received after the balance sheet date but before the consolidated financial statements are issued, the facts and circumstances are reviewed to determine whether or not it is a recognized subsequent event.
Interim financial statements may also employ a greater use of estimates than the annual financial statements. There were no material changes in the nature of the Corporation's critical accounting estimates during the three months ended March 31, 2016.
An evaluation of subsequent events through May 2, 2016, the date these interim consolidated financial statements were approved by the Audit Committee of the Board of Directors, was completed to determine whether circumstances warranted recognition and disclosure of events or transactions in the interim consolidated financial statements as at March 31, 2016 (Note 20).
All amounts are presented in Canadian dollars unless otherwise stated.
These interim consolidated financial statements are comprised of the accounts of Fortis and its wholly owned subsidiaries and controlling ownership interests. All significant intercompany balances and transactions have been eliminated on consolidation.
These interim consolidated financial statements have been prepared following the same accounting policies and methods as those used to prepare the Corporation's 2015 annual audited consolidated financial statements, except as described below.
New Accounting Policies
Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items
Effective January 1, 2016, the Corporation adopted Accounting Standards Update ("ASU") No. 2015-01, Simplifying Income Statement Presentation by Eliminating the Concept of Extraordinary Items. The amendments in this update are part of the Financial Accounting Standards Board's ("FASB") initiative to reduce complexity in accounting standards by eliminating the concept of extraordinary items. 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, 2016.
Amendments to the Consolidation Analysis
Effective January 1, 2016, the Corporation adopted ASU No. 2015-02, Amendments to the Consolidation Analysis. The amendments in this update change the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. Specifically, the amendments note the following regarding limited partnerships: (i) modify the evaluation of whether limited partnerships and similar legal entities are variable interest entities or voting interest entities; and (ii) eliminate the presumption that a general partner should consolidate a limited partnership. The amendments did not materially impact the Corporation's interim unaudited consolidated financial statements. The amendments did, however, change the Corporation's 51% controlling ownership interest in the Waneta Expansion Limited Partnership ("Waneta Partnership") from a voting interest entity to a variable interest entity, resulting in additional disclosure (Note 16).
Simplifying the Accounting for Measurement-Period Adjustments
Effective January 1, 2016, the Corporation adopted ASU No. 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The amendments in this update require that in a business combination, an acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. Under previous guidance, these adjustments were required to be accounted for retrospectively. ASU No. 2015-16 was applied prospectively and did not have an impact on the Corporation's interim unaudited consolidated financial statements for the three months ended March 31, 2016.
3. FUTURE ACCOUNTING PRONOUNCEMENTS
The Corporation considers the applicability and impact of all ASUs issued by 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 completes a joint effort by FASB and the International Accounting Standards Board to improve financial reporting by creating common revenue recognition guidance for US GAAP and International Financial Reporting Standards that clarifies the principles for recognizing revenue and that can be applied consistently across various transactions, industries and capital markets. This standard was originally effective for annual and interim periods beginning after December 15, 2016 and is to be applied on a full retrospective or modified retrospective basis. ASU No. 2015-14 was issued in August 2015 and the amendments in this update defer the effective date of ASU No. 2014-09 by one year to annual and interim periods beginning after December 15, 2017. Early adoption is permitted as of the original effective date.
ASU No. 2016-08, Principal versus Agent Considerations, was issued in March 2016 and ASU 2016-10, Identifying Performance Obligations and Licensing, was issued in April 2016. Both ASUs clarify implementation guidance in ASC Topic 606. The effective date of these updates is the same as the effective date and transition requirements of ASU No. 2014-09.
The majority of the Corporation's revenue is generated from energy sales to customers based on published tariff rates, as approved by the respective regulators, and is expected to be in the scope of ASU No. 2014-09. Fortis has not yet selected a transition method and is assessing the impact that the adoption of this standard, and all related ASUs, will have on its consolidated financial statements and related disclosures. The Corporation plans to have this assessment substantially complete by the end of 2016.
Recognition and Measurement of Financial Assets and Financial Liabilities
ASU No. 2016-01, Recognition and Measurement of Financial Assets and Financial Liabilities, was issued in January 2016 and the amendments in this update address certain aspects of recognition, measurement, presentation and disclosure of financial instruments. Most notably, the amendments require the following: (i) equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings; however, entities will be able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes; and (ii) financial assets and financial liabilities to be presented separately in the notes to the consolidated financial statements, grouped by measurement category and form of financial asset. This update is effective for annual and interim periods beginning after December 15, 2017. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Leases
ASU No. 2016-02 was issued in February 2016 and the amendments in this update create ASC Topic 842, Leases, and supersede lease requirements in ASC Topic 840, Leases. The main provision of ASC Topic 842 is the recognition of lease assets and lease liabilities on the balance sheet by lessees for those leases that were previously classified as operating leases. For operating leases, a lessee is required to do the following: (i) recognize a right-of-use asset and a lease liability, initially measured at the present value of the lease payments, on the balance sheet; (ii) recognize a single lease cost, calculated so that the cost of the lease is allocated over the lease term on a generally straight-line basis; and (iii) classify all cash payments within operating activities in the statement of cash flows. These amendments also require qualitative disclosures along with specific quantitative disclosures. This update is effective for annual and interim periods beginning after December 15, 2018 and is to be applied using a modified retrospective approach with practical expedient options. Early adoption is permitted. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Improvements to Employee Share-Based Payment Accounting
ASU No. 2016-09, Improvements to Employee Share-Based Payment Accounting, was issued in March 2016 as part of FASB's simplification initiative. The areas for simplification in this update involve several aspects of accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. This update is effective for annual and interim periods beginning after December 15, 2016. Early adoption is permitted, however, an entity that elects early adoption must adopt all the amendments in the same period. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
4. SEGMENTED INFORMATION
Information by reportable segment is as follows:
REGULATED
---------------------------------------------------------------
United States Canada
---------------------------------------------------------------
Quarter Ended Electric & Gas Gas Electric
--------------- ----------------------------------
March 31,
2016 UNS Central FortisBC FortisFortisBC Eastern
($ millions) Energy Hudson Total Energy AlbertaElectric Canadian Total
----------------------------------------------------------------------------
Revenue 440 249 689 406 142 104 329 981
Energy supply
costs 180 81 261 134 - 40 234 408
Operating
expenses 153 104 257 71 48 22 35 176
Depreciation
and
amortization 67 16 83 50 45 14 22 131
----------------------------------------------------------------------------
Operating
income 40 48 88 151 49 28 38 266
Other income
(expenses),
net 2 1 3 3 2 - - 5
Finance
charges 26 10 36 31 20 10 14 75
Income tax
expense
(recovery) 4 15 19 31 - 3 6 40
----------------------------------------------------------------------------
Net earnings
(loss) 12 24 36 92 31 15 18 156
Non-
controlling
interests - - - - - - - -
Preference
share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 12 24 36 92 31 15 18 156
----------------------------------------------------------------------------
Goodwill 1,794 585 2,379 913 227 235 67 1,442
Identifiable
assets 6,529 2,437 8,966 5,066 3,638 1,888 2,265 12,857
----------------------------------------------------------------------------
Total assets 8,323 3,022 11,345 5,979 3,865 2,123 2,332 14,299
----------------------------------------------------------------------------
Gross capital
expenditures 120 58 178 87 79 19 28 213
----------------------------------------------------------------------------
Quarter Ended
March 31,
2015
($ millions)
----------------------------------------------------------------------------
Revenue 435 292 727 488 146 96 322 1,052
Energy supply
costs 188 134 322 217 - 25 224 466
Operating
expenses 135 100 235 70 46 22 39 177
Depreciation
and
amortization 60 14 74 48 41 14 20 123
----------------------------------------------------------------------------
Operating
income 52 44 96 153 59 35 39 286
Other income
(expenses),
net 1 2 3 3 1 - - 4
Finance
charges 23 9 32 34 19 10 14 77
Income tax
expense
(recovery) 10 15 25 34 - 2 6 42
----------------------------------------------------------------------------
Net earnings
(loss) 20 22 42 88 41 23 19 171
Non-
controlling
interests - - - - - - - -
Preference
share
dividends - - - - - - - -
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 20 22 42 88 41 23 19 171
----------------------------------------------------------------------------
Goodwill 1,750 571 2,321 913 227 235 67 1,442
Identifiable
assets 6,217 2,357 8,574 4,864 3,314 1,822 2,195 12,195
----------------------------------------------------------------------------
Total assets 7,967 2,928 10,895 5,777 3,541 2,057 2,262 13,637
----------------------------------------------------------------------------
Gross capital
expenditures 193 33 226 118 106 32 35 291
----------------------------------------------------------------------------
REGULATED NON-REGULATED
------------------------------------------
Quarter Ended Inter-
March 31,
2016 Caribbean Energy Non- Corporate segment
($ millions) Electric Infrastructure Utility and Other eliminations Total
----------------------------------------------------------------------------
Revenue 75 28 - 2 (18) 1,757
Energy supply
costs 37 1 - - (15) 692
Operating
expenses 12 7 - 9 (3) 458
Depreciation
and
amortization 13 6 - 1 - 234
----------------------------------------------------------------------------
Operating
income 13 14 - (8) - 373
Other income
(expenses),
net 3 2 - (17) - (4)
Finance
charges 3 1 - 24 - 139
Income tax
expense
(recovery) - - - (17) - 42
----------------------------------------------------------------------------
Net earnings
(loss) 13 15 - (32) - 188
Non-
controlling
interests 3 4 - - - 7
Preference
share
dividends - - - 19 - 19
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 10 11 - (51) - 162
----------------------------------------------------------------------------
Goodwill 184 - - - - 4,005
Identifiable
assets 1,027 994 - 294 (127)24,011
----------------------------------------------------------------------------
Total assets 1,211 994 - 294 (127)28,016
----------------------------------------------------------------------------
Gross capital
expenditures 22 11 - 2 - 426
----------------------------------------------------------------------------
Quarter Ended
March 31,
2015
($ millions)
----------------------------------------------------------------------------
Revenue 78 7 53 7 (9) 1,915
Energy supply
costs 45 - - - - 833
Operating
expenses 12 3 44 5 (3) 473
Depreciation
and
amortization 11 1 6 - - 215
----------------------------------------------------------------------------
Operating
income 10 3 3 2 (6) 394
Other income
(expenses),
net 1 - - 9 - 17
Finance
charges 4 - 6 21 (6) 134
Income tax
expense
(recovery) - - (1) (9) - 57
----------------------------------------------------------------------------
Net earnings
(loss) 7 3 (2) (1) - 220
Non-
controlling
interests 2 - - - - 2
Preference
share
dividends - - - 20 - 20
----------------------------------------------------------------------------
Net earnings
(loss)
attributable
to common
equity
shareholders 5 3 (2) (21) - 198
----------------------------------------------------------------------------
Goodwill 179 - - - - 3,942
Identifiable
assets 1,012 1,035 687 552 (440)23,615
----------------------------------------------------------------------------
Total assets 1,191 1,035 687 552 (440)27,557
----------------------------------------------------------------------------
Gross capital
expenditures 21 11 4 1 - 554
----------------------------------------------------------------------------
Related party transactions are in the normal course of operations and are measured at the exchange amount, which is the amount of consideration established and agreed to by the related parties. The significant related party inter-segment transactions for the three months ended March 31, 2016 and 2015 were as follows:
Significant Related Party Inter-Segment Transactions Quarter Ended
March 31
($ millions) 2016 2015
----------------------------------------------------------------------------
Sales from Non-Regulated Energy Infrastructure to
Regulated Electric Utilities - Canadian 15 -
Revenue from Regulated Electric Utilities - Canadian
to Non-Regulated Energy Infrastructure 3 -
Sales from Regulated Electric Utilities - Canadian
to Non-Utility - 2
Inter-segment finance charges on lending from:
Corporate to Non-Utility - 6
----------------------------------------------------------------------------
The significant related party inter-segment asset balances were as follows:
As at March 31
($ millions) 2016 2015
----------------------------------------------------------------------------
Inter-segment lending from:
Non-Regulated Energy Infrastructure to Eastern
Canadian Electric Utilities 20 20
Corporate to Regulated Electric Utilities -
Canadian 46 -
Corporate to Non-Utility - 410
Other inter-segment assets - Regulated Electric &
Gas Utilities - United States to Corporate 17 -
Other inter-segment assets 44 10
----------------------------------------------------------------------------
Total inter-segment eliminations 127 440
----------------------------------------------------------------------------
5. REGULATORY ASSETS AND LIABILITIES
A summary of the Corporation's regulatory assets and liabilities is provided below. For a detailed description of the nature of the Corporation's regulatory assets and liabilities, refer to Note 8 to the Corporation's 2015 annual audited consolidated financial statements.
As at
March 31, December 31,
($ millions) 2016 2015
----------------------------------------------------------------------------
Regulatory assets
Deferred income taxes 932 936
Employee future benefits 593 627
Deferred energy management costs 148 145
Manufactured gas plant ("MGP") site remediation
deferral (Note 19) 112 121
Deferred lease costs 99 90
Rate stabilization accounts 93 119
Deferred operating overhead costs 69 66
Derivative instruments (Note 15) 64 74
Final mine reclamation and retiree health care
costs (Note 19) 38 39
Deferred net losses on disposal of utility capital
assets and intangible assets 32 33
Property tax deferrals 28 30
Springerville Unit 1 unamortized leasehold
improvements 26 30
Other regulatory assets 252 222
----------------------------------------------------------------------------
Total regulatory assets 2,486 2,532
Less: current portion (247) (246)
----------------------------------------------------------------------------
Long-term regulatory assets 2,239 2,286
----------------------------------------------------------------------------
As at
March 31, December 31,
($ millions) 2016 2015
----------------------------------------------------------------------------
Regulatory liabilities
Non-asset retirement obligation removal cost
provision 1,040 1,060
Rate stabilization accounts 170 212
Electric and gas moderator account 78 88
Renewable energy surcharge 44 47
Employee future benefits 40 44
Customer and community benefits obligation 26 32
Other regulatory liabilities 176 155
----------------------------------------------------------------------------
Total regulatory liabilities 1,574 1,638
Less: current portion (285) (298)
----------------------------------------------------------------------------
Long-term regulatory liabilities 1,289 1,340
----------------------------------------------------------------------------
6. LONG-TERM DEBT
As at
March 31, December 31,
($ millions) 2016 2015
----------------------------------------------------------------------------
Long-term debt 10,335 10,689
Long-term classification of credit facility
borrowings (Note 17) 609 551
----------------------------------------------------------------------------
Total long-term debt (Note 15) 10,944 11,240
Less: Deferred financing costs (70) (72)
Less: Current installments of long-term debt (396) (384)
----------------------------------------------------------------------------
10,478 10,784
----------------------------------------------------------------------------
In April 2016 FortisBC Energy issued $300 million of unsecured debentures in a dual tranche of 10-year $150 million at 2.58% and 30-year $150 million at 3.67%. The net proceeds will be used to repay credit facility borrowings and finance the Company's capital expenditure program.
7. COMMON SHARES
Common shares issued during the period were as follows:
Quarter Ended
March 31, 2016
Number of
Shares Amount
(in thousands) ($ millions)
----------------------------------------------------------------------------
Balance, beginning of period 281,562 5,867
Dividend Reinvestment Plan 779 29
Consumer Share Purchase Plan 7 -
Employee Share Purchase Plan 141 5
Stock Option Plans 560 16
Conversion of convertible debentures 1 -
----------------------------------------------------------------------------
Balance, end of period 283,050 5,917
----------------------------------------------------------------------------
8. STOCK-BASED COMPENSATION PLANS
Stock Options
In February 2016 the Corporation granted 788,188 options to purchase common shares under its 2012 Stock Option Plan ("2012 Plan") at the five-day volume weighted average trading price immediately preceding the date of grant of $37.30. The options granted under the 2012 Plan are exercisable for a period not to exceed ten years from the date of grant, expire no later than three years after the termination, death or retirement of the optionee and vest evenly over a four-year period on each anniversary of the date of grant. Directors are not eligible to receive grants of options under the 2012 Plan.
The fair value of each option granted was $2.41 per option. The fair value was estimated at the date of grant using the Black-Scholes fair value option-pricing model and the following assumptions:
Dividend yield (%) 3.9
Expected volatility (%) 16.4
Risk-free interest rate (%) 0.7
Weighted average expected life (years) 5.5
Directors' Deferred Share Unit Plan
In January 2016, 8,085 Deferred Share Units ("DSUs") were granted to the Corporation's Board of Directors, representing the first quarter equity component of the Directors' annual compensation and, where opted, their first quarter component of annual retainers in lieu of cash. Each DSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. The DSUs are fully vested at the date of grant.
Performance Share Unit Plans
In February 2016 the Corporation granted 341,241 Performance Share Units ("PSUs") under the 2015 PSU Plan to senior management of the Corporation and its subsidiaries. The Corporation's PSU Plans represent a component of long-term compensation awarded to senior management of the Corporation and its subsidiaries. Each PSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting and performance period, at which time a cash payment may be made. Each PSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors. As at March 31, 2016, the estimated payout percentages for the grants under the 2013 and 2015 PSU Plans ranged from 82% to 112%.
Restricted Share Unit Plans
In February 2016 the Corporation granted 70,393 Restricted Share Units ("RSUs") under the 2015 RSU Plan to senior management of the Corporation and its subsidiaries. The Corporation's RSU Plan represents a component of long-term compensation awarded to senior management of the Corporation and its subsidiaries. Each RSU represents a unit with an underlying value equivalent to the value of one common share of the Corporation and is subject to a three-year vesting period, at which time a cash payment may be made. Each RSU is entitled to accrue notional common share dividends equivalent to those declared by the Corporation's Board of Directors.
For the three months ended March 31, 2016, stock-based compensation expense of approximately $9 million was recognized ($4 million for the three months ended March 31, 2015).
9. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group Registered Retirement Savings Plans and group 401(k) plans, for employees. The Corporation and certain subsidiaries also offer other post-employment benefit ("OPEB") plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following table.
Quarter Ended March 31
Defined Benefit
Pension Plans OPEB Plans
($ millions) 2016 2015 2016 2015
------------------------------------------------
Components of net benefit
cost:
Service costs 16 17 4 4
Interest costs 27 27 6 6
Expected return on plan
assets (36) (34) (3) (3)
Amortization of actuarial
losses 12 14 - 1
Amortization of past service
credits - - (3) (3)
Regulatory adjustments 2 - 2 2
----------------------------------------------------------------------------
Net benefit cost 21 24 6 7
----------------------------------------------------------------------------
For the three months ended March 31, 2016, the Corporation expensed $8 million ($8 million for the three months ended March 31, 2015) related to defined contribution pension plans.
10. OTHER INCOME (EXPENSES), NET
Quarter Ended
March 31
($ millions) 2016 2015
----------------------------------------------------------------------------
Equity component of allowance for funds used during
construction ("AFUDC") 7 4
Equity income - Belize Electricity 2 -
Interest income 2 3
Acquisition-related expenses (20) -
Net foreign exchange gain - 9
Other income (expenses), net 5 1
----------------------------------------------------------------------------
(4) 17
----------------------------------------------------------------------------
The acquisition-related expenses are associated with the pending Acquisition of ITC (Note 1).
The net foreign exchange gain related to the translation into Canadian dollars of the Corporation's previous US dollar-denominated long-term other asset, that represented the book value of the Corporation's expropriated investment in Belize Electricity, which was settled in August 2015.
11. FINANCE CHARGES
Quarter Ended
March 31
($ millions) 2016 2015
----------------------------------------------------------------------------
Interest - Long-term debt and capital lease and
finance obligations 145 140
- Short-term borrowings 2 3
Debt component of AFUDC (8) (9)
----------------------------------------------------------------------------
139 134
----------------------------------------------------------------------------
12. INCOME TAXES
Income taxes differ from the amount that would be expected to be generated by applying the enacted combined Canadian federal statutory and provincial income tax rate to earnings before income taxes. The following is a reconciliation of consolidated statutory income taxes to consolidated effective income taxes.
Quarter Ended
March 31
($ millions, except as noted) 2016 2015
----------------------------------------------------------------------------
Combined Canadian federal and provincial statutory
income tax rate 27.5% 29.0%
----------------------------------------------------------------------------
Statutory income tax rate applied to earnings
before income taxes 63 80
Difference between Canadian statutory rate and
rates applicable to foreign subsidiaries (8) (3)
Difference between Canadian provincial statutory
rates applicable to subsidiaries in different
Canadian jurisdictions (2) (5)
Items capitalized for accounting purposes but
expensed for income tax purposes (13) (15)
Other 2 -
----------------------------------------------------------------------------
Income tax expense 42 57
----------------------------------------------------------------------------
Effective income tax rate 18.3% 20.6%
----------------------------------------------------------------------------
13. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share ("EPS") on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the "if-converted" method for convertible securities.
EPS was as follows:
Quarter Ended March 31
2016 2015
------------------------------
Weighted Weighted
Net Earnings Average Net Earnings Average
to Common Number of to Common Number of
Shareholders Shares Shareholders Shares
($ millions) (millions) EPS ($ millions) (millions) EPS
----------------------------------------------------------------------------
Basic EPS (1) 162 282.4 $0.57 198 276.7 $0.72
----------------------------------------------------------------------------
Effect of
potential
dilutive
securities:
Stock Options - 0.6 - 1.0
Preference
Shares 2 5.6 2 5.4
----------------------------------------------------------------------------
Diluted EPS 164 288.6 $0.57 200 283.1 $0.71
----------------------------------------------------------------------------
(1) The Corporation's Directors DSUs are considered participating securities
as they participate in dividend equivalents and these securities are
fully vested at the time of grant. The impact of the DSUs have been
included in the weighted average number of shares outstanding for
purposes of calculating EPS.
14. SUPPLEMENTARY INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
Quarter Ended
March 31
($ millions) 2016 2015
----------------------------------------------------------------------------
Change in non-cash operating working capital:
Accounts receivable and other current assets 63 (24)
Prepaid expenses (17) (2)
Inventories 51 60
Regulatory assets - current portion 7 39
Accounts payable and other current liabilities (69) (10)
Regulatory liabilities - current portion (5) 14
----------------------------------------------------------------------------
30 77
----------------------------------------------------------------------------
Non-cash investing and financing activities:
Common share dividends reinvested 29 34
Additions to utility capital assets and intangible
assets included in current liabilities and long-
term other liabilities 126 196
Contributions in aid of construction included in
current assets 4 5
Exercise of stock options into common shares 2 2
----------------------------------------------------------------------------
15. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS
Fair value is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value.
The three levels of the fair value hierarchy are defined as follows:
Level 1: Fair value determined using unadjusted quoted prices in active
markets;
Level 2: Fair value determined using pricing inputs that are observable; and
Level 3: Fair value determined using unobservable inputs only when relevant
observable inputs are not available.
The fair values of the Corporation's financial instruments, including derivatives, reflect point-in-time estimates based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation's future consolidated earnings or cash flows.
The following table presents, by level within the fair value hierarchy, the Corporation's assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement and there were no transfers between the levels in the periods presented. For derivative instruments, the Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions.
As at
Fair value March 31, December 31,
($ millions) hierarchy 2016 2015
--------------------------------------
Assets
Energy contracts subject to regulatory
deferral (1) (2) (3) Levels 2/3 5 7
Energy contracts not subject to
regulatory deferral (1) (2) Level 3 1 2
Available-for-sale investment (4) Level 1 37 33
Assets held for sale (5) Level 2 - 9
Other investments (6) Level 1 11 12
----------------------------------------------------------------------------
Total gross assets 54 63
Less: Counterparty netting not offset on the
balance sheet (7) (3) (6)
----------------------------------------------------------------------------
Total net assets 51 57
----------------------------------------------------------------------------
Liabilities
Energy contracts subject to regulatory
deferral (1) (2) (8) Levels 1/2/3 67 78
Interest rate swaps - cash flow hedges
(9) Level 2 4 5
----------------------------------------------------------------------------
Total gross liabilities 71 83
Less: Counterparty netting not offset on the
balance sheet (7) (3) (6)
----------------------------------------------------------------------------
Total net liabilities 68 77
----------------------------------------------------------------------------
(1) The fair value of the Corporation's energy contracts is recorded in
accounts receivable and other current assets, long-term other assets,
accounts payable and other current liabilities and long-term other
liabilities. Unrealized gains and losses arising from changes in fair
value of these contracts are deferred as a regulatory asset or liability
for recovery from, or refund to, customers in future rates as permitted
by the regulators, with the exception of long-term wholesale trading
contracts.
(2) Changes in one or more of the unobservable inputs could have a
significant impact on the fair value measurement depending on the
magnitude and direction of the change for each input. The impacts of
changes in fair value are subject to regulatory recovery, with the
exception of long-term wholesale trading contracts.
(3) As at March 31, 2016, includes $3 million - level 2 and $2 million -
level 3 (December 31, 2015 - $2 million - level 2 and $5 million - level
3)
(4) The available-for-sale investment is recorded in long-term other assets
and unrealized gains and losses arising from changes in fair value are
recorded in other comprehensive income until they become realized and
are reclassified to earnings.
(5) As at December 31, 2015, assets held for sale were associated with the
Walden hydroelectric generating facility and were included in accounts
receivable and other current assets on the consolidated balance sheet.
(6) Included in long-term other assets on the consolidated balance sheet
(7) Certain energy contracts are subject to legally enforceable master
netting arrangements to mitigate credit risk and netted by counterparty
where the intent and legal right to offset exists.
(8) As at March 31, 2016, includes $32 million - level 2 and $35 million -
level 3 (December 31, 2015 - $1 million - level 1, $52 million - level 2
and $25 million - level 3)
(9) The fair value of the Corporation's interest rate swaps is recorded in
accounts payable and other current liabilities and long-term other
liabilities. Unrealized gains and losses arising from changes in fair
value are recorded in other comprehensive income until they become
realized and are reclassified to earnings.
Derivative Instruments
The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments are estimates of the amounts that the utilities would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates.
Energy Contracts Subject to Regulatory Deferral
UNS Energy holds electricity power purchase contracts and gas swap and option contracts to reduce its exposure to energy price risk associated with purchased power and gas requirements. UNS Energy primarily applies the market approach for fair value measurements using independent third-party information, where possible. When published prices are not available, adjustments are applied based on historical price curve relationships and transmission and line losses. The fair value of gas option contracts is estimated using a Black-Scholes option-pricing model, which includes inputs such as implied volatility, interest rates, and forward price curves. UNS Energy also considers the impact of counterparty credit risk using current and historical default and recovery rates, as well as its own credit risk using credit default swap data.
Central Hudson holds electricity swap contracts and gas swap and option contracts to minimize commodity price volatility for electricity and natural gas purchases by fixing the effective purchase price for the defined commodities. The fair value of the electricity swap contracts and gas swap and option contracts was calculated using forward pricing provided by independent third parties.
FortisBC Energy holds gas supply contract premiums to fix the effective purchase price of natural gas, as the majority of the natural gas supply contracts have floating, rather than fixed, prices. The fair value of the natural gas derivatives was calculated using the present value of cash flows based on market prices and forward curves for the cost of natural gas.
As at March 31, 2016, these energy contract derivatives were not designated as hedges; however, any unrealized gains or losses associated with changes in the fair value of the derivatives are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulators. These unrealized losses and gains would otherwise be recorded in earnings. As at March 31, 2016, unrealized losses of $64 million (December 31, 2015 - $74 million) were recognized in regulatory assets and unrealized gains of $2 million were recognized in regulatory liabilities (December 31, 2015 - $3 million) (Note 5).
Energy Contracts Not Subject to Regulatory Deferral
In June 2015 UNS Energy entered into long-term wholesale trading contracts that qualify as derivative instruments. The unrealized gains and losses on these derivative instruments are recorded in earnings, as they do not qualify for regulatory deferral. Ten percent of any realized gains on these contracts are shared with the ratepayer through UNS Energy's rate stabilization accounts.
Cash Flow Hedges
UNS Energy holds an interest rate swap, expiring in 2020, to mitigate its exposure to volatility in variable interest rates on lease debt. The after-tax unrealized gains and losses on cash flow hedges are recorded in other comprehensive income and reclassified to earnings as they become realized. The loss expected to be reclassified to earnings within the next 12 months is estimated to be approximately $1 million. The realized losses from cash flow hedges were less than $1 million for the three months ended March 31, 2016 and 2015.
Central Hudson holds interest rate cap contracts expiring in 2017 and 2019 on bonds with a total principal amount of US$64 million. Variations in the interest costs of the bonds, including any gains or losses associated with the interest rate cap contracts, are deferred as a regulatory asset or liability for recovery from, or refund to, customers in future rates, as permitted by the regulator and do not impact earnings.
Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation's consolidated statement of cash flows.
Volume of Derivative Activity
As at March 31, 2016, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.
Maturity Contracts There-
Volume (year) (#) 2016 2017 2018 2019 2020 after
----------------------------------------------------------------------------
Energy contracts
subject to regulatory
deferral:
Electricity swap
contracts (gigawatt
hours ("GWh")) 2019 7 749 730 438 219 - -
Electricity power
purchase contracts
(GWh) 2017 28 983 145 - - - -
Gas swap and option
contracts (petajoules
("PJ")) 2018 125 24 11 4 - - -
Gas supply contract
premiums (PJ) 2024 93 79 46 44 26 22 63
Energy contracts not
subject to regulatory
deferral:
Long-term wholesale
trading contracts
(GWh) 2016 6 655 - - - - -
----------------------------------------------------------------------------
Financial Instruments Not Carried At Fair Value
The following table discloses the estimated fair value measurements of the Corporation's financial instruments not carried at fair value. The fair values were measured using Level 2 pricing inputs, except as noted. The carrying values of the Corporation's consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows:
As at
(Liability) March 31, 2016 December 31, 2015
------------------------
Carrying Estimated Carrying Estimated
($ millions) Value Fair Value Value Fair Value
----------------------------------------------------------------------------
Long-term debt, including (11,240) (12,614)
current portion (Note 6)
(1) (10,944) (12,015)
Waneta Partnership (56)
promissory note (2) (57) (60) (59)
----------------------------------------------------------------------------
(1) The Corporation's $200 million unsecured debentures due 2039 and
consolidated borrowings under credit facilities classified as long-term
debt of $609 million (December 31, 2015 - $551 million) are valued using
Level 1 inputs. All other long-term debt is valued using Level 2 inputs.
(2) Included in long-term other liabilities on the consolidated balance
sheet (Note 16).
The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.
16. VARIABLE INTEREST ENTITY
On adoption of ASU No. 2015-02, Amendments to the Consolidation Analysis, effective January 1, 2016, Fortis was required to reassess its limited partnerships under the voting interest model. As a result, the Corporation's ownership interest in the Waneta Partnership is considered to be a variable interest entity ("VIE") based on an assessment of the rights of the limited partners and the general partner. It was determined under the VIE model that the Corporation is the primary beneficiary of the Waneta Partnership and should, therefore, continue to consolidate its investment. As the primary beneficiary, the Corporation has the power to direct the activities of the partnership and the obligation to absorb losses or the right to receive benefits that could potentially be significant to the partnership, as discussed below.
The purpose of the Waneta Partnership was to construct, own and operate the Waneta Expansion hydroelectric generating facility dam ("Waneta Expansion") on the Pend d'Oreille River south of Trail, British Columbia, which was completed in April 2015. The Corporation has a 51% controlling ownership interest in the Waneta Partnership, with Columbia Power Corporation and Columbia Basin Trust ("CPC/CBT") holding the remaining 49% interest. The general partner, which is owned by the Corporation and CPC/CBT in the same proportion as the Waneta Partnership, has a 0.01% interest in the Waneta Partnership. Each partner pays its proportionate share of the costs and is entitled to a proportionate share of the net revenue and expenses. The construction of the Waneta Expansion was jointly financed and managed by the Corporation and CPC/CBT. The Waneta Expansion is operated and maintained by a wholly owned subsidiary of the Corporation and output is sold to BC Hydro and FortisBC Electric under 40-year contracts.
The table below details the assets and liabilities of the Waneta Partnership included in the Corporation's consolidated balance sheets.
As at
March 31, December 31,
($ millions) 2016 2015
----------------------------------------------------------------------------
ASSETS
Cash and cash equivalents 16 23
Accounts receivable and other current assets 13 14
Utility capital assets 706 708
Intangible assets 30 30
----------------------------------------------------------------------------
765 775
----------------------------------------------------------------------------
LIABILITIES
Accounts payable and current liabilities 10 18
Other liabilities (Note 15) 74 74
----------------------------------------------------------------------------
84 92
----------------------------------------------------------------------------
For the three months ended March 31, 2016, the Waneta Partnership reported revenue of $19 million, operating expenses of $5 million, depreciation and amortization expense of $5 million and finance charges of $1 million.
17. FINANCIAL RISK MANAGEMENT
The Corporation is primarily exposed to credit risk, liquidity risk and market risk as a result of holding financial instruments in the normal course of business.
Credit risk Risk that a counterparty to a financial instrument might
fail to meet its obligations under the terms of the
financial instrument.
Liquidity risk Risk that an entity will encounter difficulty in raising
funds to meet commitments associated with financial
instruments.
Market risk Risk that the fair value or future cash flows of a financial
instrument will fluctuate due to changes in market prices.
The Corporation is exposed to foreign exchange risk,
interest rate risk and commodity price risk.
Credit Risk
For cash equivalents, trade and other accounts receivable, and long-term other receivables, the Corporation's credit risk is generally limited to the carrying value on the consolidated balance sheet. The Corporation generally has a large and diversified customer base, which minimizes the concentration of credit risk. The Corporation and its subsidiaries have various policies to minimize credit risk, which include requiring customer deposits, prepayments and/or credit checks for certain customers and performing disconnections and/or using third-party collection agencies for overdue accounts.
FortisAlberta has a concentration of credit risk as a result of its distribution service billings being to a relatively small group of retailers. As at March 31, 2016, FortisAlberta's gross credit risk exposure was approximately $117 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $1 million by obtaining from the retailers either a cash deposit, bond, letter of credit, an investment-grade credit rating from a major rating agency, or a financial guarantee from an entity with an investment-grade credit rating.
UNS Energy, Central Hudson and FortisBC Energy may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The Companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist. They also limit credit risk by only dealing with counterparties that have investment-grade credit ratings. At UNS Energy, contractual arrangements also contain certain provisions requiring counterparties to derivative instruments to post collateral under certain circumstances.
Liquidity Risk
The Corporation's consolidated financial position could be adversely affected if it, or one of its subsidiaries, fails to arrange sufficient and cost-effective financing to fund, among other things, capital expenditures, acquisitions and the repayment of maturing debt. The ability to arrange sufficient and cost-effective financing is subject to numerous factors, including the consolidated results of operations and financial position of the Corporation and its subsidiaries, conditions in capital and bank credit markets, ratings assigned by rating agencies and general economic conditions.
To help mitigate liquidity risk, the Corporation and its regulated utilities have secured committed credit facilities to support short-term financing of capital expenditures and seasonal working capital requirements.
The Corporation's committed corporate credit facility is used for interim financing of acquisitions and for general corporate purposes. Depending on the timing of cash payments from subsidiaries, borrowings under the Corporation's committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. As at March 31, 2016, over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $240 million. The combination of available credit facilities and relatively low annual debt maturities and repayments provides the Corporation and its subsidiaries with flexibility in the timing of access to capital markets.
As at March 31, 2016, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.5 billion, of which approximately $2.3 billion was unused, including $590 million unused under the Corporation's committed revolving corporate credit facility. The credit facilities are syndicated mostly with the seven largest Canadian banks, as well as large banks in the United States, with no one bank holding more than 20% of these facilities. Approximately $3.3 billion of the total credit facilities are committed facilities with maturities ranging from 2016 through 2020.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
As at
December
Regulated Corporate March 31, 31,
($ millions) Utilities and Other 2016 2015
----------------------------------------------------------------------------
Total credit facilities (1) 2,161 1,324 3,485 3,565
Credit facilities utilized:
Short-term borrowings (2) (477) - (477) (511)
Long-term debt (Note 6) (3) (110) (499) (609) (551)
Letters of credit outstanding (69) (36) (105) (104)
----------------------------------------------------------------------------
Credit facilities unused 1,505 789 2,294 2,399
----------------------------------------------------------------------------
(1)Total credit facilities exclude a $300 million option to increase the
Corporation's committed corporate credit facility, as discussed below.
(2) The weighted average interest rate on short-term borrowings was
approximately 1.0% as at March 31, 2016 (December 31, 2015 - 1.0%).
(3) As at March 31, 2016, credit facility borrowings classified as long-term
debt included $110 million in current installments of long-term debt on
the consolidated balance sheet (December 31, 2015 - $71 million). The
weighted average interest rate on credit facility borrowings classified
as long-term debt was approximately 1.7% as at March 31, 2016 (December
31, 2015 - 1.5%).
As at March 31, 2016 and December 31, 2015, certain borrowings under the Corporation's and subsidiaries' credit facilities were classified as long-term debt. These borrowings are under long-term committed credit facilities and it is management's intention to refinance these borrowings with long-term permanent financing during future periods. The significant changes in credit facilities from that disclosed in the Corporation's 2015 annual audited consolidated financial statements are as follows.
In April 2016 FortisBC Electric amended its $150 million unsecured committed revolving credit facility to now mature in May 2019.
In April 2016 FHI amended its unsecured committed revolving credit facility resulting in an increase in the facility to $50 million and an extension of the maturity date to April 2019.
In April 2016 the Corporation amended its $1 billion unsecured committed revolving credit facility, resulting in an extension of the maturity date to July 2021. The Corporation has the option to increase the facility to $1.3 billion from $1 billion. As at March 31, 2016, the Corporation has not yet exercised this option.
In connection with the pending Acquisition of ITC, in February 2016 the Corporation obtained commitments of US$2.0 billion from Goldman Sachs Bank USA to bridge the long-term debt financing ("Debt Bridge Facility") and US$1.7 billion from The Bank of Nova Scotia to primarily bridge the sale of the minority investment in ITC ("Equity Bridge Facilities"). These non-revolving term senior unsecured credit facilities are repayable in full on the first anniversary of their advance. Goldman Sachs Bank USA has syndicated 60% of the Debt Bridge Facility to three other financial institutions, each of which have agreed to provide 20% of such facility. The Bank of Nova Scotia may syndicate a portion of the Equity Bridge Facilities. The credit facilities table does not include the US$3.7 billion Acquisition credit facilities.
The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. As at March 31, 2016, the Corporation's credit ratings were as follows:
Standard & Poor's ("S&P") A- / Negative (long-term corporate credit rating)
BBB+ / Negative (unsecured debt credit rating)
DBRS A (low) / Under Review - Negative Implications
(unsecured debt credit rating)
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 management's commitment to maintaining reasonable levels of debt at the holding company level. In February 2016, after the announcement by Fortis that it had entered into an agreement to acquire ITC, S&P affirmed the Corporation's long-term corporate credit rating at A-, revised its unsecured debt credit rating to BBB+ from A-, and revised its outlook on the Corporation to negative from stable. Similarly, in February 2016 DBRS placed the Corporation's credit rating under review with negative implications.
Market Risk
Foreign Exchange Risk
The Corporation's earnings from, and net investments in, foreign subsidiaries are exposed to fluctuations in the US dollar-to-Canadian dollar exchange rate. The Corporation has decreased the above-noted exposure through the use of US dollar-denominated borrowings at the corporate level. The foreign exchange gain or loss on the translation of US dollar-denominated interest expense partially offsets the foreign exchange gain or loss on the translation of the Corporation's foreign subsidiaries' earnings, which are denominated in US dollars. The reporting currency of UNS Energy, Central Hudson, Caribbean Utilities, Fortis Turks and Caicos and Belize Electric Company Limited is the US dollar.
As at March 31, 2016, the Corporation's corporately issued US$1,540 million (December 31, 2015 - US$1,535 million) long-term debt had been designated as an effective hedge of a portion of the Corporation's foreign net investments. As at March 31, 2016, the Corporation had approximately US$3,153 million (December 31, 2015 - US$3,137 million) in foreign net investments remaining to be hedged. Foreign currency exchange rate fluctuations associated with the translation of the Corporation's corporately issued US dollar-denominated borrowings designated as effective hedges are recorded on the consolidated balance sheet in accumulated other comprehensive income and serve to help offset unrealized foreign currency exchange gains and losses on the net investments in foreign subsidiaries, which gains and losses are also recorded on the consolidated balance sheet in accumulated other comprehensive income.
On an annual basis, it is estimated that a 5 cent, or 5%, increase or decrease in the US dollar relative to the Canadian dollar exchange rate of US$1.00=CDN$1.30 as at March 31, 2016 would increase or decrease earnings per common share of Fortis by approximately 4 cents, excluding the pending acquisition of ITC. Management will continue to hedge future exchange rate fluctuations related to the Corporation's foreign net investments and US dollar-denominated earnings streams, where possible, through future US dollar-denominated borrowings, and will continue to monitor the Corporation's exposure to foreign currency fluctuations on a regular basis.
Interest Rate Risk
The Corporation and most of its subsidiaries are exposed to interest rate risk associated with borrowings under variable-rate credit facilities, variable-rate long-term debt and the refinancing of long-term debt. The Corporation and its subsidiaries may enter into interest rate swap agreements to help reduce this risk.
Commodity Price Risk
UNS Energy is exposed to commodity price risk associated with changes in the market price of gas, purchased power and coal. Central Hudson is exposed to commodity price risk associated with changes in the market price of electricity and natural gas. FortisBC Energy is exposed to commodity price risk associated with changes in the market price of natural gas. The risks have been reduced by entering into derivative contracts that effectively fix the price of natural gas, power and electricity purchases. These derivative instruments are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, as permitted by the regulators, for recovery from, or refund to, customers in future rates (Note 15).
18. COMMITMENTS
There were no material changes in the nature and amount of the Corporation's commitments from the commitments disclosed in the Corporation's 2015 annual audited consolidated financial statements, except as follows.
UNS Energy is party to renewable power purchase agreements totalling approximately US$1,190 million as at March 31, 2016, which require UNS Energy to purchase 100% of the output of certain renewable energy generation facilities that have achieved commercial operation. In March 2016 one of the facilities achieved commercial operation, increasing estimated future payments of renewable power purchase contracts by US$58 million as at March 31, 2016.
In January 2016 the ownership of the San Juan generating station was restructured and a new coal supply agreement came into effect under which TEP's minimum purchase obligations are US$137 million as at March 31, 2016.
In February 2016 TEP entered into a settlement agreement with third-party owners of Springerville Unit 1 to purchase the third-party owners' 50.5% undivided interest in Springerville Unit 1 for US$85 million. The purchase is expected to close in the second quarter of 2016 (Note 19).
19. CONTINGENCIES
The Corporation and its subsidiaries are subject to various legal proceedings and claims associated with the ordinary course of business operations. Management believes that the amount of liability, if any, from these actions would not have a material adverse effect on the Corporation's consolidated financial position, results of operations or cash flows.
The following describes the nature of the Corporation's contingencies.
UNS Energy
Springerville Unit 1
In February 2016 TEP entered into an agreement with the third-party owners for the settlement and release of asserted claims and the purchase and sale of beneficial interests in Springerville Unit 1 (the "Agreement"). The Agreement provides that TEP will purchase the third-party owners' 50.5% undivided interest in Springerville Unit 1 for US$85 million and the third-party owners will pay TEP US$13 million for operating costs related to Springerville Unit 1 incurred on behalf of the third-party owners. Upon completion of the purchase, all outstanding disputes, pending litigation and arbitration proceedings between TEP and the third-party owners will be dismissed with prejudice.
The purchase of the third-party owners' undivided interest in Springerville Unit 1 is subject to, among other things, FERC approval and satisfaction of other customary closing conditions. TEP expects the purchase to close in the second quarter of 2016. However, there is no assurance that the settlement will be finalized or that the litigation will not continue. Therefore, at this time TEP cannot predict the outcome of the claims relating to Springerville Unit 1, and, due to the general and non-specific scope and nature of the claims, TEP cannot determine estimates of the range of loss, if any, at this time and, accordingly no amount has been accrued in the consolidated financial statements. Should the litigation matters continue, TEP intends to continue vigorously defending itself against the claims asserted by the third-party owners and to vigorously pursue the claims it has asserted against the owner trustees and co-trustees.
The following is the history of the outstanding disputes and pending litigation and arbitration proceedings between TEP and the third-party owners.
In November 2014 the Springerville Unit 1 third-party owners filed a complaint ("FERC Action") against TEP with FERC, alleging that TEP had not agreed to wheel power and energy for the third-party owners in the manner specified in the existing Springerville Unit 1 facility support agreement between TEP and the third-party owners and for the cost specified by the third-party owners. The third-party owners requested an order from FERC requiring such wheeling of the third-party owners' energy from their Springerville Unit 1 interests beginning in January 2015 for the price specified by the third-party owners. In February 2015 FERC issued an order denying the third-party owners' complaint. In March 2015 the third-party owners filed a request for rehearing in the FERC Action, which FERC denied in October 2015. In December 2015 the third-party owners appealed FERC's order denying the third-party owners' complaint to the U.S. Court of Appeals for the Ninth Circuit. In December 2015 TEP filed an unopposed motion to intervene in the Ninth Circuit appeal.
In December 2014 the third-party owners filed a complaint ("New York Action") against TEP in the Supreme Court of the State of New York, New York County. In response to motions filed by TEP to dismiss various counts and compel arbitration of certain of the matters alleged and the court's subsequent ruling on the motions, the third-party owners have amended the complaint three times, dropping certain of the allegations and raising others in the New York Action and in the arbitration proceeding described below. As amended, the New York Action alleges, among other things, that TEP failed to properly operate, maintain and make capital investments in Springerville Unit 1 during the term of the leases; and that TEP breached the lease transaction documents by refusing to pay certain of the third-party owners' claimed expenses. The third amended complaint seeks US$71 million in liquidated damages and direct and consequential damages in an amount to be determined at trial. The third-party owners have also agreed to stay their claim that TEP has not agreed to wheel power and energy as required pending the outcome of the FERC Action. In November 2015 the third-party owners filed a motion for summary judgment on their claim that TEP failed to pay certain of the third-party owners' claimed expenses.
In December 2014 and January 2015, Wilmington Trust Company, as owner trustees and lessors under the leases of the third-party owners, sent notices to TEP that alleged that TEP had defaulted under the third-party owners' leases. The notices demanded that TEP pay liquidated damages totalling approximately US$71 million. In letters to the owner trustees, TEP denied the allegations in the notices.
In April 2015 TEP filed a demand for arbitration with the American Arbitration Association ("AAA") seeking an award of the owner trustees and co-trustees' share of unreimbursed expenses and capital expenditures for Springerville Unit 1. In June 2015 the third-party owners filed a separate demand for arbitration with the AAA alleging, among other things, that TEP has failed to properly operate, maintain and make capital investments in Springerville Unit 1 since the leases have expired. The third-party owners' arbitration demand seeks declaratory judgments, damages in an amount to be determined by the arbitration panel and the third-party owners' fees and expenses. TEP and the third-party owners have since agreed to consolidate their arbitration demands into one proceeding. In August 2015 the third-party owners filed an amended arbitration demand adding claims that TEP has converted the third-party owners' water rights and certain emission reduction payments and that TEP is improperly dispatching the third-party owners' unscheduled Springerville Unit 1 power and capacity.
In October 2015 the arbitration panel granted TEP's motion for interim relief, ordering the owner trustees and co-trustees to pay TEP their pro-rata share of unreimbursed expenses and capital expenditures for Springerville Unit 1 during the pendency of the arbitration. The arbitration panel also denied the third-party owners' motion for interim relief, which had requested that TEP be enjoined from dispatching the third-party owners' unscheduled Springerville Unit 1 power and capacity. TEP has been scheduling the third-party owners' entitlement share of power from Springerville Unit 1, as permitted under the Springerville Unit 1 facility support agreement, since June 2015.
In November 2015 TEP filed a petition to confirm the interim arbitration order in the Supreme Court of the State of New York naming owner trustee and co-trustee as respondents. The petition seeks an order from the court confirming the interim arbitration order under the Federal Arbitration Act. In December 2015 the owner trustees filed an answer to the petition and a cross-motion to vacate the interim arbitration order.
As at March 31, 2016, TEP billed the third-party owners approximately US$29 million for their pro-rata share of Springerville Unit 1 expenses and US$6 million for their pro-rata share of capital expenditures, none of which had been paid as of May 2, 2016.
Mine Reclamation Costs
TEP pays ongoing reclamation costs related to coal mines that supply generating stations in which the Company has an ownership interest but does not operate. TEP is liable for a portion of final reclamation costs upon closure of the mines servicing the San Juan, Four Corners and Navajo generating stations. TEP's share of reclamation costs at all three mines is expected to be US$42 million upon expiration of the coal supply agreements, which expire between 2019 and 2031. The mine reclamation liability recorded as at March 31, 2016 was US$25 million (December 31, 2015 - US$25 million) and represents the present value of the estimated future liability.
Amounts recorded for final reclamation are subject to various assumptions, such as estimations of reclamation costs, the dates when final reclamation will occur, and the expected inflation rate. As these assumptions change, TEP will prospectively adjust the expense amounts for final reclamation over the remaining coal supply agreements' terms.
TEP is permitted to fully recover these costs from retail customers and, accordingly, these costs are deferred as a regulatory asset (Note 5).
Central Hudson
Site Investigation and Remediation Program
Central Hudson and its predecessors owned and operated MGPs to serve their customers' heating and lighting needs. These plants manufactured gas from coal and oil beginning in the mid to late 1800s, with all sites ceasing operations by the 1950s. This process produced certain by-products that may pose risks to human health and the environment.
The New York State Department of Environmental Conservation ("DEC"), which regulates the timing and extent of remediation of MGP sites in New York State, has notified Central Hudson that it believes the Company or its predecessors at one time owned and/or operated MGPs at seven sites in Central Hudson's franchise territory. The DEC has further requested that the Company investigate and, if necessary, remediate these sites under a Consent Order, Voluntary Clean-up Agreement or Brownfield Clean-up Agreement. Central Hudson accrues for remediation costs based on the amounts that can be reasonably estimated. As at March 31, 2016, an obligation of US$92 million (December 31, 2015 - US$92 million) was recognized in respect of site investigation and remediation and, based upon cost model analysis completed in 2014, it is estimated, with a 90% confidence level, that total costs to remediate these sites over the next 30 years will not exceed US$169 million.
Central Hudson has notified its insurers and intends to seek reimbursement from insurers for remediation, where coverage exists. Further, as authorized by the PSC, Central Hudson is currently permitted to defer, for future recovery from customers, differences between actual costs for MGP site investigation and remediation and the associated rate allowances, with carrying charges to be accrued on the deferred balances at the authorized pre-tax rate of return. In the three-year rate order issued by the PSC in June 2015, Central Hudson's authorization to defer all site investigation and remediation costs was reaffirmed and extended through June 2018 (Note 5).
Asbestos Litigation
Prior to and after its acquisition by Fortis, various asbestos lawsuits have been brought against Central Hudson. While a total of 3,351 asbestos cases have been raised, 1,168 remained pending as at March 31, 2016. Of the cases no longer pending against Central Hudson, 2,027 have been dismissed or discontinued without payment by the Company, and Central Hudson has settled the remaining 156 cases. The Company is presently unable to assess the validity of the outstanding asbestos lawsuits; however, based on information known to Central Hudson at this time, including the Company's experience in the settlement and/or dismissal of asbestos cases, Central Hudson believes that the costs which may be incurred in connection with the remaining lawsuits will not have a material effect on its financial position, results of operations or cash flows and, accordingly, no amount has been accrued in the consolidated financial statements.
FortisBC Electric
The Government of British Columbia filed a claim in the British Columbia Supreme Court in June 2012 claiming on its behalf, and on behalf of approximately 17 homeowners, damages suffered as a result of a landslide caused by a dam failure in Oliver, British Columbia in 2010. The Government of British Columbia alleges in its claim that the dam failure was caused by the defendants', which include FortisBC Electric, use of a road on top of the dam. The Government of British Columbia estimates its damages and the damages of the homeowners, on whose behalf it is claiming, to be approximately $15 million. While FortisBC Electric has notified its insurers, it has been advised by the Government of British Columbia that a response to the claim is not required at this time. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
FHI
In April 2013 FHI and Fortis were named as defendants in an action in the B.C. Supreme Court by the Coldwater Indian Band ("Band"). The claim is in regard to interests in a pipeline right of way on reserve lands. The pipeline on the right of way was transferred by FHI (then Terasen Inc.) to Kinder Morgan Inc. in April 2007. The Band seeks orders cancelling the right of way and claims damages for wrongful interference with the Band's use and enjoyment of reserve lands. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
20. SUBSEQUENT EVENTS
Acquisition of Aitken Creek Gas Storage Facility
On April 1, 2016, Fortis acquired ACGS from Chevron for approximately US$266 million. The net purchase price was primarily financed through US dollar-denominated credit facility borrowings under the Corporation's committed revolving credit facility.
ACGS owns 93.8% of the Aitken Creek gas storage site ("Aitken Creek"), with the remaining share owned by BP Canada Energy Company. Aitken Creek is the only underground natural gas storage facility in British Columbia and has a total working gas capacity of 77 billion cubic feet. The facility is an integral part of Western Canada's natural gas transmission network. ACGS also owns 100% of the North Aitken Creek gas storage site which offers future expansion potential.
FERC Order at TEP
In April 2016 FERC issued an order relating to late-filed transmission service agreements, which directs TEP to issue time value refunds on revenue collected from relevant counterparties to the agreements in an amount up to $18 million (US$13 million). The refund was recognized in the first quarter of 2016, resulting in a reduction of earnings of $11 million (US$8 million) after tax.
21. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period presentation.
CORPORATE INFORMATION
Fortis Inc. is a leader in the North American electric and gas utility business, with total assets of approximately $28 billion and fiscal 2015 revenue of $6.7 billion. The Corporation's asset mix is approximately 96% regulated (70% electric, 26% gas), with the remaining 4% comprised of non-regulated energy infrastructure. The Corporation's regulated utilities serve more than 3 million customers across Canada, the United States and the Caribbean.
The Common Shares; First Preference Shares, Series E; First Preference Shares, Series F; First Preference Shares, Series G; First Preference Shares, Series H; First Preference Shares, Series I; First Preference Shares, Series J; First Preference Shares, Series K; and First Preference Shares, Series M of Fortis are listed on the Toronto Stock Exchange and trade under the ticker symbols FTS, FTS.PR.E, FTS.PR.F, FTS.PR.G, FTS.PR.H, FTS.PR.I, FTS.PR.J, FTS.PR.K, and FTS.PR.M, respectively.
Transfer Agent and Registrar:
Computershare Trust Company of Canada
8th Floor, 100 University Avenue
Toronto, ON M5J 2Y1
T: 514.982.7555 or 1.866.586.7638
F: 416.263.9394 or 1.888.453.0330
W: www.investorcentre.com/fortisinc
Additional information, including the Fortis 2015 Annual Information Form, Management Information Circular and Annual Report, are available on SEDAR at www.sedar.com and on the Corporation's website at www.fortisinc.com.
Contacts:
Janet Craig
Vice President, Investor Relations
Fortis Inc.
709.737.2863
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