ST. JOHN’S, NEWFOUNDLAND AND LABRADOR–(Marketwired – Nov. 4, 2016) – Fortis Inc. (“Fortis” or the “Corporation”) (TSX:FTS)(NYSE:FTS), a leader in the North American regulated electric and gas utility industry, released its third quarter results today. The Corporation’s net earnings attributable to common equity shareholders for the third quarter were $127 million, or $0.45 per common share, compared to $151 million, or $0.54 per common share, for the third quarter of 2015. On a year-to-date basis, earnings were $396 million, or $1.40 per common share, compared to $593 million, or $2.13 per common share, for 2015. Results reflect acquisition-related expenses associated with ITC Holdings Corp. (“ITC”) in 2016 and gains on the sale of non-core assets in 2015.
On an adjusted basis, net earnings attributable to common equity shareholders for the third quarter were $154 million, or $0.54 per common share, an increase of $9 million, or $0.02 per common share, over the third quarter of 2015. On a year-to-date basis, adjusted earnings were $475 million, or $1.67 per common share, an increase of $28 million, or $0.06 per common share, over 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 and nine months ended September 30, 2016.
Strong performance continued in the third quarter
– Factors that resulted in growth in adjusted earnings for the third quarter included:
- strong performance at most of the Corporation’s regulated utilities. Performance was driven by UNS Energy, largely due to the settlement of Springerville Unit 1 matters, and Central Hudson, due to an increase in delivery revenue. The Corporation’s utilities in Canada and the Caribbean, with the exception of FortisAlberta, also delivered strong results;
- the timing of quarterly earnings at FortisBC Electric compared to the third quarter of 2015; and
- contribution of $2 million from the Aitken Creek gas storage facility in British Columbia, which was acquired in early April 2016.
– Earnings growth for the third quarter was tempered by:
- lower earnings at FortisAlberta due to higher operating expenses, a negative capital tracker revenue adjustment as a result of the outcome of the Generic Cost of Capital (“GCOC”) Proceeding in Alberta, as further discussed below, and lower average energy consumption;
- the sale of hotel assets in 2015; and
- an increase in Corporate and Other expenses.
– Cash flow from operating activities totalled $1.4 billion year to date, an increase of approximately 10% over the same period in 2015. The increase was driven by higher cash earnings and favourable changes in working capital.
– The Corporation’s capital expenditure plan is on track and capital investments reached almost $1.4 billion year to date. Consolidated capital expenditures for 2016 are now expected to total $2.1 billion, up from the original forecast of $1.9 billion. The increase is primarily due to expected capital investments at ITC from the date of acquisition. In the third quarter, UNS Energy purchased the remaining 50.5% interest in Springerville Unit 1 for US$85 million as part of a settlement agreement with the third-party owners.
“Performance in the third quarter continues to demonstrate the strength of our low-risk and diversified portfolio of utilities,” said Mr. Barry Perry, President and Chief Executive Officer of Fortis.
A transformative acquisition
On October 14, 2016, Fortis and GIC Private Limited closed the acquisition of ITC in a transaction valued at approximately US$11.8 billion on closing, including approximately US$4.8 billion of ITC consolidated indebtedness at fair value. Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion. Details on the financing of the acquisition are included in the Corporation’s Interim Management Discussion and Analysis for the three and nine months ended September 30, 2016.
ITC is the largest independent electric transmission company in the United States. As a result of the acquisition, 2017 forecast midyear rate base of Fortis is expected to increase by almost $7.5 billion to approximately $26 billion.
“The ITC acquisition is the largest in the history of Fortis and dramatically increases our North American footprint,” explained Mr. Perry. “ITC further diversifies our business and positions us well for continued growth. We remain confident that this transaction will be accretive to earnings per common share in 2017.”
Execution of growth strategy
The Corporation’s five-year consolidated capital expenditures through 2021 are expected to be approximately $13 billion, including more than $3.5 billion in capital investments at ITC. The Corporation’s highly executable capital plan primarily consists of a large number of individually small capital projects.
Construction continues on the Tilbury liquefied natural gas (“LNG”) facility expansion (“Tilbury 1A”) in British Columbia, the Corporation’s largest ongoing capital project, at an estimated cost of $440 million. Approximately $388 million has been invested in Tilbury 1A to the end of the third quarter of 2016 and the facility is expected to be in service in mid-2017. The Corporation will continue to invest in four Multi Value Projects (“MVPs”) at ITC. Three of the MVPs are expected to be completed by the end of 2018, with the fourth scheduled for completion in 2023.
In addition to the Corporation’s base consolidated capital expenditure forecast, management is pursuing additional investment opportunities within existing service territories, including ITC. Specifically, the Corporation continues to pursue LNG infrastructure investment opportunities in British Columbia, including FortisBC Energy’s potential pipeline expansion to the Woodfibre LNG export facility. The potential pipeline expansion has an estimated total project cost of up to $600 million. A final investment decision by Woodfibre LNG is targeted for late 2016.
Regulatory proceedings
In the third quarter, the Corporation’s regulated utilities made significant progress on a number of key regulatory proceedings.
In August, Tucson Electric Power Company (“TEP”) entered into a partial settlement agreement regarding its general rate application requesting new retail rates to be effective January 1, 2017, using the year ended June 30, 2015 as a historical test year. The settlement agreement includes an increase in non-fuel base revenue of US$81.5 million, an allowed rate of return on common shareholder’s equity (“ROE”) of 9.75%, and a common equity component of capital structure of approximately 50%. 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%. Certain aspects of the general rate application, including net metering and rate design for distributed generation customers, have been deferred to a second rate case proceeding, which is expected to begin in the first quarter of 2017. The settlement agreement is subject to regulatory approval, which is expected by the end of 2016.
GCOC Proceedings in British Columbia and Alberta also concluded in recent months. In British Columbia, the outcome resulted in FortisBC Energy maintaining its allowed ROE at 8.75% and common equity component of capital structure at 38.5%. In Alberta, the GCOC Proceeding resulted in FortisAlberta maintaining its allowed ROE at 8.30% for 2016, with a decrease in the common equity component of capital structure from 40% to 37% effective January 1, 2016. The allowed ROE for 2017 has been approved at 8.50%. Changes in FortisAlberta’s allowed ROE and common equity component of capital structure impact only the portion of rate base that is funded by capital tracker revenue.
These regulatory outcomes provide stability for the Corporation’s utilities in the near term. Fortis continues to be actively engaged with all of its existing regulators and is focused on maintaining constructive regulatory relationships and outcomes across its utilities.
Outlook
The Corporation’s business continues to grow in 2016 and results for 2017 will benefit from the impact of ITC, the expected outcome of the TEP general rate case and continued growth of the underlying business. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital plan, the balance and strength of its diversified portfolio of businesses, as well as growth opportunities within its franchise regions.
Over the five-year period through 2021, including ITC, the Corporation’s capital program is expected to be approximately $13 billion. This investment in energy infrastructure is expected to increase rate base to almost $30 billion in 2021. Fortis expects long-term sustainable growth in rate base, resulting from investment in its existing utility operations and strategic utility acquisitions, to support continuing growth in earnings and dividends.
Fortis extended its targeted average annual dividend growth of approximately 6% through 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation’s utilities, the successful execution of the five-year capital expenditure program, and management’s continued confidence in the strength of the Corporation’s diversified portfolio of utilities and record of operational excellence.
“In September we raised our quarterly common share dividend by almost 7%, marking 43 consecutive years of common share dividend payment increases,” said Perry. “This is the longest record of any public company in Canada and is one that we will strive to maintain,” he concluded.
| Teleconference to Discuss Third Quarter 2016 Results |
| A teleconference and webcast will be held on November 4 at 8:00 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 third 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, http://www.fortisinc.com/. |
| A replay of the conference will be available two hours after the conclusion of the call until December 4, 2016. Please call 1.800.585.8367 or 416.621.4642 and enter pass code 96004380. |
| Interim Management Discussion and Analysis |
| For the three and nine months ended September 30, 2016 |
| Dated November 4, 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 and nine months ended September 30, 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 this MD&A has been prepared in accordance with accounting principles generally accepted in the United States (“US GAAP”) and is presented in Canadian dollars unless otherwise specified.
Fortis includes forward-looking information in the MD&A within the meaning of applicable securities laws including the Private Securities Litigation Reform Act of 1995. Forward-looking statements included in this MD&A reflect expectations of Fortis management regarding future growth, results of operations, performance and business prospects and opportunities as of November 4, 2016. Wherever possible, words such as “anticipates”, “believes”, “budgets”, “could”, “estimates”, “expects”, “forecasts”, “intends”, “may”, “might”, “plans”, “projects”, “schedule”, “should”, “target”, “will”, “would” and the negative of these terms and other similar terminology or expressions have been used to identify the forward-looking statements, which include, without limitation: the expectation that the acquisition of ITC Holdings Corp. (“ITC”) will be accretive to earnings per common share in the first full year following closing, excluding one-time acquisition-related expenses; the expectation that the Corporation will recognize additional acquisition-related expenses in the fourth quarter of 2016; targeted annual dividend growth through 2021; the expected timing of filing of regulatory applications and receipt and outcome of regulatory decisions; the Corporation’s forecast midyear rate base for 2017 and the expectation that midyear rate base will increase from 2016 to 2021; the Corporation’s forecast gross consolidated capital expenditures for 2016 and total capital spending through 2021;
forecast gross consolidated capital expenditures for 2016 for certain of the Corporation’s subsidiaries, including ITC, FortisAlberta and UNS Energy; the nature, timing and expected costs of certain capital projects including, without limitation, expansions of the Tilbury liquefied natural gas (“LNG”) facility, including Tilbury 1A, the pipeline expansion to the Woodfibre LNG site, and additional opportunities including electric transmission, LNG and renewable-related infrastructure and generation; the expectation that the Corporation’s significant capital expenditure program will support continuing growth in earnings and dividends; the expectation that the acquisition of ITC will increase total capitalization, but will not have a significant impact on the percentage breakdown of the Corporation’s capital structure; 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 maintaining the targeted capital structure of the Corporation’s regulated operating subsidiaries will not have an impact on its ability to pay dividends in the foreseeable future; the expectation that the Corporation’s subsidiaries will be able to source the cash required to fund their 2016 capital expenditure programs; the expected consolidated fixed-term debt maturities and repayments over the next five years, including ITC; 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 throughout 2016; the intent of management to hedge future exchange rate fluctuations and monitor its foreign currency exposure; the expectation that FortisAlberta will recognize capital tracker revenue in 2016; Tucson Electric Power Company’s expected share of mine reclamation costs; Central Hudson’s estimated total remediation costs for manufactured gas plant sites; the estimated range of return on common shareholder’s equity refunds and associated regulatory liabilities at ITC; 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.
Certain material factors or assumptions have been applied in drawing the conclusions contained in the forward-looking statements, including, without limitation: the receipt of applicable regulatory approvals and requested rate orders, no material adverse regulatory decisions being received, and the expectation of regulatory stability; no material capital project and financing cost overrun related to any of the Corporation’s capital projects; the realization of additional opportunities including natural gas related infrastructure and generation; the Board of Directors exercising its discretion to declare dividends, taking into account the business performance and financial conditions of the Corporation; no significant variability in interest rates; no significant operational disruptions or environmental liability due to a catastrophic event or environmental upset caused by severe weather, other acts of nature or other major events; the continued ability to maintain the electricity and gas systems to ensure their continued performance; no severe and prolonged downturn in economic conditions; no significant decline in capital spending; sufficient liquidity and capital resources; the continuation of regulator-approved mechanisms to flow through the cost of natural gas and energy supply costs in customer rates; the ability to hedge exposures to fluctuations in foreign exchange rates, natural gas prices and electricity prices; no significant 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 and its subsidiaries; no material change in public policies and directions by governments that could materially negatively affect the Corporation and its subsidiaries; maintenance of adequate insurance coverage; the ability to obtain and maintain licences and permits; retention of existing service areas; the continued tax-deferred treatment of earnings from the Corporation’s Caribbean operations; continued maintenance of information technology infrastructure; continued favourable relations with First Nations; favourable labour relations; that the Corporation can reasonably assess the merit of and potential liability attributable to ongoing legal proceedings; and sufficient human resources to deliver service and execute the capital program.
Forward-looking statements involve significant risks, uncertainties and assumptions. Fortis cautions readers that a number of factors could cause actual results, performance or achievements to differ materially from the results discussed or implied in the forward-looking statements. These factors should be considered carefully and undue reliance should not be placed on the forward-looking statements. Risk factors which could cause results or events to differ from current expectations are detailed under the heading “Business Risk Management” in this MD&A and in continuous disclosure materials filed from time to time with Canadian securities regulatory authorities and the Securities and Exchange Commission. Key risk factors for 2016 include, but are not limited to: 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, Fortis disclaims any intention or obligation to update or revise any forward-looking statements, whether as a result of new information, future events or otherwise.
CORPORATE OVERVIEW
Fortis is a leader in the North American regulated electric and gas utility business, with total assets of approximately $47 billion, on a pro forma basis as at September 30, 2016 including the acquisition of ITC Holdings Corp. (“ITC”). The Corporation’s 8,000 employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.
Year-to-date September 30, 2016, the Corporation’s electricity distribution systems met a combined peak demand of 9,590 megawatts (“MW”) and its gas distribution system met a peak day demand of 1,335 terajoules. In addition, ITC’s electricity transmission system serves a combined peak load exceeding 26,000 MW. 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 and nine months ended September 30, 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
Acquisition of ITC: On October 14, 2016, Fortis and GIC Private Limited (“GIC”) acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion on closing, including approximately US$4.8 billion of ITC consolidated indebtedness at fair value. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC.
Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion. The net cash consideration totalled approximately US$3.4 billion and was financed using: (i) net proceeds from the issuance of US$2.0 billion unsecured notes on October 4, 2016; (ii) net proceeds from GIC’s US$1.228 billion minority investment; and (iii) drawings of approximately US$404 million ($535 million) under the Corporation’s non-revolving term senior unsecured equity bridge credit facility. On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately US$3.6 billion, based on the closing price for Fortis common shares of $40.96 and the closing foreign exchange rate of 1.32 on October 13, 2016. The financing of the acquisition has been structured to allow Fortis to maintain investment-grade credit ratings.
ITC is the largest independent electric transmission company in the United States. Based in Novi, Michigan, ITC invests in the electrical transmission grid to improve reliability, expand access to markets, allow new generating resources to interconnect to its transmission systems and lower the overall cost of delivered energy. Through its regulated operating subsidiaries ITCTransmission, Michigan Electric Transmission Company, ITC Midwest and ITC Great Plains, 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 Midwest maintains utility status in Wisconsin.
ITC’s tariff rates are regulated by the United States Federal Energy Regulatory Commission (“FERC”). As at September 30, 2016, the weighted average allowed ROEs for ITC’s regulated operating subsidiaries are more than 11.00% on a 60% common equity component of capital structure. Rates are set using a forward-looking rate-setting mechanism with an annual true-up, which provides timely cost recovery and reduces regulatory lag. Dating back to 2013, two third-party complaints were filed with FERC requesting that FERC find the Midcontinent Independent System Operator (“MISO”) regional base ROE rate for all MISO transmission organizations, including ITCTransmission, Michigan Electric Transmission Company and ITC Midwest, for the periods November 2013 through February 2015 (the “Initial Refund Period”) and February 2015 through May 2016 (the “Second Refund Period”) to no longer be just and reasonable. In September 2016 FERC issued an order affirming the presiding Administrative Law Judge’s (“ALJ’s”) initial decision for the Initial Refund Period and setting the base ROE at 10.32%, with a maximum ROE of 11.35%. Additionally, the rates established by the September 2016 order will be used prospectively from the date of the order until a new approved rate is established for the Second Refund Period. In June 2016 the presiding ALJ issued an initial decision for the Second Refund Period, which recommended a base ROE of 9.7%, with a maximum ROE of 10.68%, which is a non-binding recommendation to FERC. A decision from FERC for the Second Refund Period is expected in 2017. As at September 30, 2016, the estimated range of refunds for both periods is between US$219 million and US$256 million and ITC has recognized an aggregate estimated regulatory liability of US$256 million. It is possible that the outcome of these matters could differ materially from the estimated range of refunds.
Fortis and ITC shareholders approved the acquisition at shareholder meetings held in May and June 2016, respectively. All required regulatory, state and federal approvals associated with the acquisition, including, among others, those of FERC and the United States Federal Trade Commission/Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act, were received prior to closing.
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. ITC represents a singular opportunity for Fortis to significantly diversify its business in terms of regulatory jurisdictions, business risk profile and regional economic mix. As a result of the acquisition, 2017 forecast midyear rate base of Fortis is expected to increase by almost $7.5 billion to approximately $26 billion.
In connection with the acquisition, on May 17, 2016, Fortis became a U.S. Securities and Exchange Commission registrant and, on October 14, 2016, commenced trading its common shares on the New York Stock Exchange. Fortis continues to list its shares on the Toronto Stock Exchange.
Acquisition-related expenses totalling $25 million ($19 million after tax) and $74 million ($58 million after tax) were recognized in earnings for the third quarter and year-to-date 2016, respectively. Acquisition-related expenses included: (i) investment banking, legal, consulting and other fees totalling approximately $4 million ($3 million after tax) and $39 million ($32 million after tax) for the third quarter and year-to-date 2016, respectively, which were included in operating expenses; and (ii) fees associated with the Corporation’s acquisition credit facilities and deal-contingent interest rate swap contracts totalling approximately $21 million ($16 million after tax) and $35 million ($26 million after tax) for third quarter and year-to-date 2016, respectively, which were included in finance charges. The Corporation expects to recognize additional acquisition-related expenses in the fourth quarter of 2016.
Acquisition of Aitken Creek Gas Storage Facility
On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC (“ACGS”) from Chevron Canada Properties Ltd. for approximately $349 million (US$266 million), plus working gas inventory. The net cash purchase price was primarily financed through US dollar-denominated borrowings under the Corporation’s committed revolving credit facility.
ACGS owns 93.8% of the Aitken Creek gas storage site (“Aitken Creek”), with the remaining share owned by BP Canada Energy Company. Aitken Creek is the only underground natural gas storage facility in British Columbia and has a total working gas capacity of 77 billion cubic feet. The facility is an integral part of western Canada’s natural gas transmission network. ACGS also owns 100% of the North Aitken Creek gas storage site which offers future expansion potential. The financial results of ACGS have been included in the Corporation’s consolidated results from the date of acquisition and are included in the Non-Regulated – Energy Infrastructure reporting segment.
FINANCIAL HIGHLIGHTS
Fortis has adopted a strategy of long-term profitable growth with the primary measures of financial performance being earnings per common share and total shareholder return. The Corporation’s business is segmented by franchise area and, depending on regulatory requirements, by the nature of the assets. Key financial highlights for the third quarter and year-to-date periods ended September 30, 2016 and 2015 are provided in the following table.
| Consolidated Financial Highlights (Unaudited) | |||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | |||||||
| ($ millions, except for common share data) | 2016 | 2015 | Variance | 2016 | 2015 | Variance | |||
| Revenue | 1,510 | 1,566 | (56 | ) | 4,744 | 5,019 | (275 | ) | |
| Energy Supply Costs | 485 | 533 | (48 | ) | 1,657 | 1,897 | (240 | ) | |
| Operating Expenses | 439 | 461 | (22 | ) | 1,367 | 1,392 | (25 | ) | |
| Depreciation and Amortization | 234 | 217 | 17 | 700 | 652 | 48 | |||
| Other Income (Expenses), Net | 10 | 5 | 5 | 35 | 188 | (153 | ) | ||
| Finance Charges | 164 | 141 | 23 | 457 | 416 | 41 | |||
| Income Tax Expense | 40 | 40 | – | 110 | 173 | (63 | ) | ||
| Net Earnings | 158 | 179 | (21 | ) | 488 | 677 | (189 | ) | |
| Net Earnings Attributable to: | |||||||||
| Non-Controlling Interests | 9 | 9 | – | 33 | 26 | 7 | |||
| Preference Equity Shareholders | 22 | 19 | 3 | 59 | 58 | 1 | |||
| Common Equity Shareholders | 127 | 151 | (24 | ) | 396 | 593 | (197 | ) | |
| Net Earnings | 158 | 179 | (21 | ) | 488 | 677 | (189 | ) | |
| Earnings per Common Share | |||||||||
| Basic ($) | 0.45 | 0.54 | (0.09 | ) | 1.40 | 2.13 | (0.73 | ) | |
| Diluted ($) | 0.45 | 0.54 | (0.09 | ) | 1.39 | 2.11 | (0.72 | ) | |
| Weighted Average Number of Common Shares Outstanding (# millions) | 285.0 | 279.1 | 5.9 | 283.7 | 277.9 | 5.8 | |||
| Cash Flow from Operating Activities | 478 | 358 | 120 | 1,409 | 1,276 | 133 | |||
Revenue
The decrease in revenue for the quarter and year to date was mainly due to a decrease in non-utility revenue due to the sale of commercial real estate and hotel assets in 2015 and the flow through in customer rates of lower overall energy supply costs, partially offset by contribution from Aitken Creek, which was acquired in April 2016. The decrease year to date was partially offset by the impact of favourable foreign exchange associated with the translation of US dollar-denominated revenue.
Energy Supply Costs
The decrease in energy supply costs for the quarter and year to date was mainly due to lower overall commodity costs, partially offset by energy supply costs at Aitken Creek. The decrease year to date was partially offset by the impact of unfavourable foreign exchange associated with the translation of US dollar-denominated energy supply costs.
Operating Expenses
The decrease in operating expenses for the quarter and year to date 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 acquisition-related expenses associated with ITC, operating expenses at Aitken Creek, and general inflationary and employee-related cost increases. The year-to-date decrease was also partially offset by the impact of unfavourable foreign exchange associated with the translation of US dollar-denominated operating expenses.
Depreciation and Amortization
The increase in depreciation for the quarter and year to date was primarily due to continued investment in energy infrastructure at the Corporation’s regulated utilities and depreciation at Aitken Creek. The impact of unfavourable foreign exchange associated with the translation of US dollar-denominated depreciation also contributed to the year-to-date increase. The year-to-date 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, year to date was primarily due to a net gain of approximately $109 million ($101 million after tax), net of expenses, related to the sale of commercial real estate and hotel assets in 2015 and a gain of approximately $56 million ($32 million after tax), net of expenses and foreign exchange impacts, on the sale of generation assets in 2015.
Finance Charges
The increase in finance charges for the quarter and year to date was primarily due to acquisition-related fees associated with the Corporation’s acquisition credit facilities and deal-contingent interest rate swap contracts. The impact of unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense also contributed to the year-to-date increase.
Income Tax Expense
The decrease in income tax expense year to date was primarily due to lower earnings before income taxes, mainly due to the net gains on the sale of commercial real estate and hotel assets and generation assets in 2015.
Net Earnings Attributable to Common Equity Shareholders and Basic Earnings Per Common Share
Fortis supplements the use of US GAAP financial measures with non-US GAAP financial measures, including adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share. The Corporation refers to these measures as non-US GAAP financial measures since they are not required by, or presented in accordance with, US GAAP.
The Corporation defines: (i) adjusted net earnings attributable to common equity shareholders as net earnings attributable to common equity shareholders plus or minus items that management believes help investors better evaluate results of operations; and (ii) adjusted basic earnings per common share as adjusted net earnings attributable to common equity shareholders divided by the weighted average number of common shares outstanding. The most directly comparable US GAAP measures to adjusted net earnings attributable to common equity shareholders and adjusted basic earnings per common share are net earnings attributable to common equity shareholders and basic earnings per common share.
The following table provides a reconciliation of the non-US GAAP financial measures and each of the adjusting items are discussed in the segmented results of operations for the respective reporting segments. The adjusting items do not have a standardized meaning as prescribed under US GAAP and are not considered US GAAP measures. Therefore, these adjusting items may not be comparable with similar measures presented by other companies.
| Non-US GAAP Reconciliation (Unaudited) | |||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | |||||||||
| ($ millions, except for common share data) | 2016 | 2015 | Variance | 2016 | 2015 | Variance | |||||
| Net Earnings Attributable to Common Equity Shareholders | 127 | 151 | (24 | ) | 396 | 593 | (197 | ) | |||
| Adjusting Items: | |||||||||||
| UNS Energy -FERC ordered transmission refunds | 7 | – | 7 | 18 | – | 18 | |||||
| FortisAlberta – | |||||||||||
| Capital tracker revenue adjustment for 2013 and 2014 | – | – | – | – | (9 | ) | 9 | ||||
| Non-Regulated – Energy Infrastructure – | |||||||||||
| Gain on sale of generation assets | – | (5 | ) | 5 | – | (32 | ) | 32 | |||
| Unrealized loss on mark-to-market of derivatives | 1 | – | 1 | 3 | – | 3 | |||||
| Non-Utility – | |||||||||||
| Net gain on sale of commercial real estate and hotel assets | – | (5 | ) | 5 | – | (101 | ) | 101 | |||
| Corporate and Other – | |||||||||||
| Acquisition-related expenses and fees | 19 | – | 19 | 58 | – | 58 | |||||
| Loss on settlement of expropriation matters | – | 9 | (9 | ) | – | 9 | (9 | ) | |||
| Foreign exchange gain | – | (5 | ) | 5 | – | (13 | ) | 13 | |||
| Adjusted Net Earnings Attributable to Common Equity Shareholders | 154 | 145 | 9 | 475 | 447 | 28 | |||||
| Adjusted Basic Earnings Per Common Share ($) | 0.54 | 0.52 | 0.02 | 1.67 | 1.61 | 0.06 | |||||
| Weighted Average Number of Common Shares Outstanding (# millions) | 285.0 | 279.1 | 5.9 | 283.7 | 277.9 | 5.8 | |||||
The increase in adjusted net earnings attributable to common equity shareholders for the quarter was mainly due to: (i) strong performance at most of the Corporation’s regulated utilities driven by UNS Energy, largely due to the settlement of Springerville Unit 1 matters, and Central Hudson, due to an increase in delivery revenue; (ii) the timing of quarterly earnings at FortisBC Electric compared to the third quarter of 2015; and (iii) contribution of $2 million from Aitken Creek, which was acquired in early April 2016. The increase was partially offset by: (i) lower earnings at FortisAlberta due to higher operating expenses, a negative capital tracker revenue adjustment as a result of the outcome of the 2016 Generic Cost of Capital (“GCOC”) Proceeding in Alberta, and lower average energy consumption; (ii) the sale of hotel assets in 2015; and (iii) an increase in Corporate and Other expenses.
The increase in adjusted net earnings attributable to common equity shareholders year to date was mainly due to: (i) strong performance at most of the Corporation’s regulated utilities, driven by the same factors discussed above for the quarter, a higher allowance for funds used during construction (“AFUDC”) at FortisBC Energy Inc. (“FEI”), equity income of $3 million from Belize Electricity and electricity sales growth at Caribbean Utilities; (ii) favourable foreign exchange associated with US dollar-denominated earnings; and (iii) contribution of $6 million from Aitken Creek and higher earnings at the Waneta Expansion, which commenced production in early April 2015. The increase was partially offset by: (i) the sale of commercial real estate and hotel assets in 2015; (ii) lower earnings at FortisAlberta due to higher operating expenses, a negative capital tracker revenue adjustment, as discussed above, and lower average energy consumption; (iii) the timing of quarterly earnings at FortisBC Electric compared to the same period in 2015; and (iv) higher Corporate and Other expenses.
Adjusted earnings per common share for the quarter and year to date were $0.02 and $0.06 higher, respectively, compared to the same periods in 2015. The impact of the above-noted items on adjusted net earnings attributable to common equity shareholders were partially offset by an increase in the weighted average number of common shares outstanding.
SEGMENTED RESULTS OF OPERATIONS
| Segmented Net Earnings Attributable to Common Equity Shareholders (Unaudited) | |||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | |||||||||||
| ($ millions) | 2016 | 2015 | Variance | 2016 | 2015 | Variance | |||||||
| Regulated Gas & Electric Utilities- United States | |||||||||||||
| UNS Energy | 102 | 97 | 5 | 170 | 169 | 1 | |||||||
| Central Hudson | 14 | 11 | 3 | 50 | 43 | 7 | |||||||
| 116 | 108 | 8 | 220 | 212 | 8 | ||||||||
| Regulated Gas Utility – Canadian | |||||||||||||
| FortisBC Energy | (19 | ) | (20 | ) | 1 | 81 | 75 | 6 | |||||
| Regulated Electric Utilities – Canadian | |||||||||||||
| FortisAlberta | 30 | 37 | (7 | ) | 91 | 109 | (18 | ) | |||||
| FortisBC Electric | 11 | 8 | 3 | 41 | 42 | (1 | ) | ||||||
| Eastern Canadian | 14 | 13 | 1 | 48 | 47 | 1 | |||||||
| 55 | 58 | (3 | ) | 180 | 198 | (18 | ) | ||||||
| Regulated Electric Utilities – Caribbean | 13 | 11 | 2 | 34 | 25 | 9 | |||||||
| Non-Regulated – Energy Infrastructure | 15 | 18 | (3 | ) | 45 | 66 | (21 | ) | |||||
| Non-Regulated – Non-Utility | – | 11 | (11 | ) | – | 113 | (113 | ) | |||||
| Corporate and Other | (53 | ) | (35 | ) | (18 | ) | (164 | ) | (96 | ) | (68 | ) | |
| Net Earnings Attributable to Common Equity Shareholders | 127 | 151 | (24 | ) | 396 | 593 | (197 | ) | |||||
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 further discussion pertaining to the Corporation’s regulated utilities.
REGULATED ELECTRIC & GAS UTILITIES – UNITED STATES
UNS ENERGY (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||
| Periods Ended September 30 | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||
| Average US:CAD Exchange Rate (2) | 1.31 | 1.31 | – | 1.32 | 1.26 | 0.06 | ||
| Electricity Sales (gigawatt hours (“GWh”)) | 4,379 | 4,426 | (47 | ) | 11,031 | 11,804 | (773 | ) |
| Gas Volumes (petajoules (“PJ”)) | 1 | 2 | (1 | ) | 9 | 9 | – | |
| Revenue ($ millions) | 604 | 623 | (19 | ) | 1,534 | 1,552 | (18 | ) |
| Earnings ($ millions) | 102 | 97 | 5 | 170 | 169 | 1 | ||
| (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 for the quarter was primarily due to lower mining retail sales and year to date was primarily due to lower short-term wholesale and mining retail sales, all as a result of less favourable commodity prices compared to the same periods in 2015. The majority of short-term wholesale sales is flowed through to customers and has no impact on earnings. The decrease in electricity sales year to date was partially offset by higher residential retail electricity sales, mainly due to warmer temperatures in the second quarter of 2016, which increased air conditioning load, and cooler temperatures in the first quarter of 2016, which increased electric heating load.
Gas volumes for the quarter and year to date were comparable with the same periods in 2015.
Revenue
The decrease in revenue for the quarter was mainly due to the flow through to customers of lower purchased power and fuel supply costs, and $11 million (US$9 million), or $7 million (US$5 million) after tax, in FERC ordered transmission refunds associated with late-filed transmission service agreements. The decrease was partially offset by $17 million (US$13 million), or $10 million (US$8 million) after tax, in revenue related to the settlement of Springerville Unit 1. For details on the FERC order, refer to the “Material Regulatory Decisions and Applications” section of this MD&A. For details on the settlement of Springerville Unit 1, refer to the “Critical Accounting Estimates” section of this MD&A.
The decrease in revenue year to date was mainly due to the flow through to customers of lower purchased power and fuel supply costs, lower short-term wholesale electricity sales, and $29 million (US$22 million), or $18 million (US$13 million) after tax, in FERC ordered transmission refunds. The decrease was partially offset by approximately $51 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue, revenue related to the settlement of Springerville Unit 1, an increase in lost fixed-cost recovery revenue and higher residential retail electricity sales.
Earnings
The increase in earnings for the quarter was primarily due to $10 million (US$8 million) related to the settlement of Springerville Unit 1, lower deferred income tax expense, and higher gains on investments. The increase was partially offset by $7 million (US$5 million) in FERC ordered transmission refunds in the third quarter of 2016 and higher depreciation and amortization.
The increase in earnings year to date was primarily due to the settlement of Springerville Unit 1, approximately $5 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, lower deferred income tax expense, an increase in lost fixed-cost recovery revenue and higher residential retail electricity sales. The increase was partially offset by $18 million (US$13 million) in FERC ordered transmission refunds and higher operating expenses and depreciation and amortization.
CENTRAL HUDSON
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | |||||
| Periods Ended September 30 | 2016 | 2015 | Variance | 2016 | 2015 | Variance | |
| Average US:CAD Exchange Rate (1) | 1.31 | 1.31 | – | 1.32 | 1.26 | 0.06 | |
| Electricity Sales (GWh) | 1,513 | 1,340 | 173 | 3,917 | 3,972 | (55 | ) |
| Gas Volumes (PJ) | 5 | 4 | 1 | 18 | 19 | (1 | ) |
| Revenue ($ millions) | 208 | 193 | 15 | 642 | 678 | (36 | ) |
| Earnings ($ millions) | 14 | 11 | 3 | 50 | 43 | 7 | |
| (1) | The reporting currency of Central Hudson is the US dollar. |
Electricity Sales & Gas Volumes
Electricity sales and gas volumes for the quarter and year to date were favorably impacted by the timing of customer billings, as a result of regulatory approval to increase billing frequency to monthly effective July 1, 2016. The increase in electricity sales for the quarter was also due to higher average consumption as a result of warmer temperatures, which increased air conditioning load. The decrease in electricity sales and gas volumes year to date was due to lower average consumption in the first quarter of 2016 as a result of warmer temperatures, which reduced heating load.
Changes in electricity sales and gas volumes at Central Hudson are subject to regulatory revenue decoupling mechanisms and, as a result, do not have a material impact on revenue and earnings.
Revenue
The increase in revenue for the quarter was primarily due to the recovery from customers of higher commodity costs and higher delivery revenue from an increase in base electricity rates effective July 1, 2016.
The decrease in revenue year to date was mainly due to the recovery from customers of lower commodity costs, which were mainly due to overall lower wholesale prices, and the impact of energy-efficiency incentives earned during the first half 2015 upon achieving energy saving targets established by the regulator. The decrease was partially offset by approximately $19 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue and higher delivery revenue from increases in base electricity rates effective July 1, 2016 and 2015.
Earnings
The increase in earnings for the quarter and year to date was primarily due to increases in delivery revenue. The increase year to date was also due to approximately $4 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings, partially offset by the impact of energy-efficiency incentives earned during the first half of 2015, as discussed above.
REGULATED GAS UTILITY – CANADIAN
FORTISBC ENERGY
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||||
| Periods Ended September 30 | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||||
| Gas Volumes (PJ) | 28 | 26 | 2 | 130 | 124 | 6 | ||||
| Revenue ($ millions) | 151 | 168 | (17 | ) | 758 | 884 | (126 | ) | ||
| (Loss) Earnings ($ millions) | (19 | ) | (20 | ) | 1 | 81 | 75 | 6 | ||
Gas Volumes
The increase in gas volumes for the quarter and year to date was primarily due to higher volumes for transportation customers, due to certain transportation customers switching to natural gas compared to alternative fuel sources. Also contributing to the year to date increase was higher average consumption by residential and commercial customers during the first quarter of 2016 due to colder temperatures.
Revenue
The decrease in revenue for the quarter and year to date 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 an increase in customer delivery rates effective January 1, 2016 and higher gas volumes.
(Loss) Earnings
The lower loss for the quarter and increase in earnings year to date were primarily due to higher AFUDC, partially offset by the timing of regulatory flow-through deferral amounts compared to the same periods in 2015.
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 | Year-to-Date | ||||||
| Periods Ended September 30 | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||
| Energy Deliveries (GWh) | 4,081 | 4,251 | (170 | ) | 12,436 | 12,944 | (508 | ) |
| Revenue ($ millions) | 143 | 141 | 2 | 429 | 423 | 6 | ||
| Earnings ($ millions) | 30 | 37 | (7 | ) | 91 | 109 | (18 | ) |
Energy Deliveries
The decrease in energy deliveries for the quarter and year to date 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, commercial and irrigation customers, mainly due to cooler temperatures in the third quarter of 2016. The decrease was partially offset by higher energy deliveries to residential customers due to customer growth.
Revenue
The increase in revenue for the quarter was due to 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 residential customers and higher revenue related to flow-through costs to customers. The increase was partially offset by lower average consumption and a $2 million negative capital tracker revenue adjustment as a result of the outcome of the 2016 GCOC Proceeding in Alberta. For details on this regulatory decision, refer to the “Material Regulatory Decisions and Applications” section of this MD&A.
The increase in revenue year to date was due to the same factors discussed above for the quarter, partially offset by the impact of a $9 million positive capital tracker revenue adjustment recognized in the first half of 2015 that related to 2013 and 2014.
Earnings
The decrease in earnings for the quarter and year to date was due to higher operating expenses, the $2 million negative capital tracker revenue adjustment recognized in the third quarter of 2016, as discussed above, and lower average energy consumption, partially offset by rate base growth and growth in the number of customers. The decrease in earnings year to date was also due to the $9 million positive capital tracker revenue adjustment recognized in the first half of 2015, as discussed above.
FORTISBC ELECTRIC (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||
| Periods Ended September 30 | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||
| Electricity Sales (GWh) | 728 | 742 | (14 | ) | 2,263 | 2,280 | (17 | ) |
| Revenue ($ millions) | 88 | 85 | 3 | 275 | 261 | 14 | ||
| Earnings ($ millions) | 11 | 8 | 3 | 41 | 42 | (1 | ) | |
| (1) | Includes the regulated operations of FortisBC Inc. and operating, maintenance and management services related to the Waneta, Brilliant and Arrow Lakes hydroelectric generating plants. 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 decrease in electricity sales for the quarter and year to date was mainly due to lower average consumption as a result of changes in temperatures.
Revenue
The increase in revenue for the quarter and year to date was driven by increases in base electricity rates and surplus capacity sales, partially offset by a decrease in electricity sales. Revenue year to date was also favourably impacted by higher contribution from non-regulated operating, maintenance and management services associated with the Waneta Expansion.
Earnings
The increase in earnings for the quarter was primarily due to approximately $2 million associated with the timing of quarterly earnings compared to the same period in 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, which 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. Also contributing to the increase in earnings was lower operating and maintenance expenses and rate base growth.
The decrease in earnings year to date was primarily due to approximately $4 million associated with the timing of quarterly earnings compared to the same period in 2015, as discussed above for the quarter. The decrease was partially offset by higher earnings from non-regulated operating, maintenance and management services, lower operating and maintenance expenses, and rate base growth.
EASTERN CANADIAN ELECTRIC UTILITIES (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||
| Periods Ended September 30 | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||
| Electricity Sales (GWh) | 1,540 | 1,543 | (3 | ) | 6,167 | 6,214 | (47 | ) |
| Revenue ($ millions) | 211 | 206 | 5 | 785 | 760 | 25 | ||
| Earnings ($ millions) | 14 | 13 | 1 | 48 | 47 | 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
Electricity sales for the quarter were comparable to the same period last year. Lower average consumption by commercial customers in Newfoundland was largely offset by higher average consumption by residential customers in Ontario due to warmer temperatures.
The decrease in electricity sales year to date was primarily due to lower average consumption by residential customers in all regions, mainly due to warmer temperatures. The decrease was partially offset by customer growth in Newfoundland.
Revenue
The increase in revenue for the quarter and year to date was mainly due to the flow through in customer electricity rates of higher energy supply costs at Newfoundland Power and FortisOntario, partially offset by lower electricity sales.
Earnings
Earnings for the quarter and year to date were comparable with the same periods in 2015. The quarterly impact of the timing of earnings at Newfoundland Power was partially offset by a decrease in the allowed ROE effective January 1, 2016. The year to date impact of approximately $1 million in business development costs in Ontario in the second quarter of 2015 was partially offset by lower electricity sales.
REGULATED ELECTRIC UTILITIES – CARIBBEAN (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||
| Periods Ended September 30 | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||
| Average US:CAD Exchange Rate (2) | 1.31 | 1.31 | – | 1.32 | 1.26 | 0.06 | ||
| Electricity Sales (GWh) | 227 | 219 | 8 | 632 | 601 | 31 | ||
| Revenue ($ millions) | 79 | 87 | (8 | ) | 225 | 239 | (14 | ) |
| Earnings ($ millions) | 13 | 11 | 2 | 34 | 25 | 9 | ||
| (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 for the quarter and year to date was primarily due to growth in the number of customers as a result of increased economic activity. Overall warmer temperatures, which increased air conditioning load, also contributed to the year-to-date increase.
Revenue
The decrease in revenue for the quarter and year to date was mainly due to the flow through in customer electricity rates of lower fuel costs at Caribbean Utilities, partially offset by electricity sales growth. The translation of US dollar-denominated revenue had a $5 million favourable impact on revenue year to date.
Earnings
The increase in earnings for the quarter and year to date was primarily due to equity income from Belize Electricity and electricity sales growth. Favourable foreign exchange of approximately $3 million associated with the translation of US dollar-denominated earnings and higher capitalized interest at Caribbean Utilities also contributed to the year-to-date increase. The increase was partially offset by higher depreciation.
NON-REGULATED – ENERGY INFRASTRUCTURE (1)
| Financial Highlights (Unaudited) | Quarter | Year-to-Date | ||||||
| Periods Ended September 30 | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||
| Energy Sales (GWh) | 181 | 170 | 11 | 786 | 722 | 64 | ||
| Revenue ($ millions) | 44 | 29 | 15 | 139 | 77 | 62 | ||
| Earnings ($ millions) | 15 | 18 | (3 | ) | 45 | 66 | (21 | ) |
| (1) | Primarily comprised of long-term contracted generation assets in British Columbia and Belize, with a combined generating capacity of 391 MW, and the Aitken Creek natural gas storage facility in British Columbia, with a total working gas capacity of 77 billion cubic feet. Aitken Creek was acquired by Fortis on April 1, 2016 and the financial results are included in this segment from the date of acquisition. For further information, refer to the “Significant Items” section of this MD&A and Note 16 to the interim unaudited consolidated financial statements. In February 2016 the Corporation sold its 16-MW Walden hydroelectric generating facility. |
Energy Sales
The increase in energy sales for the quarter was primarily due to increased production in Belize due to higher rainfall, partially offset by lower energy sales due to the sale of generation assets in February 2016.
The increase in energy sales year to date was driven by the Waneta Expansion, which commenced production in April 2015, and increased production in Belize. The increase was partially offset by lower energy sales due to the sale of generation assets in 2015 and February 2016.
Revenue
The increase in revenue for the quarter was driven by the acquisition of Aitken Creek in April 2016, and increased production in Belize.
The increase in revenue year to date was driven by Aitken Creek and the Waneta Expansion, which commenced production in April 2015. The impacts of increased production in Belize and approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated revenue were partially offset by lower revenue due to the sale of generation assets.
Earnings
The decrease in earnings for the quarter was primarily due to the recognition of an after-tax gain of approximately $5 million on the sale of generation assets in the third quarter of 2015. The decrease was partially offset by contribution of $1 million from Aitken Creek, net of an after-tax $1 million unrealized loss on the mark-to-market of derivatives, and increased production in Belize.
The decrease in earnings year to date was primarily due to the recognition of after-tax gains of approximately $27 million and $5 million on the sale of generation assets in the second and third quarters of 2015, respectively, and lower earnings due to the sale of generation assets. The decrease was partially offset by the Waneta Expansion, which commenced production in April 2015, contribution of $3 million from Aitken Creek, net of an after-tax $3 million unrealized loss on the mark-to-market of derivatives, increased production in Belize, and approximately $1 million of favourable foreign exchange associated with the translation of US dollar-denominated earnings.
NON-REGULATED – NON-UTILITY (1)
| Financial Highlights (Unaudited) | ||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | ||||||
| ($ millions) | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||
| Revenue | – | 47 | (47 | ) | – | 165 | (165 | ) |
| Earnings | – | 11 | (11 | ) | – | 113 | (113 | ) |
| (1) | Comprised of Fortis Properties, which completed the sale of its commercial real estate and hotel assets in June 2015 and October 2015, respectively. |
Revenue
The decrease in revenue for the quarter and year to date was due to the sale of commercial real estate and hotel assets in 2015.
Earnings
The decrease in earnings for the quarter and year to date was due to the sale of commercial real estate and hotel assets in 2015. In the third quarter of 2015, a $5 million positive adjustment was recognized, largely related to a deferred income tax recovery associated with the sale of hotel assets. Year-to-date 2015, an after-tax net gain of approximately $101 million was recognized related to the sale of commercial real estate and hotel assets.
CORPORATE AND OTHER (1)
| Financial Highlights (Unaudited) | ||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | ||||||||||
| ($ millions) | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||||||
| Revenue | 2 | 8 | (6 | ) | 7 | 22 | (15 | ) | ||||
| Operating Expenses | 8 | 8 | – | 61 | 25 | 36 | ||||||
| Depreciation and Amortization | 1 | – | 1 | 3 | 1 | 2 | ||||||
| Other Income (Expenses), Net | 1 | (4 | ) | 5 | 5 | 4 | 1 | |||||
| Finance Charges | 47 | 25 | 22 | 109 | 70 | 39 | ||||||
| Income Tax Recovery | (22 | ) | (13 | ) | (9 | ) | (56 | ) | (32 | ) | (24 | ) |
| (31 | ) | (16 | ) | (15 | ) | (105 | ) | (38 | ) | (67 | ) | |
| Preference Share Dividends | 22 | 19 | 3 | 59 | 58 | 1 | ||||||
| Net Corporate and Other Expenses | (53 | ) | (35 | ) | (18 | ) | (164 | ) | (96 | ) | (68 | ) |
| (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:
- Acquisition-related expenses totalling $25 million ($19 million after tax) and $74 million ($58 million after tax) for the third quarter and year-to-date 2016, respectively, associated with ITC. Acquisition-related expenses included: (i) investment banking, legal, consulting and other fees totalling approximately $4 million ($3 million after tax) and $39 million ($32 million after tax) for the third quarter and year-to-date 2016, respectively, which were included in operating expenses; and (ii) fees associated with the Corporation’s acquisition credit facilities and deal-contingent interest rate swap contracts totalling approximately $21 million ($16 million after tax) and $35 million ($26 million after tax) for the third quarter and year-to-date 2016, respectively, which were included in finance charges;
- A foreign exchange gain of $5 million and $13 million for the third quarter and year-to-date 2015, respectively, 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; and
- A loss of $9 million recognized in the third quarter of 2015 on settlement of expropriation matters related to the Corporation’s investment in Belize Electricity.
Excluding the above-noted items, net Corporate and Other expenses were $34 million for the quarter compared to $31 million for the same period in 2015. A decrease in revenue due to lower related-party interest income, mainly due to the sale of commercial real estate and hotel assets in 2015, and higher preference share dividends, mainly due to approximately $3 million of costs associated with the redemption of First Preference Shares, Series E in September 2016, was largely offset by lower operating expenses and a higher income tax recovery. The decrease in operating expenses was mainly due to lower share-based compensation expenses and a decrease in legal fees, largely as a result of the settlement of expropriation matters in the third quarter of 2015.
Excluding the above-noted items, net Corporate and Other expenses were $106 million year to date compared to $100 million for the same period in 2015. The increase was primarily due to lower revenue, as discussed above for the quarter, and higher finance charges, due to the impact of no longer capitalizing interest upon the completion of the Waneta Expansion in April 2015 and the impact of unfavourable foreign exchange associated with the translation of US dollar-denominated interest expense, partially offset by lower interest on the Corporation’s credit facility. The increase was partially offset by other income associated with the release of provisions on the wind-up of a partnership in the first quarter of 2016, lower operating expenses, largely as a result of a corporate donation of $3 million ($2 million after tax) in the second quarter of 2015, and a higher income tax recovery.
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 year-to-date 2016.
UNS Energy
General Rate Applications
In November 2015 Tucson Electric Power Company (“TEP”), UNS Energy’s largest utility, filed a general rate application (“GRA”) with the Arizona Corporation Commission (“ACC”) 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 included: (i) a non-fuel base revenue 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 August 2016 TEP entered into a partial settlement agreement with several parties regarding TEP’s revenue requirement in its pending rate case. The terms of the settlement agreement include: (i) an increase in non-fuel base revenue of US$81.5 million, including US$15 million of operating costs related to the 50.5% undivided interest in Springerville Unit 1 purchased by TEP in September 2016; (ii) a 7.04% return on original cost rate base, including a cost of equity of 9.75% and an embedded cost of long-term debt of 4.32%; (iii) a common equity component of capital structure of approximately 50%; and (iv) the adoption of proposed depreciation rates which reflect a reduction in the depreciable life for San Juan Unit 1. Certain aspects of the GRA, including net metering and rate design for distributed generation customers, have been deferred to a second rate case proceeding, which is expected to begin in the first quarter of 2017. Hearings before an Administrative Law Judge (“ALJ”) were held in September 2016 with a Recommended Opinion and Order expected in the fourth quarter of 2016. That recommendation is then subject to review and approval by the ACC before new rates can become effective. TEP requested new rates to be implemented by January 1, 2017.
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. The nature of UNS Electric’s GRA was similar to that of TEP. In July 2016 the presiding ALJ issued a Recommended Opinion and Order that was subsequently approved by the ACC in August 2016. The approved order included a US$15 million non-fuel base revenue increase and an allowed ROE of 9.50% on a common equity component of capital structure of 52.8%. New rates were implemented in August 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 compliance filings, including the filing of several TEP transmission service agreements, the majority of which were entered into before the acquisition of UNS Energy by Fortis in 2014, that contained certain deviations from TEP’s standard form of service agreement. In April 2016 FERC issued an order relating to the late-filed transmission service agreements, which directed TEP to issue time value refunds to the counterparties of the agreements. TEP accrued $18 million (US$13 million), or $11 million (US$8 million) after tax, in the first quarter of 2016. As authorized in the order, TEP reviewed its refund calculations, including losses incurred as a result of the calculated refund, and determined the refund amount to be US$3 million. TEP filed a refund report, including the updated calculations, with FERC in July 2016.
In October 2016, in response to TEP’s filed refund report, FERC issued an additional order which: (i) rejected the filed refund report; (ii) directed TEP to recalculate and pay additional time value refunds within 30 days; and (iii) file a revised report with FERC within 30 days thereafter. TEP has the right to seek rehearing of this order within 30 days of issuance. As a result of this order and ongoing discussions with the Office of Enforcement, TEP accrued an additional $11 million (US$9 million), or $7 million (US$5 million) after tax, in the third quarter of 2016. TEP paid time value refunds of US$3 million year-to-date 2016 and an additional US$14 million in October 2016.
In June 2016, to preserve its rights, TEP petitioned the District of Columbia Circuit Court of Appeals to review the refund order. In July 2016 TEP filed an unopposed motion to hold the appeal, which the Court has since granted. As a result of the October order issued by FERC, TEP intends to pursue the appeal. In addition, FERC’s Office of Enforcement is reviewing the matter, and FERC could impose civil penalties on TEP as a result of this review. At this time, TEP cannot predict the outcome of these matters or the range of possible recoveries or additional losses, if any.
FortisBC Energy and FortisBC Electric
Generic Cost of Capital Proceeding
In October 2015, as required by the regulator, FEI filed its application to review the 2016 benchmark allowed ROE and common equity component of capital structure. In August 2016 the British Columbia Utilities Commission issued its decision, which reaffirmed FEI as the benchmark utility and established that the ROE and common equity component of capital structure for the benchmark utility would remain unchanged at 8.75% and 38.5%, respectively, both effective January 1, 2016. As FEI is the benchmark utility, FortisBC Electric’s allowed ROE also remains unchanged at 9.15%.
FortisAlberta
Capital Tracker Applications
In February 2016 the Alberta Utilities Commission (“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 filed a 2015 True-Up Application in June 2016, with a decision expected in the first quarter of 2017.
In April 2016 FortisAlberta filed its Compliance Filing related to the February 2016 capital tracker decision, which was approved by the AUC in September 2016, including approval of capital tracker revenue of $71 million and $90 million for 2016 and 2017, respectively. The adjustments to capital tracker revenue have been included in the 2017 Annual Rates Application, as discussed below. Any further differences between 2016 capital tracker revenue collected from customers and actual capital expenditures will be included in 2017 applications to be refunded to or collected from customers in 2018.
FortisAlberta expects to recognize capital tracker revenue of $60 million for 2016, down $11 million from the $71 million approved in the Compliance Filing, which reflects actual capital expenditures and associated financing costs compared to forecast, and the impact of the 2016 GCOC Decision, as discussed below.
2017 Annual Rates Application Proceeding
In September 2016 FortisAlberta filed its 2017 Annual Rates Application requesting new rates to be effective, on an interim basis, for January 1, 2017. The key provisions of the rate application include a decrease of approximately 2.4% to the distribution component of customer rates reflecting: (i) a combined inflation and productivity factor of negative 1.9%; (ii) a K factor placeholder of $90 million, which is 100% of the depreciation and return associated with the 2017 forecast capital tracker expenditures; (iii) a refund of $13 million representing the difference between the 2013 through 2016 K factor amounts applied for, or approved, and the amounts collected from customers, including associated carrying costs; (iv) a refund of less than $1 million of K factor carrying costs; and (v) a net collection of Y factor amounts of approximately $1 million. A decision on the 2017 Annual Rates Application is expected in the fourth quarter of 2016.
Generic Cost of Capital Proceeding
In October 2016 the AUC issued its decision related to FortisAlberta’s 2016 and 2017 GCOC Proceeding, establishing that FortisAlberta’s allowed ROE remain unchanged at 8.30% for 2016 and increase to 8.50% for 2017. The decision also set the common equity component of capital structure at 37%, effective January 1, 2016, down from 40% approved on an interim basis. Changes in FortisAlberta’s allowed ROE and common equity component of capital structure impact only the portion of rate base that is funded by capital tracker revenue.
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 Court of Appeal of Alberta’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 AUC to have been subject to an extraordinary retirement will not be recoverable from customers.
Next Generation PBR Proceeding
In May 2015 the AUC initiated a generic proceeding to establish parameters for the next term of PBR, being the five-year period from 2018 to 2022. The AUC is assessing three main issues: (i) rebasing and the going-in rates for the next PBR term; (ii) the productivity factor; and (iii) the ongoing treatment of capital. In March 2016 FortisAlberta, along with other Alberta utilities, submitted common expert evidence to the AUC on the design of the next PBR term. At that time, FortisAlberta also submitted Company specific evidence for the implementation of the next PBR term. A hearing was held in July 2016 with a decision expected by the end of 2016.
Eastern Canadian Electric Utilities
In June 2016 the Newfoundland and Labrador Board of Commissioners of Public Utilities issued an order on Newfoundland Power’s 2016/2017 GRA, with new customer rates effective July 1, 2016. The order, which established the cost of capital for rate-making purposes for 2016 through 2018, resulted in a decrease in the allowed ROE to 8.50% from 8.80%, effective January 1, 2016, on a 45% common equity component of capital structure. Newfoundland Power is required to file its next GRA for 2019 on or before June 1, 2018.
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/Proceeding | Filing Date | Expected Decision | |||
| TEP | GRA for 2017 | November 2015 | Fourth quarter of 2016 | |||
| Central Hudson | Reforming the Energy Vision | Not applicable | To be determined | |||
| FortisAlberta | Next Generation PBR Proceeding | Not applicable | Fourth quarter of 2016 | |||
| ITC | Second MISO Base ROE Complaint | Not applicable | 2017 |
CONSOLIDATED FINANCIAL POSITION
The following table outlines the significant changes in the consolidated balance sheets between September 30, 2016 and December 31, 2015.
| Significant Changes in the Consolidated Balance Sheets (Unaudited) between | ||
| September 30, 2016 and December 31, 2015 | ||
| Balance Sheet Account | Increase/ (Decrease) ($ millions) |
Explanation |
| Accounts receivable and other current assets | (127) | The decrease was primarily due to the impact of a seasonal decrease in sales at FortisBC Energy, Newfoundland Power and Central Hudson and the impact of foreign exchange on the translation of US dollar-denominated accounts receivable. |
| Utility capital assets | 610 | The increase was mainly due to utility capital expenditures and the acquisition of Aitken Creek, partially offset by the impact of foreign exchange on the translation of US dollar-denominated utility capital assets and depreciation. |
| Goodwill | (115) | The decrease was primarily due to the impact of foreign exchange on the translation of US dollar-denominated goodwill. |
| Long-term debt (including current portion) | 574 | The increase was primarily due to higher borrowings under the Corporation’s committed credit facility, primarily to finance the acquisition of Aitken Creek and redeem the First Preference Shares, Series E in September 2016, and the issuance of long-term debt mainly at FortisBC Energy and FortisAlberta. The increase was partially offset by the impact of foreign exchange on the translation of US dollar-denominated debt and regularly scheduled debt repayments. |
| Deferred income tax liabilities | 153 | The increase was mainly due to timing differences associated with the acquisition of Aitken Creek and capital expenditures at the regulated utilities, partially offset by the impact of foreign exchange on the translation of US dollar-denominated deferred income tax liabilities. |
| Shareholders’ equity (before non-controlling interests) | (212) | The decrease was primarily 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, and a decrease in preference shares due to the redemption of First Preference Shares, Series E in September 2016. The decrease was partially offset by net earnings attributable to common equity shareholders for the nine months ended September 30, 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 and nine months ended September 30, 2016, as compared to the same periods in 2015, followed by a discussion of the nature of the variances in cash flows.
| Summary of Consolidated Cash Flows (Unaudited) | ||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | ||||||||||
| ($ millions) | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||||||
| Cash, Beginning of Period | 296 | 797 | (501 | ) | 242 | 230 | 12 | |||||
| Cash Provided by (Used in): | ||||||||||||
| Operating Activities | 478 | 358 | 120 | 1,409 | 1,276 | 133 | ||||||
| Investing Activities | (529 | ) | (446 | ) | (83 | ) | (1,704 | ) | (1,134 | ) | (570 | ) |
| Financing Activities | 51 | (388 | ) | 439 | 365 | (66 | ) | 431 | ||||
| Effect of Exchange Rate Changes on Cash and Cash Equivalents | 5 | 24 | (19 | ) | (11 | ) | 41 | (52 | ) | |||
| Change in Cash Associated with Assets Held for Sale | – | 2 | (2 | ) | – | – | – | |||||
| Cash, End of Period | 301 | 347 | (46 | ) | 301 | 347 | (46 | ) | ||||
Operating Activities: Cash flow from operating activities was $120 million higher for the quarter and $133 million higher year to date compared to the same periods in 2015. The increase was mainly due to favourable changes in working capital and long-term regulatory deferrals for both periods and higher cash earnings year to date. The favourable changes in working capital were mainly associated with accounts receivable at UNS Energy and current regulatory deferrals at FortisAlberta, partially offset by unfavourable changes at FortisBC Energy due to timing differences.
Investing Activities: Cash used in investing activities was $83 million higher quarter over quarter. The increase was primarily due to higher capital spending at UNS Energy, due to the purchase of the third-party owners’ 50.5% undivided interest in the Springerville Unit 1 generating facility for US$85 million, partially offset by lower capital spending at FortisBC Energy, due to lower capital expenditures related to the Tilbury liquefied natural gas (“LNG”) facility expansion (“Tilbury 1A”), and Caribbean Utilities, due to the completion of its generation expansion project in the second quarter of 2016. The increase also reflects proceeds of US$35 million received in the third quarter of 2015 on the settlement of expropriation matters related to the Corporation’s investment in Belize Electricity.
Cash used in investing activities was $570 million higher year to date compared to the same period in 2015. The increase was primarily due to proceeds received from the sale of commercial real estate and generation assets in the second quarter of 2015 of approximately $430 million and $77 million (US$63 million), respectively, and the acquisition of Aitken Creek in the second quarter of 2016 for a net purchase price of $318 million. The increase was partially offset by 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 additional ownership interests in the Springerville Unit 1 generating facility and previously leased coal-handling assets in the first and second quarters of 2015, respectively, partially offset by the purchase of the third-party owners’ 50.5% undivided interest in Springerville Unit 1 in the third quarter of 2016, as discussed above. Lower capital spending at FortisBC Energy was related to Tilbury 1A, as discussed above. 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 $439 million higher for the quarter and $431 million higher year to date compared to the same periods in 2015. The changes were primarily due to higher net borrowings under committed credit facilities and lower repayments of long-term debt, partially offset by lower proceeds from the issuance of long-term debt and the redemption of preference shares in September 2016.
Proceeds from long-term debt, net of issue costs, repayments of long-term debt and capital lease and finance obligations, and net (repayments) borrowings under committed credit facilities for the quarter and year to date compared to the same periods in 2015 are summarized in the following tables.
| Proceeds from Long-Term Debt, Net of Issue Costs (Unaudited) | ||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | ||||||||
| ($ millions) | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||||
| UNS Energy (1) | – | 163 | (163 | ) | – | 594 | (594 | ) | ||
| Central Hudson (2) | – | – | – | 29 | 25 | 4 | ||||
| FortisBC Energy (3) | – | – | – | 298 | 150 | 148 | ||||
| FortisAlberta (4) | 149 | 149 | – | 149 | 149 | – | ||||
| Newfoundland Power (5) | – | 75 | (75 | ) | – | 75 | (75 | ) | ||
| Maritime Electric (6) | 40 | – | 40 | 40 | – | 40 | ||||
| Fortis Turks and Caicos (7) | 36 | – | 36 | 65 | 12 | 53 | ||||
| Corporate | (2 | ) | – | (2 | ) | (2 | ) | – | (2 | ) |
| Total | 223 | 387 | (164 | ) | 579 | 1,005 | (426 | ) | ||
| (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. In April 2015 UNS Electric issued 30-year US$50 million 3.95% unsecured notes. The net proceeds were primarily used for general corporate purposes. In August 2015 UNS Electric issued 12-year US$80 million 3.22% unsecured notes and UNS Gas issued 30-year US$45 million 4.00% unsecured notes. The net proceeds were used to repay maturing long-term debt. |
| (2) | In June 2016 Central Hudson issued 4-year US$24 million 2.16% unsecured notes. The net proceeds were used to finance capital expenditures and for general corporate purposes. 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 April 2016 FortisBC Energy issued $300 million of unsecured debentures in a dual tranche of 10-year $150 million unsecured debentures at 2.58% and 30-year $150 million unsecured debentures at 3.67%. The net proceeds were used to repay short-term borrowings and to finance capital expenditures. In April 2015 FortisBC Energy issued 30-year $150 million 3.38% unsecured debentures. The net proceeds were used to repay short-term borrowings and for general corporate purposes. |
| (4) | In September 2016 FortisAlberta issued 30-year $150 million unsecured debentures at 3.34%. The net proceeds were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes. In September 2015 FortisAlberta issued 30-year $150 million 4.27% unsecured debentures. The net proceeds were used to repay credit facility borrowings and for general corporate purposes. |
| (5) | In September 2015 Newfoundland Power issued 30-year $75 million 4.446% secured first mortgage sinking fund bonds. The net proceeds were used to repay credit facility borrowings and for general corporate purposes. |
| (6) | In August 2016 Maritime Electric issued 40-year $40 million secured first mortgage bonds at 3.657%. The net proceeds were primarily used to repay long-term debt and short-term borrowings. |
| (7) | In May and September 2016, Fortis Turks and Caicos issued 15-year US$45 million unsecured notes, in a dual tranche of US$22.5 million at 5.14% and 5.29%, respectively. In July 2016 Fortis Turks and Caicos issued 15-year US$5 million unsecured bonds at 5.14%. The net proceeds were used to finance capital expenditures and for general corporate purposes. In January 2015 Fortis Turks and Caicos issued 15-year US$10 million 4.75% unsecured notes. The net proceeds were used to finance capital expenditures and for general corporate purposes. |
| Repayments of Long-Term Debt and Capital Lease and Finance Obligations (Unaudited) | ||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | ||||||||||
| ($ millions) | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||||||
| UNS Energy | – | (276 | ) | 276 | (19 | ) | (449 | ) | 430 | |||
| Central Hudson | – | – | – | (10 | ) | – | (10 | ) | ||||
| FortisBC Energy | (202 | ) | (75 | ) | (127 | ) | (211 | ) | (89 | ) | (122 | ) |
| FortisBC Electric | – | – | – | (25 | ) | – | (25 | ) | ||||
| Newfoundland Power | – | – | – | (30 | ) | – | (30 | ) | ||||
| Maritime Electric | (12 | ) | – | (12 | ) | (12 | ) | – | (12 | ) | ||
| Caribbean Utilities | – | – | – | (14 | ) | (13 | ) | (1 | ) | |||
| Fortis Turks and Caicos | (1 | ) | – | (1 | ) | (3 | ) | – | (3 | ) | ||
| Other | – | (2 | ) | 2 | – | (38 | ) | 38 | ||||
| Total | (215 | ) | (353 | ) | 138 | (324 | ) | (589 | ) | 265 | ||
| Net (Repayments) Borrowings Under Committed Credit Facilities (Unaudited) | ||||||||||||
| Periods Ended September 30 | Quarter | Year-to-Date | ||||||||||
| ($ millions) | 2016 | 2015 | Variance | 2016 | 2015 | Variance | ||||||
| UNS Energy | (17 | ) | (19 | ) | 2 | 51 | (141 | ) | 192 | |||
| FortisAlberta | (115 | ) | (105 | ) | (10 | ) | (53 | ) | (23 | ) | (30 | ) |
| Newfoundland Power | (13 | ) | (92 | ) | 79 | 33 | (65 | ) | 98 | |||
| Corporate (1) | 228 | (370 | ) | 598 | 565 | (95 | ) | 660 | ||||
| Total | 83 | (586 | ) | 669 | 596 | (324 | ) | 920 | ||||
| (1) | Borrowings under the Corporation’s committed credit facility in the third quarter of 2016 were primarily used to redeem preference shares in September 2016. Year-to-date 2016, borrowings were primarily used to redeem the preference shares and finance the acquisition of Aitken Creek. Repayments under the Corporation’s committed credit facility in the third quarter of 2015 were made using net proceeds from the sale of commercial real estate assets in June 2015. Year-to-date 2015, net repayments were partially offset by borrowings to finance equity injections into UNS Energy and FortisBC Energy, and for other general corporate purposes. |
Borrowings under committed 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.
In September 2016 the Corporation redeemed all of the First Preference Shares, Series E for $200 million.
Common share dividends paid in the third quarter of 2016 were $69 million, net of $37 million of dividends reinvested, compared to $56 million, net of $38 million of dividends reinvested, paid in the third quarter of 2015. Common share dividends paid year-to-date 2016 were $216 million, net of $102 million of dividends reinvested, compared to $171 million, net of $112 million of dividends reinvested, paid year-to-date 2015. The dividend paid per common share for each of the first, second and third quarters of 2016 was $0.375 compared to $0.34 for each of the same quarters of 2015. The weighted average number of common shares outstanding for the third quarter and year-to-date 2016 was 285.0 million and 283.7 million, respectively, compared to 279.1 million and 277.9 million for the same periods in 2015.
CONTRACTUAL OBLIGATIONS
The Corporation’s consolidated contractual obligations with external third parties in each of the next five years and for periods thereafter as at September 30, 2016, are outlined in the following table. A detailed description of the nature of the obligations is provided in the 2015 Annual MD&A and below, where applicable.
| Contractual Obligations (Unaudited) |
Total |
Due within 1 year |
Due in year 2 |
Due in year 3 |
Due in year 4 |
Due in year 5 |
Due after 5 years |
| As at September 30, 2016 | |||||||
| ($ millions) | |||||||
| Long-term debt (1) | 11,816 | 118 | 86 | 378 | 119 | 1,634 | 9,481 |
| Interest obligations on long-term debt (1) | 9,345 | 521 | 517 | 507 | 499 | 489 | 6,812 |
| Capital lease and finance obligations | 2,422 | 72 | 65 | 92 | 86 | 52 | 2,055 |
| Renewable power purchase obligations (2) | 1,621 | 97 | 97 | 97 | 97 | 96 | 1,137 |
| Gas purchase contract obligations | 1,329 | 448 | 261 | 176 | 134 | 104 | 206 |
| Power purchase obligations | 1,285 | 265 | 207 | 115 | 47 | 33 | 618 |
| Long-term contracts – UNS Energy (3) | 1,153 | 184 | 162 | 154 | 129 | 94 | 430 |
| Capital cost | 485 | 19 | 19 | 19 | 20 | 20 | 388 |
| Operating lease obligations | 165 | 11 | 11 | 10 | 9 | 6 | 118 |
| Renewable energy credit purchase agreements | 145 | 12 | 12 | 12 | 12 | 12 | 85 |
| Purchase of Springerville common facilities | 139 | – | 50 | – | – | 89 | – |
| Defined benefit pension funding contributions | 105 | 23 | 12 | 9 | 9 | 10 | 42 |
| Waneta Partnership promissory note | 72 | – | – | – | 72 | – | – |
| Joint-use asset and shared service agreements | 54 | 3 | 3 | 3 | 3 | 3 | 39 |
| Other | 83 | 21 | 15 | 20 | – | – | 27 |
| Total | 30,219 | 1,794 | 1,517 | 1,592 | 1,236 | 2,642 | 21,438 |
| (1) | In October 2016 Fortis issued US$2 billion unsecured notes to finance a portion of the cash purchase price of the acquisition of ITC. Long-term debt and interest obligations in the table, which are as at September 30, 2016, do not reflect this debt issuance. For further details refer to the “Significant Items” section of this MD&A. |
| (2) | UNS Energy is party to renewable power purchase agreements totalling approximately US$1,236 million as at September 30, 2016, which require UNS Energy to purchase 100% of the output of certain renewable energy generation facilities that have achieved commercial operation. In March and July 2016 two of the facilities achieved commercial operation, increasing estimated future payments of renewable power purchase contracts by US$58 million and US$86 million, respectively, as at September 30, 2016. |
| (3) | 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$137 million as at September 30, 2016. |
Other contractual obligations, which are not reflected in the above table, did not materially change from those disclosed in the 2015 Annual MD&A.
For a discussion of the nature and amount of the Corporation’s consolidated capital expenditure program not included in the preceding Contractual Obligations table, refer to the “Capital Expenditure Program” section of this MD&A.
CAPITAL STRUCTURE
The Corporation’s principal businesses of regulated electric and gas utilities require ongoing access to capital to enable the utilities to fund maintenance and expansion of infrastructure. Fortis raises debt at the subsidiary level to ensure regulatory transparency, tax efficiency and financing flexibility. Fortis generally finances a significant portion of acquisitions at the corporate level with proceeds from common share, preference share and long-term debt offerings. To help ensure access to capital, the Corporation targets a consolidated long-term capital structure that will enable it to maintain investment-grade credit ratings. Each of the Corporation’s regulated utilities maintains its own capital structure in line with the deemed capital structure reflected in each of the utility’s customer rates.
The consolidated capital structure of Fortis is presented in the following table.
| Capital Structure (Unaudited) | As at | |||
| September 30, 2016 | December 31, 2015 | |||
| ($ millions) | (%) | ($ millions) | (%) | |
| Total debt and capital lease and finance obligations (net of cash) (1) | 12,430 | 56.2 | 12,022 | 54.9 |
| Preference shares | 1,623 | 7.4 | 1,820 | 8.3 |
| Common shareholders’ equity | 8,045 | 36.4 | 8,060 | 36.8 |
| Total (2) | 22,098 | 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 September 30, 2016 was 55.3% debt, 7.5% preference shares and 37.2% common shareholders’ equity (December 31, 2015 – 53.8% debt, 8.5% preference shares and 37.7% common shareholders’ equity). The change in the Corporation’s capital structure was mainly due to an increase in total debt at the Corporation, primarily to finance the acquisition of Aitken Creek and redeem first preference shares, and at the regulated utilities, largely in support of energy infrastructure investment. The acquisition of ITC in October 2016 will significantly increase the Corporation’s total capitalization, however, the percentage breakdown of the consolidated capital structure is expected to be comparable with September 30, 2016.
CREDIT RATINGS
The Corporation’s credit ratings are as follows:
| Rating Agency | Credit Rating | Type of Rating | Outlook | |
| Standard & Poor’s (“S&P”) | A- | Corporate | Stable | |
| BBB+ | Unsecured debt | Stable | ||
| DBRS | BBB (high) | Unsecured debt | Stable | |
| Moody’s Investor Service (“Moody’s”) | Baa3 | Issuer | Stable | |
| Baa3 | Unsecured debt | Stable |
The above-noted credit ratings reflect the Corporation’s low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company. In 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 unsecured debt credit rating under review with negative implications. In September 2016 Moody’s commenced rating Fortis and assigned the Corporation an issuer credit rating of Baa3 and an unsecured debt credit rating of Baa3, both with a stable outlook. In October 2016, following the completion of the acquisition of ITC, DBRS revised the Corporation’s unsecured debt credit rating to BBB (high) from A (low) and revised its outlook to stable from under review with negative implications, and S&P affirmed the Corporation’s long-term corporate and unsecured debt credit ratings, as previously discussed, and revised its outlook to stable from negative.
CAPITAL EXPENDITURE PROGRAM
A breakdown of the $1,381 million in gross consolidated capital expenditures by segment year-to-date 2016 is provided in the following table.
| Gross Consolidated Capital Expenditures (Unaudited) (1) | ||||||||||
| Year-to-Date September 30, 2016 | ||||||||||
| ($ millions) | ||||||||||
| Regulated Utilities | Non-Regulated | |||||||||
| UNS Energy |
Central Hudson | FortisBC Energy | Fortis Alberta | FortisBC Electric | Eastern Canadian | Electric Caribbean | Total Regulated Utilities | Energy Infrastructure | Corporate and Other | Total |
| 416 | 177 | 252 | 260 | 53 | 113 | 83 | 1,354 | 17 | 10 | 1,381 |
| (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 $2.1 billion, an increase from the original forecast of $1.9 billion, as disclosed in the 2015 Annual MD&A. The increase is primarily due to expected capital investments at ITC from the date of acquisition. There have been no other 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 for 2016 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 at UNS Energy for 2016 are expected to be higher than the original forecast, primarily due to the purchase of the remaining 50.5% undivided interest in Springerville Unit 1 for US$85 million in September 2016 as part of a settlement agreement with the third-party owners. For a discussion of the nature of the Springerville Unit 1 settlement, 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 activities during the third quarter included the continued construction of the internal LNG storage tank and the control building, as well as the continued installation of the liquefaction process area major equipment. Tilbury 1A will be included in regulated rate base and is estimated to cost $440 million. It will include a second LNG tank and a new liquefier, both expected to be in service in mid-2017. Approximately $388 million has been invested in Tilbury 1A to the end of the third quarter of 2016.
In the second quarter of 2016, Caribbean Utilities completed its 39.7-MW generation expansion project, which included two 18.5 MW diesel-generating units, one 2.7 MW waste heat recovery steam turbine and associated auxiliary equipment. The generating units replaced retiring generators and provide firm capacity to meet expected load growth. The generation expansion project was completed on schedule and below budget, for a total cost of US$79 million.
Over the five-year period through 2021, including ITC, gross consolidated capital expenditures are expected to be approximately $13 billion. The approximate breakdown of the capital spending expected to be incurred is as follows: 29% at U.S. Regulated Electric & Gas Utilities; 28% at U.S. Regulated Transmission Utility, which is ITC; 26% at Canadian Regulated Electric Utilities, driven by FortisAlberta; 13% at Canadian Regulated Gas Utility; 3% 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 expected to be incurred is as follows: 58% for sustaining capital expenditures, 30% to meet customer growth, and 12% 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.
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.
FortisBC Energy’s potential pipeline expansion is conditional on Woodfibre LNG proceeding with its LNG export facility. Woodfibre LNG has obtained an export license from the National Energy Board and received environmental assessment approvals from the Squamish First Nation, the British Columbia Environmental Assessment Office, and the Canadian Environmental Assessment Agency. FortisBC Energy also received environmental assessment approval from the Squamish First Nation and provincial environmental assessment approval to date in 2016. The potential pipeline expansion has an estimated total project cost of up to $600 million. A final investment decision by Woodfibre LNG is targeted for late 2016.
In July 2016, following the dissolution of a proposed merger between Hawaiian Electric Company, Inc. (“Hawaiian Electric”) and NextEra Energy Resources, the 20-year agreement between Fortis Hawaii Energy Inc., a wholly owned subsidiary of Fortis, and Hawaiian Electric to export LNG to Hawaii was terminated. The Corporation’s Tilbury LNG facility is uniquely positioned to meet customer demand for clean-burning natural gas. The site is scalable and can accommodate additional storage and liquefaction equipment, and is relatively close to international shipping lanes. Despite the termination of the agreement with Hawaiian Electric, Fortis continues to have discussions with a number of other potential export customers.
The Corporation also has other significant opportunities that have not yet been included in the Corporation’s capital expenditure forecast including, but not limited to, transmission investment opportunities at ITC, including the 1,000 MW Lake Erie Connector project; the New York Transco, LLC to address electric transmission constraints in New York; renewable energy alternatives and transmission investments at UNS Energy; the Wataynikaneyap transmission line to connect remote First Nations communities in Ontario; 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 structures of its regulated operating subsidiaries will have an impact on its ability to pay dividends in the foreseeable future.
Cash required of Fortis to support subsidiary capital expenditure programs and finance acquisitions is expected to be derived from a combination of borrowings under the Corporation’s committed corporate credit facility and proceeds from the issuance of common shares, preference shares and long-term debt. Depending on the timing of cash payments from the subsidiaries, borrowings under the Corporation’s committed corporate credit facility may be required from time to time to support the servicing of debt and payment of dividends. 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 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 unsecured debentures at 2.58% and 30-year $150 million unsecured debentures at 3.67% under the base shelf prospectus. The net proceeds were used to repay short-term borrowings and to finance capital expenditures.
In October 2015 FortisAlberta 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 $500 million during the 25-month life of the shelf prospectus. In September 2016 FortisAlberta issued 30-year $150 million unsecured debentures at 3.34%. The net proceeds were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes.
Management expects consolidated fixed-term debt maturities and repayments to average approximately $450 million annually over the next five years, including an average of approximately $210 million at ITC. 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 September 30, 2016 and are expected to remain compliant throughout 2016.
CREDIT FACILITIES
As at September 30, 2016, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.8 billion, of which approximately $2.2 billion was unused, including $327 million unused under the Corporation’s committed 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 $3.6 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2021.
The following table outlines the credit facilities of the Corporation and its subsidiaries.
| Credit Facilities (Unaudited) | As at | ||||||||
| Regulated | Corporate | September 30, | December 31, | ||||||
| ($ millions) | Utilities | and Other | 2016 | 2015 | |||||
| Total credit facilities | 2,176 | 1,647 | 3,823 | 3,565 | |||||
| Credit facilities utilized: | |||||||||
| Short-term borrowings | (414 | ) | (9 | ) | (423 | ) | (511 | ) | |
| Long-term debt (1) | (51 | ) | (1,068 | ) | (1,119 | ) | (551 | ) | |
| Letters of credit outstanding | (68 | ) | (54 | ) | (122 | ) | (104 | ) | |
| Credit facilities unused | 1,643 | 516 | 2,159 | 2,399 | |||||
| (1) | As at September 30, 2016, credit facility borrowings classified as long-term debt included $51 million in current installments of long-term debt on the consolidated balance sheet (December 31, 2015 – $71 million). |
As at September 30, 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 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. In August 2016 the Corporation exercised its option to increase the facility to $1.3 billion from $1.0 billion.
In June 2016 FortisOntario amended its $30 million unsecured committed revolving credit facility to now mature in June 2019.
In July 2016 FortisBC Energy amended its $700 million unsecured committed revolving credit facility to now mature in August 2021.
In July 2016 FortisAlberta amended its $250 million unsecured committed revolving credit facility to now mature in August 2021.
In July 2016 Newfoundland Power amended its $100 million unsecured committed revolving credit facility to now mature in August 2021.
In October 2016 UNS Energy amended its US$500 million unsecured committed revolving credit facilities resulting in an extension of the maturity dates to October 2021.
In connection with the 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 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”). In October 2016, $535 million (US$404 million) was drawn on the Equity Bridge Facility to finance a portion of the cash purchase price of the acquisition of ITC and is repayable in full within one year. All remaining acquisition credit facilities have been cancelled. The credit facilities table above does not include the acquisition credit facilities.
FINANCIAL INSTRUMENTS
The carrying values of the Corporation’s consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows:
| Financial Instruments (Unaudited) | As at | |||
| September 30, 2016 | December 31, 2015 | |||
| Carrying | Estimated | Carrying | Estimated | |
| ($ millions) | Value | Fair Value | Value | Fair Value |
| Waneta Partnership promissory note | 58 | 62 | 56 | 59 |
| Long-term debt, including current portion | 11,816 | 13,909 | 11,240 | 12,614 |
The fair value of long-term debt is calculated using quoted market prices when available. When quoted market prices are not available, as is the case with the Waneta Partnership promissory note and certain long-term debt, the fair value is determined by either: (i) discounting the future cash flows of the specific debt instrument at an estimated yield to maturity equivalent to benchmark government bonds or treasury bills with similar terms to maturity, plus a credit risk premium equal to that of issuers of similar credit quality; or (ii) obtaining from third parties indicative prices for the same or similarly rated issues of debt of the same remaining maturities. Since the Corporation does not intend to settle the long-term debt or promissory note prior to maturity, the excess of the estimated fair value above the carrying value does not represent an actual liability.
Derivative Instruments
The Corporation generally limits the use of derivative instruments to those that qualify as accounting, economic or cash flow hedges, or those that are approved for regulatory recovery. The Corporation records all derivative instruments at fair value, with certain exceptions including those derivatives that qualify for the normal purchase and normal sale exception. The fair value of derivative instruments is the estimate of the amounts that the Corporation would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates. The Corporation’s derivatives primarily include energy contracts that are subject to regulatory deferral, as permitted by the regulators, as well as certain limited energy contracts that are not subject to regulatory deferral and cash flow hedges.
For details of the Corporation’s derivative instruments as at September 30, 2016, refer to Note 17 to the Corporation’s interim unaudited consolidated financial statements. There were no material changes in the nature and amount of the Corporations’ derivative instruments during the three and nine months ended September 30, 2016 from those disclosed in the 2015 Annual MD&A, except as follows.
Aitken Creek holds gas swap contracts to manage its exposure to changes in natural gas prices, to capture natural gas price spreads, and to manage the financial risk posed by physical transactions. The fair value of the gas swap contracts was calculated using forward pricing provided by third parties. The unrealized gains and losses on these derivative instruments are recorded in earnings. As at September 30, 2016, unrealized losses totalled $4 million ($3 million after tax).
In July 2016 the Corporation entered into forward-starting deal-contingent interest rate swap contracts with notional amounts totalling US$1.25 billion. These derivatives were designated as a hedge of a portion of the cash flow risk associated with the expected issuance of US$2 billion of long-term debt, which was completed on October 4, 2016, to finance a portion of the cash purchase price of the acquisition of ITC. As at September 30, 2016, the unrealized loss on the derivatives totalled approximately $9 million (US$7 million), of which $5 million (US$4 million) was recognized in other comprehensive income and $4 million (US$3 million) of hedge ineffectiveness was recognized in earnings. The derivative contracts were cancelled and settled in October 2016.
OFF-BALANCE SHEET ARRANGEMENTS
With the exception of letters of credit outstanding of $122 million as at September 30, 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: As a result of the closing of the ITC acquisition on October 14, 2016, the risks associated with the completion of the transaction are no longer applicable.
As a result of the acquisition of ITC, consolidated earnings and cash flows of Fortis will be impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, including ITC, it is estimated that a 5 cent increase or decrease in the US dollar relative-to-Canadian dollar exchange rate would increase or decrease earnings per common share of Fortis by approximately 7 cents. 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.
Capital Resources and Liquidity Risk – Credit Ratings: Year-to-date 2016 the following changes occurred to the debt credit ratings of the Corporation’s utilities: (i) 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; (ii) in March 2016 S&P affirmed Maritime Electric’s secured debt credit rating at ‘A’ and revised its outlook to stable from negative; (iii) in June 2016 S&P downgraded Central Hudson’s senior unsecured debt rating to ‘A-‘ from ‘A’ and revised its outlook to stable from negative; (iv) in July 2016 S&P affirmed TEP’s unsecured debt credit rating at BBB+ and revised its outlook to stable from negative; and (v) in October 2016, following the completion of the acquisition of ITC, S&P affirmed FortisAlberta’s and Caribbean Utilities’ debt credit ratings at ‘A-‘ and revised its outlook to stable from negative. For a discussion on the Corporation’s credit ratings refer to the “Liquidity and Capital Resources” section of this MD&A.
Defined Benefit Pension and Other Post-Employment Benefit Plan Assets: As at September 30, 2016, the fair value of the Corporation’s consolidated defined benefit pension and other post-employment benefit plan assets was $2,764 million, up $117 million or 4%, from $2,647 million as at December 31, 2015.
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 and nine months ended September 30, 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 for the three and nine months ended September 30, 2016. 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 18 to the Corporation’s interim unaudited consolidated financial statements for the three and nine months ended September 30, 2016.
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 and nine months ended September 30, 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 its consolidated financial statements.
Revenue from Contracts with Customers
ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and can be applied consistently across various transactions, industries and capital markets. 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, ASU 2016-10, Identifying Performance Obligations and Licensing, was issued in April 2016 and ASU No. 2016-12, Narrow-Scope Improvements and Practical Expedients, was issued in May 2016. The above-noted ASUs clarify implementation guidance in ASC Topic 606. The effective date and transition requirements of these updates are the same as ASU No. 2014-09.
The majority of the Corporation’s revenue is generated from energy sales to retail customers based on published tariff rates, as approved by the respective regulators, and is considered to be in the scope of ASU No. 2014-09. Fortis does not expect that the adoption of this standard, and all related ASUs, will have a material impact on the measurement of revenue generated from energy sales to retail customers. The Corporation 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 other revenue streams, and all related disclosures. Fortis plans to have this assessment substantially completed 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 expects to early adopt this standard in the fourth quarter of 2016, with an effective date of January 1, 2016, and is in the process of determining the impact that the early adoption of this standard will have on its consolidated financial statements and related disclosures.
Measurement of Credit Losses on Financial Instruments
ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Classification of Certain Cash Receipts and Cash Payments
ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments, was issued in August 2016 and the amendments in this update address diversity in practice on how eight specific cash receipts and cash payments are presented in the statement of cash flows. This update is effective for annual and interim periods beginning after December 15, 2017 and is to be applied on a retrospective basis for each period presented. Early adoption is permitted. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements or 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 nine months ended September 30, 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, except as described below. For complete details of legal proceedings affecting the Corporation, refer to Note 21 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 provided that TEP would purchase the third-party owners’ 50.5% undivided interest in Springerville Unit 1 for US$85 million and the third-party owners would pay TEP US$13 million for operating costs related to Springerville Unit 1 incurred on behalf of the third-party owners.
In September 2016 TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the undivided interest in Springerville Unit 1 for US$85 million, increasing TEP’s total ownership interest to 100%, and TEP received US$13 million from the third-party owners in full satisfaction of all previously unreimbursed operating costs. Following the purchase, all outstanding disputes, pending litigation and arbitration proceedings between TEP and the third-party owners were dismissed with prejudice.
Fortis and ITC
Following announcement of the acquisition of ITC on February 9, 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan (“Superior Court”) and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified rescissory and compensatory damages, and costs, including attorneys’ fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In July 2016 the Superior Court issued a scheduling order, which, among other things, requires the parties, including ITC, to complete discovery by March 2017, and set a trial date for June 2017. The outcome of these lawsuits cannot be predicted with any certainty and, accordingly, no amount has been accrued in the consolidated financial statements.
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 and nine months ended September 30, 2016 from those disclosed in the 2015 Annual MD&A.
Significant related-party transactions were as follows: (i) power purchased by FortisBC Electric from the Waneta Expansion, which totalled approximately $14 million and $32 million for the three and nine months ended September 30, 2016, respectively; (ii) the Waneta Expansion paid FortisBC Electric for management services associated with the generating facility, which totalled approximately $2 million and $7 million for the three and nine months ended September 30, 2016, respectively; and (iii) gas storage capacity leased by FortisBC Energy from Aitken Creek, from the date of acquisition, which totalled approximately $4 million and $9 million for the three and nine months ended September 30, 2016, respectively.
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 provides long-term financing to certain of its subsidiaries, bearing interest at rates that approximate the Corporation’s cost of long-term debt. As at September 30, 2016, there were no inter-segment loans outstanding (December 31, 2015 – $48 million) and total interest charged year-to-date 2016 was less than $1 million.
SUMMARY OF QUARTERLY RESULTS
The following table sets forth unaudited quarterly information for each of the eight quarters ended December 31, 2014 through September 30, 2016. The quarterly information has been obtained from the Corporation’s interim unaudited consolidated financial statements. These financial results are not necessarily indicative of results for any future period and should not be relied upon to predict future performance.
| Summary of Quarterly Results | Net Earnings | |||
| (Unaudited) | Attributable to | |||
| Common Equity | ||||
| Revenue | Shareholders | Earnings per Common Share | ||
| Quarter Ended | ($ millions) | ($ millions) | Basic ($) | Diluted ($) |
| September 30, 2016 | 1,510 | 127 | 0.45 | 0.45 |
| June 30, 2016 | 1,477 | 107 | 0.38 | 0.38 |
| 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 |
The summary of the past eight quarters reflects the Corporation’s continued organic growth, growth from acquisitions and associated acquisition-related expenses, the impact of the sale of non-regulated assets, as well as the seasonality associated with its businesses. Interim results will fluctuate due to the seasonal nature of electricity and gas demand 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.
September 2016/September 2015: Net earnings attributable to common equity shareholders were $127 million, or $0.45 per common share, for the third quarter of 2016 compared to earnings of $151 million, or $0.54 per common share, for the third 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.
June 2016/June 2015: Net earnings attributable to common equity shareholders were $107 million, or $0.38 per common share, for the second quarter of 2016 compared to earnings of $244 million, or $0.88 per common share, for the second quarter of 2015. The decrease in earnings was primarily due to: $22 million in acquisition-related expenses and fees and a $2 million unrealized loss on the mark-to-market of derivatives in the second quarter of 2016, and a net gain of $123 million on the sale of commercial real estate, hotel and non-regulated generation assets recognized in the second quarter of 2015. Excluding these items, the $10 million increase in earnings was mainly due to: (i) strong performance at most of the Corporation’s regulated utilities; (ii) contribution of $4 million from Aitken Creek, which was acquired in early April 2016; (iii) favourable foreign exchange associated with US dollar-denominated earnings; and (iv) the timing of quarterly earnings at FortisBC Electric compared to the second quarter of 2015. The increase was partially offset by lower earnings at FortisAlberta, due to higher operating expenses and lower average energy consumption, and the sale of commercial real estate and hotel assets in 2015.
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. The decrease in earnings was primarily due to: $17 million in acquisition-related expenses and $11 million (US$8 million) in FERC ordered transmission refunds recognized in the first quarter of 2016, and a positive capital tracker revenue adjustment of $10 million and a foreign exchange gain of $9 million recognized in the first quarter of 2015. Excluding these items, the $11 million increase in net earnings 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.
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 fourth quarter of 2015 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.
OUTLOOK
The Corporation’s business continues to grow in 2016 and results for 2017 will benefit from the impact of ITC, the expected outcome of the TEP general rate case and continued growth of the underlying business. Over the long term, Fortis is well positioned to enhance value for shareholders through the execution of its capital plan, the balance and strength of its diversified portfolio of businesses, as well as growth opportunities within its franchise regions.
Over the five-year period through 2021, including ITC, the Corporation’s capital program is expected to be approximately $13 billion. This investment in energy infrastructure is expected to increase rate base to almost $30 billion in 2021. Fortis expects long-term sustainable growth in rate base, resulting from investment in its existing utility operations and strategic utility acquisitions, to support continuing growth in earnings and dividends.
Fortis extended its targeted average annual dividend growth of approximately 6% through 2021. This dividend guidance takes into account many factors, including the expectation of reasonable outcomes for regulatory proceedings at the Corporation’s utilities, the successful execution of the five-year capital expenditure program, and management’s continued confidence in the strength of the Corporation’s diversified portfolio of utilities and record of operational excellence.
SUBSEQUENT EVENT
On October 14, 2016, Fortis and GIC acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion on closing, including approximately US$4.8 billion of ITC consolidated indebtedness at fair value. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC.
On October 4, 2016 Fortis issued US$2.0 billion unsecured notes, comprised of 5-year US$500 million notes at 2.100% and 10-year US$1.5 billion notes at 3.055%. The net proceeds were used to finance a portion of the cash purchase price of the acquisition of ITC.
On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing the portion of share consideration associated with the acquisition.
For details on the business acquisition, refer to the “Significant Items” section of this MD&A.
OUTSTANDING SHARE DATA
As at November 3, 2016, the Corporation had issued and outstanding approximately 399.8 million common shares; 5.0 million First Preference Shares, Series F; 9.2 million First Preference Shares, Series G; 7.0 million First Preference Shares, Series H; 3.0 million First Preference Shares, Series I; 8.0 million First Preference Shares, Series J; 10.0 million First Preference Shares, Series K; and 24.0 million First Preference Shares, Series M. Only the common shares of the Corporation have voting rights. The Corporation’s First Preference Shares do not have voting rights unless and until Fortis fails to pay eight quarterly dividends, whether or not consecutive and whether or not such dividends have been declared.
The number of common shares of Fortis that would be issued if all outstanding stock options were converted as at November 3, 2016 is approximately 4.2 million.
Additional information can be accessed at www.fortisinc.com, www.sedar.com, or www.sec.gov.
| Interim Consolidated Financial Statements |
| For the three and nine months ended September 30, 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) | ||||
| September 30, 2016 | December 31, 2015 | |||
| ASSETS | ||||
| Current assets | ||||
| Cash and cash equivalents | $ | 301 | $ | 242 |
| Accounts receivable and other current assets | 837 | 964 | ||
| Prepaid expenses | 101 | 68 | ||
| Inventories | 337 | 337 | ||
| Regulatory assets (Note 5) | 209 | 246 | ||
| 1,785 | 1,857 | |||
| Other assets | 308 | 352 | ||
| Regulatory assets (Note 5) | 2,286 | 2,286 | ||
| Utility capital assets | 20,205 | 19,595 | ||
| Intangible assets | 549 | 541 | ||
| Goodwill | 4,058 | 4,173 | ||
| $ | 29,191 | $ | 28,804 | |
| LIABILITIES AND SHAREHOLDERS’ EQUITY | ||||
| Current liabilities | ||||
| Short-term borrowings (Note 19) | $ | 423 | $ | 511 |
| Accounts payable and other current liabilities | 1,438 | 1,419 | ||
| Regulatory liabilities (Note 5) | 312 | 298 | ||
| Current installments of long-term debt (Note 6) | 118 | 384 | ||
| Current installments of capital lease and finance obligations | 27 | 26 | ||
| 2,318 | 2,638 | |||
| Other liabilities | 1,126 | 1,152 | ||
| Regulatory liabilities (Note 5) | 1,319 | 1,340 | ||
| Deferred income taxes | 2,203 | 2,050 | ||
| Long-term debt (Note 6) | 11,624 | 10,784 | ||
| Capital lease and finance obligations | 465 | 487 | ||
| 19,055 | 18,451 | |||
| Shareholders’ equity | ||||
| Common Shares (1) (Note 7) | 6,012 | 5,867 | ||
| Preference shares (Note 8) | 1,623 | 1,820 | ||
| Additional paid-in capital | 12 | 14 | ||
| Accumulated other comprehensive income | 565 | 791 | ||
| Retained earnings | 1,456 | 1,388 | ||
| Total Fortis Inc. shareholders’ equity | 9,668 | 9,880 | ||
| Non-controlling interests | 468 | 473 | ||
| 10,136 | 10,353 | |||
| $ | 29,191 | $ | 28,804 | |
| (1) No par value. Unlimited authorized shares; 285.5 million and 281.6 million issued and outstanding as at September 30, 2016 and December 31, 2015, respectively | ||||
| Commitments and Contingencies (Note 20 and Note 21, respectively) | ||||
| See accompanying Notes to Interim Consolidated Financial Statements | ||||
| Fortis Inc. | |||||||||
| Consolidated Statements of Earnings (Unaudited) | |||||||||
| For the periods ended September 30 | |||||||||
| (in millions of Canadian dollars, except per share amounts) | |||||||||
| Quarter Ended | Nine Months Ended | ||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||
| Revenue | $ | 1,510 | $ | 1,566 | $ | 4,744 | $ | 5,019 | |
| Expenses | |||||||||
| Energy supply costs | 485 | 533 | 1,657 | 1,897 | |||||
| Operating | 439 | 461 | 1,367 | 1,392 | |||||
| Depreciation and amortization | 234 | 217 | 700 | 652 | |||||
| 1,158 | 1,211 | 3,724 | 3,941 | ||||||
| Operating income | 352 | 355 | 1,020 | 1,078 | |||||
| Other income (expenses), net (Note 11) | 10 | 5 | 35 | 188 | |||||
| Finance charges (Note 12) | 164 | 141 | 457 | 416 | |||||
| Earnings before income taxes | 198 | 219 | 598 | 850 | |||||
| Income tax expense (Note 13) | 40 | 40 | 110 | 173 | |||||
| Net earnings | $ | 158 | $ | 179 | $ | 488 | $ | 677 | |
| Net earnings attributable to: | |||||||||
| Non-controlling interests | $ | 9 | $ | 9 | $ | 33 | $ | 26 | |
| Preference equity shareholders | 22 | 19 | 59 | 58 | |||||
| Common equity shareholders | 127 | 151 | 396 | 593 | |||||
| $ | 158 | $ | 179 | $ | 488 | $ | 677 | ||
| Earnings per common share (Note 14) | |||||||||
| Basic | $ | 0.45 | $ | 0.54 | $ | 1.40 | $ | 2.13 | |
| Diluted | $ | 0.45 | $ | 0.54 | $ | 1.39 | $ | 2.11 | |
| See accompanying Notes to Interim Consolidated Financial Statements | |||||||||
| Fortis Inc. | ||||||||||||
| Consolidated Statements of Comprehensive Income (Unaudited) | ||||||||||||
| For the periods ended September 30 | ||||||||||||
| (in millions of Canadian dollars) | ||||||||||||
| Quarter Ended | Nine Months Ended | |||||||||||
| 2016 | 2015 | 2016 | 2015 | |||||||||
| Net earnings | $ | 158 | $ | 179 | $ | 488 | $ | 677 | ||||
| Other comprehensive income (loss) | ||||||||||||
| Unrealized foreign currency translation gains (losses), net of hedging activities and tax | 58 | 253 | (229 | ) | 502 | |||||||
| Reclassification to earnings of foreign currency translation loss on disposal of investment in foreign operations, net of tax | – | – | – | 2 | ||||||||
| Unrealized gains (losses) on available-for-sale investment, net of tax (Note 17) | 4 | 1 | 6 | (1 | ) | |||||||
| Net change in fair value of cash flow hedges, net of tax (Note 17) | (3 | ) | 1 | (3 | ) | 1 | ||||||
| 59 | 255 | (226 | ) | 504 | ||||||||
| Comprehensive income | $ | 217 | $ | 434 | $ | 262 | $ | 1,181 | ||||
| Comprehensive income attributable to: | ||||||||||||
| Non-controlling interests | $ | 9 | $ | 9 | $ | 33 | $ | 26 | ||||
| Preference equity shareholders | 22 | 19 | 59 | 58 | ||||||||
| Common equity shareholders | 186 | 406 | 170 | 1,097 | ||||||||
| $ | 217 | $ | 434 | $ | 262 | $ | 1,181 | |||||
| See accompanying Notes to Interim Consolidated Financial Statements | ||||||||||||
| Fortis Inc. | |||||||||||||
| Consolidated Statements of Cash Flows (Unaudited) | |||||||||||||
| For the periods ended September 30 | |||||||||||||
| (in millions of Canadian dollars) | |||||||||||||
| Quarter Ended | Nine Months Ended | ||||||||||||
| 2016 | 2015 | 2016 | 2015 | ||||||||||
| Operating activities | |||||||||||||
| Net earnings | $ | 158 | $ | 179 | $ | 488 | $ | 677 | |||||
| Adjustments to reconcile net earnings to net cash | |||||||||||||
| provided by operating activities: | |||||||||||||
| Depreciation – capital assets | 210 | 195 | 626 | 586 | |||||||||
| Amortization – intangible assets | 17 | 16 | 52 | 48 | |||||||||
| Amortization – other | 7 | 6 | 22 | 18 | |||||||||
| Deferred income tax expense | 29 | 65 | 59 | 104 | |||||||||
| Accrued employee future benefits | 1 | (38 | ) | 23 | (24 | ) | |||||||
| Equity component of allowance for funds used during construction (Note 11) | (7 | ) | (6 | ) | (20 | ) | (15 | ) | |||||
| Loss (gain) on sale of non-utility capital assets (Note 11) | – | 2 | – | (131 | ) | ||||||||
| Gain on sale of non-regulated generation assets (Note 11) | – | (5 | ) | – | (62 | ) | |||||||
| Other | 6 | 39 | 60 | 67 | |||||||||
| Change in long-term regulatory assets and liabilities | (6 | ) | 5 | (38 | ) | (71 | ) | ||||||
| Change in non-cash operating working capital (Note 15) | 63 | (100 | ) | 137 | 79 | ||||||||
| 478 | 358 | 1,409 | 1,276 | ||||||||||
| Investing activities | |||||||||||||
| Change in other assets and other liabilities | (23 | ) | 34 | (49 | ) | (22 | ) | ||||||
| Capital expenditures – utility capital assets | (498 | ) | (487 | ) | (1,315 | ) | (1,595 | ) | |||||
| Capital expenditures – non-utility capital assets | – | – | – | (9 | ) | ||||||||
| Capital expenditures – intangible assets | (24 | ) | (25 | ) | (66 | ) | (79 | ) | |||||
| Purchase of assets held for sale | – | (4 | ) | – | (31 | ) | |||||||
| Contributions in aid of construction | 15 | 17 | 33 | 45 | |||||||||
| Proceeds on sale of assets (Note 11) | 1 | 19 | 11 | 557 | |||||||||
| Business acquisition, net of cash acquired (Note 16) | – | – | (318 | ) | – | ||||||||
| (529 | ) | (446 | ) | (1,704 | ) | (1,134 | ) | ||||||
| Financing activities | |||||||||||||
| Change in short-term borrowings and other financing activities | 252 | 236 | (23 | ) | 35 | ||||||||
| Proceeds from long-term debt, net of issue costs | 223 | 387 | 579 | 1,005 | |||||||||
| Repayments of long-term debt and capital lease and finance obligations | (215 | ) | (353 | ) | (324 | ) | (589 | ) | |||||
| Net borrowings (repayments) under committed credit facilities | 83 | (586 | ) | 596 | (324 | ) | |||||||
| Advances from non-controlling interests | 1 | – | 2 | 19 | |||||||||
| Issue of common shares, net of costs and dividends reinvested | 13 | 5 | 40 | 25 | |||||||||
| Redemption of preference shares (Note 8) | (200 | ) | – | (200 | ) | – | |||||||
| Dividends | |||||||||||||
| Common shares, net of dividends reinvested | (69 | ) | (56 | ) | (216 | ) | (171 | ) | |||||
| Preference shares | (19 | ) | (19 | ) | (56 | ) | (58 | ) | |||||
| Subsidiary dividends paid to non-controlling interests | (18 | ) | (2 | ) | (33 | ) | (8 | ) | |||||
| 51 | (388 | ) | 365 | (66 | ) | ||||||||
| Effect of exchange rate changes on cash and cash equivalents | 5 | 24 | (11 | ) | 41 | ||||||||
| Change in cash and cash equivalents | 5 | (452 | ) | 59 | 117 | ||||||||
| Change in cash associated with assets held for sale | – | 2 | – | – | |||||||||
| Cash and cash equivalents, beginning of period | 296 | 797 | 242 | 230 | |||||||||
| Cash and cash equivalents, end of period | $ | 301 | $ | 347 | $ | 301 | $ | 347 | |||||
| Supplementary Information to Consolidated Statements of Cash Flows (Note 15) | |||||||||||||
| See accompanying Notes to Interim Consolidated Financial Statements | |||||||||||||
| Fortis Inc. | |||||||||||||||||||||
| Consolidated Statements of Changes in Equity (Unaudited) | |||||||||||||||||||||
| For the periods ended September 30 | |||||||||||||||||||||
| (in millions of Canadian dollars) | |||||||||||||||||||||
| Common Shares | Preference Shares | Additional Paid-in Capital | Accumulated Other Comprehensive Income (Loss) | Retained Earnings | Non-Controlling Interests | Total Equity | |||||||||||||||
| (Note 7 | ) | (Note 8 | ) | ||||||||||||||||||
| As at January 1, 2016 | $ | 5,867 | $ | 1,820 | $ | 14 | $ | 791 | $ | 1,388 | $ | 473 | $ | 10,353 | |||||||
| Net earnings | – | – | – | – | 455 | 33 | 488 | ||||||||||||||
| Other comprehensive loss | – | – | – | (226 | ) | – | – | (226 | ) | ||||||||||||
| Common share issues | 145 | – | (4 | ) | – | – | – | 141 | |||||||||||||
| Stock-based compensation | – | – | 2 | – | – | – | 2 | ||||||||||||||
| Advances from non-controlling interests | – | – | – | – | – | 2 | 2 | ||||||||||||||
| Foreign currency translation impacts | – | – | – | – | – | (7 | ) | (7 | ) | ||||||||||||
| Subsidiary dividends paid to non-controlling interests | – | – | – | – | – | (33 | ) | (33 | ) | ||||||||||||
| Redemption of preference shares | – | (197 | ) | – | – | – | – | (197 | ) | ||||||||||||
| Dividends declared on common shares ($1.15 per share) | – | – | – | – | (328 | ) | – | (328 | ) | ||||||||||||
| Dividends declared on preference shares | – | – | – | – | (59 | ) | – | (59 | ) | ||||||||||||
| As at September 30, 2016 | $ | 6,012 | $ | 1,623 | $ | 12 | $ | 565 | $ | 1,456 | $ | 468 | $ | 10,136 | |||||||
| As at January 1, 2015 | $ | 5,667 | $ | 1,820 | $ | 15 | $ | 129 | $ | 1,060 | $ | 421 | $ | 9,112 | |||||||
| Net earnings | – | – | – | – | 651 | 26 | 677 | ||||||||||||||
| Other comprehensive income | – | – | – | 504 | – | – | 504 | ||||||||||||||
| Common share issues | 140 | – | (2 | ) | – | – | – | 138 | |||||||||||||
| Stock-based compensation | – | – | 2 | – | – | – | 2 | ||||||||||||||
| Advances from non-controlling interests | – | – | – | – | – | 19 | 19 | ||||||||||||||
| Foreign currency translation impacts | – | – | – | – | – | 16 | 16 | ||||||||||||||
| Subsidiary dividends paid to non-controlling interests | – | – | – | – | – | (8 | ) | (8 | ) | ||||||||||||
| Dividends declared on common shares ($1.06 per share) | – | – | – | – | (294 | ) | – | (294 | ) | ||||||||||||
| Dividends declared on preference shares | – | – | – | – | (58 | ) | – | (58 | ) | ||||||||||||
| As at September 30, 2015 | $ | 5,807 | $ | 1,820 | $ | 15 | $ | 633 | $ | 1,359 | $ | 474 | $ | 10,108 | |||||||
| See accompanying Notes to Interim Consolidated Financial Statements | |||||||||||||||||||||
FORTIS INC. NOTES TO INTERIM CONSOLIDATED FINANCIAL STATEMENTS For the three and nine months ended September 30, 2016 and 2015 (unless otherwise stated) (Unaudited)
1. DESCRIPTION OF BUSINESS
NATURE OF OPERATIONS
Fortis Inc. (“Fortis” or the “Corporation”) is principally an international electric and gas utility holding company. Fortis segments its utility operations by franchise area and, depending on regulatory requirements, by the nature of the assets. Fortis also holds investments in non-regulated energy infrastructure, which is treated as a separate segment. The Corporation’s reporting segments allow senior management to evaluate the operational performance and assess the overall contribution of each segment to the long-term objectives of Fortis. Each entity within the reporting segments operates with substantial autonomy, assumes profit and loss responsibility and is accountable for its own resource allocation.
The 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:
- 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”).
- Regulated Gas Utility – Canadian: Primarily includes FortisBC Energy Inc. (“FortisBC Energy”).
- Regulated Electric Utilities – Canadian: Comprised of FortisAlberta Inc. (“FortisAlberta”), FortisBC Inc. (“FortisBC Electric”), and Eastern Canadian Electric Utilities. Eastern Canadian Electric Utilities is comprised of Newfoundland Power Inc. (“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.
- Regulated Electric Utilities – Caribbean: Comprised of Caribbean Utilities Company, Ltd. (“Caribbean Utilities”), in which Fortis holds an approximate 60% controlling interest, two wholly owned utilities in the Turks and Caicos Islands, FortisTCI Limited and Turks and Caicos Utilities Limited (collectively “Fortis Turks and Caicos”), and also includes the Corporation’s 33% equity investment in Belize Electricity Limited (“Belize Electricity”).
NON-REGULATED – ENERGY INFRASTRUCTURE
Non-Regulated – Energy Infrastructure is primarily comprised of long-term contracted generation assets in British Columbia and Belize, and the Aitken Creek natural gas storage facility (“Aitken Creek”) in British Columbia. Aitken Creek was acquired by Fortis on April 1, 2016 and the financial results are included in this segment from the date of acquisition (Note 16). In February 2016 the Corporation sold its Walden hydroelectric generating facility in British Columbia for gross proceeds of approximately $9 million.
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 (Note 11).
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.
ACQUISITION OF ITC HOLDINGS CORP.
On October 14, 2016, Fortis and GIC Private Limited (“GIC”) acquired all of the outstanding common shares of ITC Holdings Corp. (“ITC”) for an aggregate purchase price of approximately US$11.8 billion on closing, including approximately US$4.8 billion of ITC consolidated indebtedness at fair value. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC. For details on the business acquisition refer to Note 16.
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 and nine months ended September 30, 2016.
An evaluation of subsequent events through November 3, 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 September 30, 2016 (Note 22).
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 and nine months ended September 30, 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 for the three and nine months ended September 30, 2016. 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 18).
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 and nine months ended September 30, 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 its consolidated financial statements.
Revenue from Contracts with Customers
ASU No. 2014-09 was issued in May 2014 and the amendments in this update create Accounting Standards Codification (“ASC”) Topic 606, Revenue from Contracts with Customers, and supersede the revenue recognition requirements in ASC Topic 605, Revenue Recognition, including most industry-specific revenue recognition guidance throughout the codification. This standard clarifies the principles for recognizing revenue and can be applied consistently across various transactions, industries and capital markets. 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, ASU 2016-10, Identifying Performance Obligations and Licensing, was issued in April 2016 and ASU No. 2016-12, Narrow-Scope Improvements and Practical Expedients, was issued in May 2016. The above-noted ASUs clarify implementation guidance in ASC Topic 606. The effective date and transition requirements of these updates are the same as ASU No. 2014-09.
The majority of the Corporation’s revenue is generated from energy sales to retail customers based on published tariff rates, as approved by the respective regulators, and is considered to be in the scope of ASU No. 2014-09. Fortis does not expect that the adoption of this standard, and all related ASUs, will have a material impact on the measurement of revenue generated from energy sales to retail customers. The Corporation 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 other revenue streams, and all related disclosures. Fortis plans to have this assessment substantially completed 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 expects to early adopt this standard in the fourth quarter of 2016, with an effective date of January 1, 2016, and is in the process of determining the impact that the early adoption of this standard will have on its consolidated financial statements and related disclosures.
Measurement of Credit Losses on Financial Instruments
ASU No. 2016-13, Measurement of Credit Losses on Financial Instruments, was issued in June 2016 and the amendments in this update require entities to use an expected credit loss methodology and to consider a broader range of reasonable and supportable information to inform credit loss estimates. This update is effective for annual and interim periods beginning after December 15, 2019 and is to be applied on a modified retrospective basis. Early adoption is permitted for annual and interim periods beginning after December 15, 2018. Fortis is assessing the impact that the adoption of this update will have on its consolidated financial statements and related disclosures.
Classification of Certain Cash Receipts and Cash Payments
ASU No. 2016-15, Classification of Certain Cash Receipts and Cash Payments, was issued in August 2016 and the amendments in this update address diversity in practice on how eight specific cash receipts and cash payments are presented in the statement of cash flows. This update is effective for annual and interim periods beginning after December 15, 2017 and is to be applied on a retrospective basis for each period presented. Early adoption is permitted. Fortis does not expect that the adoption of this update will have a material impact on its consolidated financial statements or related disclosures.
4. SEGMENTED INFORMATION
Information by reportable segment is as follows:
| REGULATED | NON-REGULATED | |||||||||||||||||||
| United States | Canada | |||||||||||||||||||
| Quarter Ended | Electric & Gas | Gas | Electric | |||||||||||||||||
| September 30, 2016 ($ millions) |
UNS Energy |
Central Hudson |
Total | FortisBC Energy |
Fortis Alberta |
FortisBC Electric |
Eastern Canadian |
Total | Caribbean Electric |
Energy Infrastructure |
Non-Utility | Corporate and Other |
Inter-segment eliminations |
Total | ||||||
| Revenue | 604 | 208 | 812 | 151 | 143 | 88 | 211 | 593 | 79 | 44 | – | 2 | (20 | ) | 1,510 | |||||
| Energy supply costs | 214 | 66 | 280 | 29 | – | 32 | 123 | 184 | 35 | 3 | – | – | (17 | ) | 485 | |||||
| Operating expenses | 148 | 96 | 244 | 69 | 46 | 20 | 32 | 167 | 11 | 12 | – | 8 | (3 | ) | 439 | |||||
| Depreciation and amortization | 65 | 15 | 80 | 49 | 45 | 15 | 23 | 132 | 13 | 8 | – | 1 | – | 234 | ||||||
| Operating income | 177 | 31 | 208 | 4 | 52 | 21 | 33 | 110 | 20 | 21 | – | (7 | ) | – | 352 | |||||
| Other income (expenses), net | 2 | 1 | 3 | 4 | – | 1 | – | 5 | 1 | – | – | 1 | – | 10 | ||||||
| Finance charges | 24 | 10 | 34 | 33 | 21 | 9 | 15 | 78 | 4 | 1 | – | 47 | – | 164 | ||||||
| Income tax expense (recovery) | 53 | 8 | 61 | (6 | ) | 1 | 2 | 4 | 1 | – | – | – | (22 | ) | – | 40 | ||||
| Net earnings (loss) | 102 | 14 | 116 | (19 | ) | 30 | 11 | 14 | 36 | 17 | 20 | – | (31 | ) | – | 158 | ||||
| Non-controlling interests | – | – | – | – | – | – | – | – | 4 | 5 | – | – | – | 9 | ||||||
| Preference share dividends | – | – | – | – | – | – | – | – | – | – | – | 22 | – | 22 | ||||||
| Net earnings (loss) attributable to common equity shareholders | 102 | 14 | 116 | (19 | ) | 30 | 11 | 14 | 36 | 13 | 15 | – | (53 | ) | – | 127 | ||||
| Goodwill | 1,812 | 591 | 2,403 | 913 | 227 | 235 | 67 | 1,442 | 186 | 27 | – | – | – | 4,058 | ||||||
| Identifiable assets | 6,826 | 2,479 | 9,305 | 5,089 | 3,789 | 1,899 | 2,255 | 13,032 | 1,137 | 1,465 | – | 280 | (86 | ) | 25,133 | |||||
| Total assets | 8,638 | 3,070 | 11,708 | 6,002 | 4,016 | 2,134 | 2,322 | 14,474 | 1,323 | 1,492 | – | 280 | (86 | ) | 29,191 | |||||
| Gross capital expenditures | 198 | 59 | 257 | 86 | 94 | 15 | 50 | 245 | 19 | 1 | – | – | – | 522 | ||||||
| Quarter Ended | ||||||||||||||||||||
| September 30, 2015 | ||||||||||||||||||||
| ($ millions) | ||||||||||||||||||||
| Revenue | 623 | 193 | 816 | 168 | 141 | 85 | 206 | 600 | 87 | 29 | 47 | 8 | (21 | ) | 1,566 | |||||
| Energy supply costs | 242 | 59 | 301 | 47 | – | 30 | 122 | 199 | 46 | – | – | – | (13 | ) | 533 | |||||
| Operating expenses | 146 | 94 | 240 | 69 | 44 | 21 | 33 | 167 | 11 | 4 | 34 | 8 | (3 | ) | 461 | |||||
| Depreciation and amortization | 61 | 14 | 75 | 47 | 42 | 14 | 21 | 124 | 12 | 6 | – | – | – | 217 | ||||||
| Operating income | 174 | 26 | 200 | 5 | 55 | 20 | 30 | 110 | 18 | 19 | 13 | – | (5 | ) | 355 | |||||
| Other income (expenses), net | – | 2 | 2 | 2 | 1 | – | 1 | 4 | – | 5 | (2 | ) | (4 | ) | – | 5 | ||||
| Finance charges | 25 | 10 | 35 | 34 | 20 | 9 | 14 | 77 | 3 | 1 | 5 | 25 | (5 | ) | 141 | |||||
| Income tax expense (recovery) | 52 | 7 | 59 | (7 | ) | (1 | ) | 3 | 4 | (1 | ) | – | – | (5 | ) | (13 | ) | – | 40 | |
| Net earnings (loss) | 97 | 11 | 108 | (20 | ) | 37 | 8 | 13 | 38 | 15 | 23 | 11 | (16 | ) | – | 179 | ||||
| Non-controlling interests | – | – | – | – | – | – | – | – | 4 | 5 | – | – | – | 9 | ||||||
| Preference share dividends | – | – | – | – | – | – | – | – | – | – | – | 19 | – | 19 | ||||||
| Net earnings (loss) attributable to common equity shareholders | 97 | 11 | 108 | (20 | ) | 37 | 8 | 13 | 38 | 11 | 18 | 11 | (35 | ) | – | 151 | ||||
| Goodwill | 1,842 | 602 | 2,444 | 913 | 227 | 235 | 67 | 1,442 | 189 | – | – | – | – | 4,075 | ||||||
| Identifiable assets | 6,699 | 2,407 | 9,106 | 4,960 | 3,501 | 1,855 | 2,162 | 12,478 | 1,050 | 1,025 | 381 | 613 | (410 | ) | 24,243 | |||||
| Total assets | 8,541 | 3,009 | 11,550 | 5,873 | 3,728 | 2,090 | 2,229 | 13,920 | 1,239 | 1,025 | 381 | 613 | (410 | ) | 28,318 | |||||
| Gross capital expenditures | 103 | 56 | 159 | 125 | 99 | 23 | 42 | 289 | 51 | 12 | – | 1 | – | 512 | ||||||
| REGULATED | NON-REGULATED | ||||||||||||||||
| United States | Canada | ||||||||||||||||
| Year-to-Date | Electric & Gas | Gas | Electric | ||||||||||||||
| September 30, 2016 ($ millions) |
UNS Energy |
Central Hudson |
Total | FortisBC Energy |
Fortis Alberta |
FortisBC Electric |
Eastern Canadian |
Total | Caribbean Electric |
Energy Infrastructure |
Non-Utility | Corporate and Other |
Inter-segment eliminations |
Total | |||
| Revenue | 1,534 | 642 | 2,176 | 758 | 429 | 275 | 785 | 2,247 | 225 | 139 | – | 7 | (50 | ) | 4,744 | ||
| Energy supply costs | 570 | 199 | 769 | 204 | – | 93 | 511 | 808 | 101 | 20 | – | – | (41 | ) | 1,657 | ||
| Operating expenses | 447 | 289 | 736 | 209 | 142 | 63 | 101 | 515 | 35 | 28 | – | 61 | (8 | ) | 1,367 | ||
| Depreciation and amortization | 197 | 46 | 243 | 149 | 134 | 43 | 68 | 394 | 39 | 21 | – | 3 | – | 700 | |||
| Operating income | 320 | 108 | 428 | 196 | 153 | 76 | 105 | 530 | 50 | 70 | – | (57 | ) | (1 | ) | 1,020 | |
| Other income (expenses), net | 6 | 3 | 9 | 11 | 2 | 1 | 1 | 15 | 5 | 1 | – | 5 | – | 35 | |||
| Finance charges | 75 | 30 | 105 | 97 | 63 | 28 | 43 | 231 | 10 | 3 | – | 109 | (1 | ) | 457 | ||
| Income tax expense (recovery) | 81 | 31 | 112 | 29 | 1 | 8 | 15 | 53 | – | 1 | – | (56 | ) | – | 110 | ||
| Net earnings (loss) | 170 | 50 | 220 | 81 | 91 | 41 | 48 | 261 | 45 | 67 | – | (105 | ) | – | 488 | ||
| Non-controlling interests | – | – | – | – | – | – | – | – | 11 | 22 | – | – | – | 33 | |||
| Preference share dividends | – | – | – | – | – | – | – | – | – | – | – | 59 | – | 59 | |||
| Net earnings (loss) attributable to common equity shareholders | 170 | 50 | 220 | 81 | 91 | 41 | 48 | 261 | 34 | 45 | – | (164 | ) | – | 396 | ||
| Goodwill | 1,812 | 591 | 2,403 | 913 | 227 | 235 | 67 | 1,442 | 186 | 27 | – | – | – | 4,058 | |||
| Identifiable assets | 6,826 | 2,479 | 9,305 | 5,089 | 3,789 | 1,899 | 2,255 | 13,032 | 1,137 | 1,465 | – | 280 | (86 | ) | 25,133 | ||
| Total assets | 8,638 | 3,070 | 11,708 | 6,002 | 4,016 | 2,134 | 2,322 | 14,474 | 1,323 | 1,492 | – | 280 | (86 | ) | 29,191 | ||
| Gross capital expenditures | 416 | 177 | 593 | 252 | 260 | 53 | 113 | 678 | 83 | 17 | – | 10 | – | 1,381 | |||
| Year-to-Date | |||||||||||||||||
| September 30, 2015 | |||||||||||||||||
| ($ millions) | |||||||||||||||||
| Revenue | 1,552 | 678 | 2,230 | 884 | 423 | 261 | 760 | 2,328 | 239 | 77 | 165 | 22 | (42 | ) | 5,019 | ||
| Energy supply costs | 626 | 257 | 883 | 337 | – | 76 | 489 | 902 | 127 | 1 | – | – | (16 | ) | 1,897 | ||
| Operating expenses | 418 | 284 | 702 | 205 | 133 | 65 | 106 | 509 | 34 | 12 | 119 | 25 | (9 | ) | 1,392 | ||
| Depreciation and amortization | 178 | 42 | 220 | 143 | 125 | 43 | 62 | 373 | 34 | 13 | 11 | 1 | – | 652 | |||
| Operating income | 330 | 95 | 425 | 199 | 165 | 77 | 103 | 544 | 44 | 51 | 35 | (4 | ) | (17 | ) | 1,078 | |
| Other income (expenses), net | 2 | 6 | 8 | 7 | 2 | – | 1 | 10 | 1 | 57 | 109 | 4 | (1 | ) | 188 | ||
| Finance charges | 73 | 29 | 102 | 102 | 59 | 28 | 42 | 231 | 11 | 2 | 18 | 70 | (18 | ) | 416 | ||
| Income tax expense (recovery) | 90 | 29 | 119 | 28 | (1 | ) | 7 | 15 | 49 | – | 24 | 13 | (32 | ) | – | 173 | |
| Net earnings (loss) | 169 | 43 | 212 | 76 | 109 | 42 | 47 | 274 | 34 | 82 | 113 | (38 | ) | – | 677 | ||
| Non-controlling interests | – | – | – | 1 | – | – | – | 1 | 9 | 16 | – | – | – | 26 | |||
| Preference share dividends | – | – | – | – | – | – | – | – | – | – | – | 58 | – | 58 | |||
| Net earnings (loss) attributable to common equity shareholders | 169 | 43 | 212 | 75 | 109 | 42 | 47 | 273 | 25 | 66 | 113 | (96 | ) | – | 593 | ||
| Goodwill | 1,842 | 602 | 2,444 | 913 | 227 | 235 | 67 | 1,442 | 189 | – | – | – | – | 4,075 | |||
| Identifiable assets | 6,699 | 2,407 | 9,106 | 4,960 | 3,501 | 1,855 | 2,162 | 12,478 | 1,050 | 1,025 | 381 | 613 | (410 | ) | 24,243 | ||
| Total assets | 8,541 | 3,009 | 11,550 | 5,873 | 3,728 | 2,090 | 2,229 | 13,920 | 1,239 | 1,025 | 381 | 613 | (410 | ) | 28,318 | ||
| Gross capital expenditures | 552 | 123 | 675 | 364 | 306 | 83 | 115 | 868 | 95 | 31 | 9 | 5 | – | 1,683 | |||
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 and nine months ended September 30, 2016 and 2015 were as follows:
| Significant Related Party Inter-Segment Transactions | Quarter Ended | Year-to-Date | |||
| September 30 | September 30 | ||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | |
| Sales from Non-Regulated Energy Infrastructure to Regulated Electric Utilities – Canadian | 14 | 12 | 33 | 15 | |
| Sales from Non-Regulated Energy Infrastructure to Regulated Gas Utilities – Canadian | 4 | – | 9 | – | |
| Revenue from Regulated Electric Utilities – Canadian to Non-Regulated Energy Infrastructure | 2 | 3 | 7 | 3 | |
| Sales from Regulated Electric Utilities – Canadian toNon-Utility | – | 1 | – | 4 | |
| Inter-segment finance charges on lending from: | |||||
| Corporate to Non-Utility | – | 5 | – | 17 | |
The significant related party inter-segment asset balances were as follows:
| Significant Related Party Inter-Segment Assets | As at September 30 |
||
| ($ millions) | 2016 | 2015 | |
| Inter-segment lending from: | |||
| Non-Regulated Energy Infrastructure to Eastern Canadian Electric Utilities | 20 | 20 | |
| Corporate to Non-Utility | – | 364 | |
| Other inter-segment assets | 66 | 26 | |
| Total inter-segment eliminations | 86 | 410 | |
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 | ||||
| September 30, | December 31, | |||
| ($ millions) | 2016 | 2015 | ||
| Regulatory assets | ||||
| Deferred income taxes | 990 | 936 | ||
| Employee future benefits | 562 | 627 | ||
| Deferred energy management costs | 159 | 145 | ||
| Manufactured gas plant (“MGP”) site remediation deferral (Note 21) | 105 | 121 | ||
| Deferred lease costs | 103 | 90 | ||
| Rate stabilization accounts | 97 | 119 | ||
| Deferred operating overhead costs | 75 | 66 | ||
| Natural gas for transportation incentives | 40 | 25 | ||
| Final mine reclamation and retiree health care costs (Note 21) | 39 | 39 | ||
| Deferred net losses on disposal of utility capital assets and intangible assets | 30 | 33 | ||
| Property tax deferrals | 30 | 30 | ||
| Derivative instruments (Note 17) | 28 | 74 | ||
| Springerville Unit 1 unamortized leasehold improvements | 23 | 30 | ||
| Other regulatory assets | 214 | 197 | ||
| Total regulatory assets | 2,495 | 2,532 | ||
| Less: current portion | (209 | ) | (246 | ) |
| Long–term regulatory assets | 2,286 | 2,286 | ||
| As at | ||||
| September 30, | December 31, | |||
| ($ millions) | 2016 | 2015 | ||
| Regulatory liabilities | ||||
| Non-asset retirement obligation removal cost provision | 1,073 | 1,060 | ||
| Rate stabilization accounts | 190 | 212 | ||
| Electric and gas moderator account | 72 | 88 | ||
| Renewable energy surcharge | 48 | 47 | ||
| Energy efficiency liability | 48 | 20 | ||
| Employee future benefits | 36 | 44 | ||
| Customer and community benefits obligation | 25 | 32 | ||
| Other regulatory liabilities | 139 | 135 | ||
| Total regulatory liabilities | 1,631 | 1,638 | ||
| Less: current portion | (312 | ) | (298 | ) |
| Long–term regulatory liabilities | 1,319 | 1,340 | ||
6. LONG-TERM DEBT
| As at | ||||
| September 30, | December 31, | |||
| ($ millions) | 2016 | 2015 | ||
| Long-term debt | 10,697 | 10,689 | ||
| Long-term classification of credit facility borrowings (Note 19) | 1,119 | 551 | ||
| Total long-term debt (Note 17) | 11,816 | 11,240 | ||
| Less: Deferred financing costs | (74 | ) | (72 | ) |
| Less: Current installments of long-term debt | (118 | ) | (384 | ) |
| 11,624 | 10,784 | |||
In April 2016 FortisBC Energy issued $300 million of unsecured debentures in a dual tranche of 10-year $150 million unsecured debentures at 2.58% and 30-year $150 million unsecured debentures at 3.67%. The net proceeds were used to repay short-term borrowings and to finance capital expenditures.
In May and September 2016, Fortis Turks and Caicos issued 15-year US$45 million unsecured notes, in a dual tranche of US$22.5 million at 5.14% and 5.29%, respectively. In July 2016 Fortis Turks and Caicos issued 15-year US$5 million unsecured bonds at 5.14%. The net proceeds were used to finance capital expenditures and for general corporate purposes.
In June 2016 Central Hudson issued 4-year US$24 million unsecured notes at 2.16%. The net proceeds were used to finance capital expenditures and for general corporate purposes.
In August 2016 Maritime Electric issued 40-year $40 million secured first mortgage bonds at 3.657%. The net proceeds were primarily used to repay long-term debt and short-term borrowings.
In September 2016 FortisAlberta issued 30-year $150 million unsecured debentures at 3.34%. The net proceeds were used to repay credit facility borrowings, to finance capital expenditures and for general corporate purposes.
In October 2016 the Corporation issued 5-year US$500 million unsecured notes at 2.100% and 10-year US$1.5 billion unsecured notes at 3.055%. The net proceeds were used to finance a portion of the cash purchase price of the acquisition of ITC (Note 16).
7. COMMON SHARES
Common shares issued during the period were as follows:
| Quarter Ended | Year-to-Date | ||||
| September 30, 2016 | September 30, 2016 | ||||
| Number of | Number of | ||||
| Shares | Amount | Shares | Amount | ||
| (in thousands) | ($ millions) | (in thousands) | ($ millions) | ||
| Balance, beginning of period | 284,187 | 5,962 | 281,562 | 5,867 | |
| Dividend Reinvestment Plan | 909 | 37 | 2,600 | 103 | |
| Consumer Share Purchase Plan | 6 | – | 21 | 1 | |
| Employee Share Purchase Plan | 67 | 3 | 288 | 11 | |
| Stock Option Plans | 293 | 10 | 989 | 30 | |
| Conversion of convertible debentures | 8 | – | 10 | – | |
| Balance, end of period (1) | 285,470 | 6,012 | 285,470 | 6,012 | |
| (1) | On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately US$3.6 billion, based on the closing share price of Fortis common shares of $40.96 and the closing foreign exchange rate of 1.32 on October 13, 2016 (Note 16). |
8. PREFERENCE SHARES
In September 2016 the Corporation redeemed all of the issued and outstanding $200 million 4.9% First Preference Shares, Series E at a redemption price of $25.3063 per share, being equal to $25.00 plus the amount of accrued and unpaid dividends per share. Upon redemption, approximately $3 million of after-tax issuance costs associated with the First Preference Shares, Series E were recognized in net earnings attributable to preference equity shareholders.
9. STOCK-BASED COMPENSATION PLANS
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.
In April 2016, 6,537 DSUs were granted to the Corporation’s Board of Directors, representing the second quarter equity component of the Directors’ annual compensation and, where opted, their second quarter component of annual retainers in lieu of cash.
In July 2016, 7,703 DSUs were granted to the Corporation’s Board of Directors, representing the third quarter equity component of the Directors’ annual compensation and, where opted, their third quarter component of annual retainers in lieu of cash.
Performance Share Unit Plans
Year-to-date 2016, the Corporation granted 351,737 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 September 30, 2016, the estimated payout percentages for the grants under the 2013 and 2015 PSU Plans ranged from 78% to 113%.
In the second quarter of 2016, 145,736 PSUs were paid out to senior management of the Corporation and its subsidiaries at $37.72 per PSU, for a total of approximately $5 million. The payout was made in respect of the PSUs granted in 2013 at a payout percentage of 96% based on the Corporation’s performance over the three-year period, as determined by the Human Resources Committee of the Board of Directors.
Restricted Share Unit Plans
Year-to-date 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 and nine months ended September 30, 2016, stock-based compensation expense of approximately $3 million and $18 million, respectively, was recognized ($5 million and $13 million for the three and nine months ended September 30, 2015, respectively).
10. EMPLOYEE FUTURE BENEFITS
The Corporation and its subsidiaries each maintain one or a combination of defined benefit pension plans and defined contribution pension plans, including group Registered Retirement Savings Plans and group 401(k) plans, for employees. The Corporation and certain subsidiaries also offer other post-employment benefit (“OPEB”) plans for qualifying employees. The net benefit cost of providing the defined benefit pension and OPEB plans is detailed in the following tables.
| Quarter Ended September 30 | ||||||||
| Defined Benefit | ||||||||
| Pension Plans | OPEB Plans | |||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||
| Components of net benefit cost: | ||||||||
| Service costs | 16 | 17 | 5 | 3 | ||||
| Interest costs | 28 | 28 | 5 | 6 | ||||
| Expected return on plan assets | (36 | ) | (37 | ) | (4 | ) | (4 | ) |
| Amortization of actuarial losses | 12 | 16 | – | 1 | ||||
| Amortization of past service credits | – | – | (3 | ) | (2 | ) | ||
| Regulatory adjustments | 2 | 1 | 2 | 2 | ||||
| Net benefit cost | 22 | 25 | 5 | 6 | ||||
| Year-to-Date September 30 | ||||||||
| Defined Benefit | ||||||||
| Pension Plans | OPEB Plans | |||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||
| Components of net benefit cost: | ||||||||
| Service costs | 48 | 51 | 12 | 12 | ||||
| Interest costs | 83 | 82 | 16 | 17 | ||||
| Expected return on plan assets | (107 | ) | (106 | ) | (10 | ) | (9 | ) |
| Amortization of actuarial losses | 35 | 44 | 1 | 3 | ||||
| Amortization of past service costs (credits) | 1 | 1 | (9 | ) | (8 | ) | ||
| Regulatory adjustments | 5 | – | 7 | 5 | ||||
| Net benefit cost | 65 | 72 | 17 | 20 | ||||
For the three and nine months ended September 30, 2016, the Corporation expensed $7 million and $22 million, respectively ($8 million and $22 million for the three and nine months ended September 30, 2015), related to defined contribution pension plans.
11. OTHER INCOME (EXPENSES), NET
| Quarter Ended | Year-to-Date | |||||
| September 30 | September 30 | |||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||
| Equity component of allowance for funds used during construction (“AFUDC”) | 7 | 6 | 20 | 15 | ||
| Net (loss) gain on sale of commercial real estate and hotel assets (1) | – | (2 | ) | – | 109 | |
| Gain on sale of non-regulated generation assets (2) | – | 5 | – | 56 | ||
| Equity income – Belize Electricity | 1 | – | 4 | – | ||
| Interest income | 1 | 2 | 5 | 6 | ||
| Net foreign exchange gain | – | 5 | – | 13 | ||
| Loss on settlement of expropriation matters | – | (9 | ) | – | (9 | ) |
| Other income (expenses), net | 1 | (2 | ) | 6 | (2 | ) |
| 10 | 5 | 35 | 188 | |||
| (1) | Net of $23 million of expenses associated with the sale and a $14 million impairment loss on the hotel assets |
| (2) | Net of $6 million of expenses and foreign exchange impacts associated with the sale |
In June 2015 the Corporation completed the sale of the commercial real estate assets of Fortis Properties for gross proceeds of $430 million. As a result of the sale, the Corporation recognized a gain on sale of $129 million ($109 million after tax), net of expenses, in the second quarter of 2015. In October 2015 the Corporation completed the sale of the hotel assets of Fortis Properties for gross proceeds of $365 million. As a result of the sale, the Corporation recognized a loss of approximately $20 million ($8 million after tax), which reflected an impairment loss and expenses associated with the sale transaction, in the second and third quarters of 2015.
In June 2015 the Corporation sold its non-regulated generation assets in Upstate New York for gross proceeds of approximately $77 million (US$63 million). As a result of the sale, the Corporation recognized a gain on sale of $51 million (US$41 million) ($27 million (US$22 million) after tax), net of expenses and foreign exchange impacts, in the second quarter of 2015. In July 2015 the Corporation sold its non-regulated generation assets in Ontario for gross proceeds of approximately $16 million. As a result of the sale, the Corporation recognized a gain on sale of $5 million ($5 million after tax) in the third quarter of 2015.
The net foreign exchange gain relates to the translation into Canadian dollars of the Corporation’s previous US dollar-denominated long-term other asset, representing the book value of the Corporation’s expropriated investment in Belize Electricity, up to the date of settlement of expropriation matters in August 2015. As a result of the settlement, the Corporation recognized an approximate $9 million loss in the third quarter of 2015. Unrealized foreign exchange gains and losses associated with the Corporation’s 33% equity investment in Belize Electricity are recognized on the balance sheet in accumulated other comprehensive income.
12. FINANCE CHARGES
| Quarter Ended | Year-to-Date | ||||||||
| September 30 | September 30 | ||||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | |||||
| Interest: | |||||||||
| Long-term debt and capital lease and finance obligations | 147 | 145 | 436 | 428 | |||||
| Short-term borrowings | 1 | 1 | 5 | 6 | |||||
| Acquisition credit facilities (Notes 16 and 19) (1) | 21 | – | 35 | – | |||||
| Debt component of AFUDC | (5 | ) | (5 | ) | (19 | ) | (18 | ) | |
| 164 | 141 | 457 | 416 | ||||||
| (1) | Includes $4 million (US$3 million) of hedge ineffectiveness associated with the Corporation’s forward-starting deal-contingent interest-rate swap contracts (Note 17). |
13. INCOME TAXES
Income taxes differ from the amount that would be expected to be generated by applying the enacted combined Canadian federal statutory and provincial income tax rate to earnings before income taxes. The following is a reconciliation of consolidated statutory income taxes to consolidated effective income taxes.
| Quarter Ended | Year-to-Date | |||||||
| September 30 | September 30 | |||||||
| ($ millions, except as noted) | 2016 | 2015 | 2016 | 2015 | ||||
| Combined Canadian federal and provincial statutory income tax rate | 28.0 | % | 29.0 | % | 28.0 | % | 29.0 | % |
| Statutory income tax rate applied to earnings before income taxes | 55 | 64 | 167 | 247 | ||||
| Difference between Canadian statutory rate and rates applicable to foreign subsidiaries | (2 | ) | (4 | ) | (15 | ) | (5 | ) |
| Difference between Canadian provincial statutory rates applicable to subsidiaries in different Canadian jurisdictions | 1 | – | (2 | ) | (8 | ) | ||
| Items capitalized for accounting purposes but expensed for income tax purposes | (7 | ) | (9 | ) | (26 | ) | (29 | ) |
| Difference between gain on sale of assets foraccounting and amounts calculated for tax purposes | – | (8 | ) | – | (21 | ) | ||
| Other | (7 | ) | (3 | ) | (14 | ) | (11 | ) |
| Income tax expense | 40 | 40 | 110 | 173 | ||||
| Effective income tax rate | 20.2 | % | 18.3 | % | 18.4 | % | 20.4 | % |
14. EARNINGS PER COMMON SHARE
The Corporation calculates earnings per common share (“EPS”) on the weighted average number of common shares outstanding. Diluted EPS is calculated using the treasury stock method for options and the “if-converted” method for convertible securities.
EPS was as follows:
| Quarter Ended September 30 | |||||||||
| 2016 | 2015 | ||||||||
| Net Earnings | Weighted | Net Earnings | Weighted | ||||||
| to Common | Average | to Common | Average | ||||||
| Shareholders | Shares | Shareholders | Shares | ||||||
| ($ millions) | (# millions) | EPS | ($ millions) | (# millions) | EPS | ||||
| Basic EPS (1) | 127 | 285.0 | $ | 0.45 | 151 | 279.1 | $ | 0.54 | |
| Effect of potential dilutive securities: | |||||||||
| Stock Options | – | 0.7 | – | 0.8 | |||||
| Preference Shares | 2 | 3.8 | 2 | 5.4 | |||||
| Diluted EPS | 129 | 289.5 | $ | 0.45 | 153 | 285.3 | $ | 0.54 | |
| (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 purpose of calculating EPS. |
| Year-to-Date September 30 | |||||||||
| 2016 | 2015 | ||||||||
| Net Earnings | Weighted | Net Earnings | Weighted | ||||||
| to Common | Average | to Common | Average | ||||||
| Shareholders | Shares | Shareholders | Shares | ||||||
| ($ millions) | (# millions) | EPS | ($ millions) | (# millions) | EPS | ||||
| Basic EPS (1) | 396 | 283.7 | $ | 1.40 | 593 | 277.9 | $ | 2.13 | |
| Effect of potential dilutive securities: | |||||||||
| Stock Options | – | 0.7 | – | 0.8 | |||||
| Preference Shares | 7 | 5.0 | 7 | 5.4 | |||||
| Diluted EPS | 403 | 289.4 | $ | 1.39 | 600 | 284.1 | $ | 2.11 | |
| (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 purpose of calculating EPS. |
On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC and will be included as a component of the Corporation’s basic EPS and diluted EPS subsequent to this date (Note 16).
15. SUPPLEMENTAL INFORMATION TO CONSOLIDATED STATEMENTS OF CASH FLOWS
| Quarter Ended | Year-to-Date | |||||||
| September 30 | September 30 | |||||||
| ($ millions) | 2016 | 2015 | 2016 | 2015 | ||||
| Change in non-cash operating working capital: | ||||||||
| Accounts receivable and other current assets | 43 | 10 | 127 | 103 | ||||
| Prepaid expenses | (30 | ) | (42 | ) | (37 | ) | (32 | ) |
| Inventories | (39 | ) | (48 | ) | 6 | (6 | ) | |
| Regulatory assets – current portion | 4 | 28 | 4 | 60 | ||||
| Accounts payable and other current liabilities | 85 | (36 | ) | 21 | (38 | ) | ||
| Regulatory liabilities – current portion | – | (12 | ) | 16 | (8 | ) | ||
| 63 | (100 | ) | 137 | 79 | ||||
| Non-cash investing and financing activities: | ||||||||
| Additions to utility capital assets and intangible assets included in current liabilities and long-term other liabilities | 152 | 197 | 152 | 197 | ||||
| Contributions in aid of construction included in current assets | 6 | 6 | 6 | 6 | ||||
| Transfer of deposit on business acquisition (Note 16) | – | – | 38 | – | ||||
| Common share dividends reinvested | 37 | 38 | 102 | 112 | ||||
| Exercise of stock options into common shares | 1 | – | 4 | 2 | ||||
16. BUSINESS ACQUISITIONS
AITKEN CREEK
On April 1, 2016, Fortis acquired Aitken Creek Gas Storage ULC (“ACGS”) from Chevron Canada Properties Ltd. for approximately $349 million (US$266 million), plus working gas inventory. The net cash purchase price was primarily financed through US dollar-denominated borrowings under the Corporation’s committed revolving credit facility.
ACGS owns 93.8% of 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.
Revenue at Aitken Creek is primarily generated from long-term lease storage, park and loan activities, and storage optimization activities and is generally recognized on an accrual basis over the term of the related contracts. Optimization revenue results from the purchase of natural gas and its forward sale through financial and physical trading contracts, to manage commodity price risk associated with buying and selling natural gas in future periods. The Corporation records the unrealized gains and losses on the changes in the fair value of the derivative instruments through net earnings.
The preliminary allocation of purchase consideration to the assets and liabilities acquired as at April 1, 2016, based on their fair values, resulted in the recognition of approximately $27 million in goodwill, which is associated with deferred income tax liabilities. The purchase price allocation is preliminary pending final assessment of deferred income tax liabilities and working capital. The acquisition has been accounted for using the acquisition method, whereby financial results of the business acquired have been consolidated in the financial statements of Fortis commencing on April 1, 2016, and are included in the Non-Regulated – Energy Infrastructure reporting segment.
ITC HOLDINGS
On October 14, 2016, Fortis and GIC acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion on closing, including approximately US$4.8 billion of ITC consolidated indebtedness at fair value. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC.
Under the terms of the transaction, ITC shareholders received US$22.57 in cash and 0.7520 of a Fortis common share per ITC share, representing total consideration of approximately US$7.0 billion. The net cash consideration totalled approximately US$3.4 billion and was financed using: (i) net proceeds from the issuance of US$2.0 billion unsecured notes on October 4, 2016; (ii) net proceeds from GIC’s US$1.228 billion minority investment; and (iii) drawings of approximately US$404 million ($535 million) under the Corporation’s non-revolving term senior unsecured equity bridge credit facility. On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing share consideration of approximately US$3.6 billion, based on the closing price for Fortis common shares of $40.96 and the closing foreign exchange rate of 1.32 on October 13, 2016. The financing of the acquisition has been structured to allow Fortis to maintain investment-grade credit ratings.
ITC is the largest independent electric transmission company in the United States. Based in Novi, Michigan, ITC invests in the electrical transmission grid to improve reliability, expand access to markets, allow new generating resources to interconnect to its transmission systems and lower the overall cost of delivered energy. Through its regulated operating subsidiaries ITCTransmission, Michigan Electric Transmission Company, ITC Midwest and ITC Great Plains, 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 Midwest maintains utility status in Wisconsin.
ITC’s tariff rates are regulated by the United States Federal Energy Regulatory Commission (“FERC”). As at September 30, 2016, the weighted average allowed ROEs for ITC’s regulated operating subsidiaries are more than 11.00% on a 60% common equity component of capital structure. Rates are set using a forward-looking rate-setting mechanism with an annual true-up, which provides timely cost recovery and reduces regulatory lag.
Fortis and ITC shareholders approved the acquisition at shareholder meetings held in May and June 2016, respectively. All required regulatory, state and federal approvals associated with the acquisition, including, among others, those of FERC and the United States Federal Trade Commission/Department of Justice under the Hart-Scott-Rodino Antitrust Improvements Act, were received prior to closing.
The acquisition will be accounted for using the acquisition method, whereby financial results of the business acquired will be consolidated in the financial statements of Fortis commencing on October 14, 2016. ITC will be presented as a separate reporting segment, Regulated Transmission Utility – United States. Due to the limited amount of time since the acquisition of ITC, the initial accounting for this business combination is not yet complete.
Acquisition-related expenses totalling $25 million ($19 million after tax) and $74 million ($58 million after tax) were recognized in earnings for the three and nine months ended September 30, 2016, respectively. Acquisition-related expenses included: (i) investment banking, legal, consulting and other fees totalling approximately $4 million ($3 million after tax) and $39 million ($32 million after tax) for the three and nine months ended September 30, 2016, respectively, which were included in operating expenses; and (ii) fees associated with the Corporation’s acquisition credit facilities and deal-contingent interest rate swap contracts totalling approximately $21 million ($16 million after tax) and $35 million ($26 million after tax) for the three and nine months ended September 30, 2016, respectively, which were included in finance charges (Note 12). The Corporation expects to recognize additional acquisition-related expenses in the fourth quarter of 2016.
17. FAIR VALUE MEASUREMENTS AND FINANCIAL INSTRUMENTS
Fair value is the price at which a market participant could sell an asset or transfer a liability to an unrelated party. A fair value measurement is required to reflect the assumptions that market participants would use in pricing an asset or liability based on the best available information. These assumptions include the risks inherent in a particular valuation technique, such as a pricing model, and the risks inherent in the inputs to the model. A fair value hierarchy exists that prioritizes the inputs used to measure fair value.
The three levels of the fair value hierarchy are defined as follows:
| Level 1: | Fair value determined using unadjusted quoted prices in active markets; |
| Level 2: | Fair value determined using pricing inputs that are observable; and |
| Level 3: | Fair value determined using unobservable inputs only when relevant observable inputs are not available. |
The fair values of the Corporation’s financial instruments, including derivatives, reflect point-in-time estimates based on current and relevant market information about the instruments as at the balance sheet dates. The estimates cannot be determined with precision as they involve uncertainties and matters of judgment and, therefore, may not be relevant in predicting the Corporation’s future consolidated earnings or cash flows.
The following table presents, by level within the fair value hierarchy, the Corporation’s assets and liabilities accounted for at fair value on a recurring basis. These assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement and there were no transfers between the levels in the periods presented. For derivative instruments, the Corporation has elected gross presentation for its derivative contracts under master netting agreements and collateral positions.
| As at | |||||
| Fair value | September 30, | December 31, | |||
| ($ millions) | hierarchy | 2016 | 2015 | ||
| Assets | |||||
| Energy contracts subject to regulatory deferral (1) (2) (3) | Levels 2/3 | 9 | 7 | ||
| Energy contracts not subject to regulatory deferral (1) (2) | Level 3 | 4 | 2 | ||
| Available-for-sale investment (4) | Level 1 | 40 | 33 | ||
| Assets held for sale (5) | Level 2 | – | 9 | ||
| Other investments (6) | Level 1 | 10 | 12 | ||
| Total gross assets | 63 | 63 | |||
| Less: Counterparty netting not offset on the balance sheet (7) | (8 | ) | (6 | ) | |
| Total net assets | 55 | 57 | |||
| Liabilities | |||||
| Energy contracts subject to regulatory deferral (1) (2) (8) | Levels 1/2/3 | 35 | 78 | ||
| Energy contracts not subject to regulatory deferral (1) | Level 2 | 4 | – | ||
| Interest rate swaps – cash flow hedges (9) | Level 2 | 12 | 5 | ||
| Total gross liabilities | 51 | 83 | |||
| Less: Counterparty netting not offset on the balance sheet (7) | (8 | ) | (6 | ) | |
| Total net liabilities | 43 | 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 and certain gas swap contracts. |
| (2) | Changes in one or more of the unobservable inputs could have a significant impact on the fair value measurement depending on the magnitude and direction of the change for each input. The impacts of changes in fair value are subject to regulatory recovery, with the exception of long-term wholesale trading contracts and certain gas swap contracts. |
| (3) | As at September 30, 2016, includes $7 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 accounts receivable and other current 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 September 30, 2016, includes $21 million – level 2 and $14 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 of the cash flow hedges are recorded in other comprehensive income until they become realized and are reclassified to earnings. Any cash flow hedge ineffectiveness is recognized in 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 is the estimate of the amounts that the Corporation would receive or have to pay to terminate the outstanding contracts as at the balance sheet dates.
Energy Contracts Subject to Regulatory Deferral
UNS Energy holds electricity power purchase contracts and gas swap 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, transmission costs 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 September 30, 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 September 30, 2016, unrealized losses of $28 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
UNS Energy holds 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 customers through UNS Energy’s rate stabilization accounts.
Aitken Creek holds gas swap contracts to manage its exposure to changes in natural gas prices, to capture natural gas price spreads, and to manage the financial risk posed by physical transactions. The fair value of the gas swap contracts was calculated using forward pricing provided by third parties. The unrealized gains and losses on these derivative instruments are recorded in earnings. As at September 30, 2016, unrealized losses totalled $4 million ($3 million after tax).
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 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. For the three and nine months ended September 30, 2016, realized losses from cash flow hedges of less than $1 million and $1 million, respectively, were recognized ($1 million for the three and nine months ended September 30, 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.
In July 2016 the Corporation entered into forward-starting deal-contingent interest rate swap contracts with notional amounts totalling US$1.25 billion. These derivatives were designated as a hedge of a portion of the cash flow risk associated with the expected issuance of US$2 billion of long-term debt, which was completed on October 4, 2016, to finance a portion of the cash purchase price of the acquisition of ITC (Notes 6 and 16). As at September 30, 2016, the unrealized loss on the derivatives totalled approximately $9 million (US$7 million), of which $5 million (US$4 million) was recognized in other comprehensive income and $4 million (US$3 million) of hedge ineffectiveness was recognized in earnings. The derivative contracts were cancelled and settled in October 2016.
Cash flows associated with the settlement of all derivative instruments are included in operating activities on the Corporation’s consolidated statement of cash flows.
Volume of Derivative Activity
As at September 30, 2016, the following notional volumes related to electricity and natural gas derivatives that are expected to be settled are outlined below.
| Maturity | Contracts | There- | ||||||
| Volume | (year) | (#) | 2016 | 2017 | 2018 | 2019 | 2020 | after |
| Energy contracts subject to regulatory deferral: | ||||||||
| Electricity swap contracts (GWh) (1) | 2019 | 8 | 275 | 781 | 438 | 219 | – | – |
| Electricity power purchase contracts (GWh) | 2017 | 30 | 374 | 737 | – | – | – | – |
| Gas swap and option contracts (PJ) (1) | 2019 | 121 | 8 | 17 | 9 | 3 | – | – |
| Gas supply contract premiums (PJ) | 2024 | 118 | 40 | 80 | 44 | 26 | 22 | 64 |
| Energy contracts not subject to regulatory deferral: | ||||||||
| Long-term wholesale trading contracts (GWh) | 2017 | 14 | 858 | 1,688 | – | – | – | – |
| Gas swap contracts (PJ) | 2017 | 541 | 4 | 13 | – | – | – | – |
| (1) | GWh means gigawatt hours and PJ means petajoules |
Financial Instruments Not Carried At Fair Value
The following table discloses the estimated fair value measurements of the Corporation’s financial instruments not carried at fair value. The fair values were measured using Level 2 pricing inputs, except as noted. The carrying values of the Corporation’s consolidated financial instruments approximate their fair values, reflecting the short-term maturity, normal trade credit terms and/or nature of these instruments, except as follows:
| As at | ||||||||
| September 30, 2016 | December 31, 2015 | |||||||
| (Liability) | Carrying | Estimated | Carrying | Estimated | ||||
| ($ millions) | Value | Fair Value | Value | Fair Value | ||||
| Long-term debt, including current portion (Note 6) (1) | (11,816 | ) | (13,909 | ) | (11,240 | ) | (12,614 | ) |
| Waneta Partnership promissory note (2) | (58 | ) | (62 | ) | (56 | ) | (59 | ) |
| (1) | The Corporation’s $200 million unsecured debentures due 2039 and consolidated borrowings under credit facilities classified as long-term debt of $1,119 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 18). |
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.
18. VARIABLE INTEREST ENTITY
On adoption of ASU No. 2015-02, Amendments to the Consolidation Analysis, effective January 1, 2016, Fortis is 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 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 following details the Waneta Partnership assets, liabilities, revenue, expenses, and cash flow, included in the Corporation’s interim unaudited consolidated financial statements.
| As at | ||||
| September 30, | December 31, | |||
| ($ millions) | 2016 | 2015 | ||
| ASSETS | ||||
| Cash and cash equivalents | 20 | 23 | ||
| Accounts receivable and other current assets | 12 | 14 | ||
| Utility capital assets | 699 | 708 | ||
| Intangible assets | 29 | 30 | ||
| 760 | 775 | |||
| LIABILITIES | ||||
| Accounts payable and other current liabilities | (4 | ) | (18 | ) |
| Other liabilities (Note 17) | (78 | ) | (74 | ) |
| (82 | ) | (92 | ) | |
| Net assets before non-controlling interests | 678 | 683 | ||
| Quarter Ended | Year-to-Date | |||
| September 30 | September 30 | |||
| ($ millions) | 2016 | 2015 | 2016 | 2015 |
| Revenue | 19 | 18 | 72 | 49 |
| Expenses | ||||
| Operating | 5 | 3 | 12 | 6 |
| Depreciation and amortization | 4 | 5 | 13 | 9 |
| Finance charges | 1 | – | 3 | 1 |
| 10 | 8 | 28 | 16 | |
| Net earnings | 9 | 10 | 44 | 33 |
Cash used in investing activities at the Waneta Partnership for the three and nine months ended September 30, 2016 included capital expenditures of $1 million and $17 million, respectively ($12 million and $26 million for the three and nine months ended September 30, 2015, respectively). Cash from financing activities for the three and nine months ended September 30, 2016 included dividends paid by the Waneta Partnership to non-controlling interests of $15 million and $24 million, respectively (advances from non-controlling interests of $9 million for the nine months ended September 30, 2015).
19. 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 September 30, 2016, FortisAlberta’s gross credit risk exposure was approximately $125 million, representing the projected value of retailer billings over a 37-day period. The Company has reduced its exposure to $2 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, FortisBC Energy and Aitken Creek may be exposed to credit risk in the event of non-performance by counterparties to derivative instruments. The Companies use netting arrangements to reduce credit risk and net settle payments with counterparties where net settlement provisions exist. They also limit credit risk by primarily 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 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 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 credit facility may be required from time to time to support the servicing of debt and payment of dividends. Over the next five years, average annual consolidated fixed-term debt maturities and repayments are expected to be approximately $450 million, including an average of approximately $210 million at ITC. 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 September 30, 2016, the Corporation and its subsidiaries had consolidated credit facilities of approximately $3.8 billion, of which approximately $2.2 billion was unused, including $327 million unused under the Corporation’s committed 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 $3.6 billion of the total credit facilities are committed facilities with maturities ranging from 2019 through 2021.
The following summary outlines the credit facilities of the Corporation and its subsidiaries.
| As at | |||||||||
| Regulated | Corporate | September 30, | December 31, | ||||||
| ($ millions) | Utilities | and Other | 2016 | 2015 | |||||
| Total credit facilities | 2,176 | 1,647 | 3,823 | 3,565 | |||||
| Credit facilities utilized: | |||||||||
| Short-term borrowings (1) | (414 | ) | (9 | ) | (423 | ) | (511 | ) | |
| Long-term debt (Note 6) (2) | (51 | ) | (1,068 | ) | (1,119 | ) | (551 | ) | |
| Letters of credit outstanding | (68 | ) | (54 | ) | (122 | ) | (104 | ) | |
| Credit facilities unused | 1,643 | 516 | 2,159 | 2,399 | |||||
| (1) | The weighted average interest rate on short-term borrowings was approximately 1.1% as at September 30, 2016 (December 31, 2015 – 1.0%). |
| (2) | As at September 30, 2016, credit facility borrowings classified as long-term debt included $51 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 September 30, 2016 (December 31, 2015 – 1.5%). |
As at September 30, 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. In August 2016 the Corporation exercised its option to increase the facility to $1.3 billion from $1.0 billion.
In June 2016 FortisOntario amended its $30 million unsecured committed revolving credit facility to now mature in June 2019.
In July 2016 FortisBC Energy amended its $700 million unsecured committed revolving credit facility to now mature in August 2021.
In July 2016 FortisAlberta amended its $250 million unsecured committed revolving credit facility to now mature in August 2021.
In July 2016 Newfoundland Power amended its $100 million unsecured committed revolving credit facility to now mature in August 2021.
In October 2016 UNS Energy amended its US$500 million unsecured committed revolving credit facilities resulting in an extension of the maturity dates to October 2021.
In connection with the acquisition of ITC (Note 16), in February 2016 the Corporation obtained commitments of US$2.0 billion from Goldman Sachs Bank USA to bridge the long-term debt financing 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”) (Note 12). In October 2016, $535 million (US$404 million) was drawn on the Equity Bridge Facility to finance a portion of the cash purchase price of the acquisition of ITC and is repayable in full within one year. All remaining acquisition credit facilities have been cancelled. The credit facilities table above does not include the acquisition credit facilities.
The Corporation and its currently rated utilities target investment-grade credit ratings to maintain capital market access at reasonable interest rates. The Corporation’s credit ratings are as follows:
| Rating Agency | Credit Rating | Type of Rating | Outlook |
| Standard & Poor’s (“S&P”) | A- | Corporate | Stable |
| BBB+ | Unsecured debt | Stable | |
| DBRS | BBB (high) | Unsecured debt | Stable |
| Moody’s Investor Service (“Moody’s”) | Baa3 | Issuer | Stable |
| Baa3 | Unsecured debt | Stable |
The above-noted credit ratings reflect the Corporation’s low business-risk profile and diversity of its operations, the stand-alone nature and financial separation of each of the regulated subsidiaries of Fortis, and the level of debt at the holding company. In 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 unsecured debt credit rating under review with negative implications. In September 2016 Moody’s commenced rating Fortis and assigned the Corporation an issuer credit rating of Baa3 and an unsecured debt credit rating of Baa3, both with a stable outlook. In October 2016, following the completion of the acquisition of ITC, DBRS revised the Corporation’s unsecured debt credit rating to BBB (high) from A (low) and revised its outlook to stable from under review with negative implications, and S&P affirmed the Corporation’s long-term corporate and unsecured debt credit ratings, as previously discussed, and revised its outlook to stable from negative.
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 September 30, 2016, the Corporation’s corporately issued US$1,793 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 September 30, 2016, the Corporation had approximately US$3,018 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.
As a result of the acquisition of ITC, consolidated earnings and cash flows of Fortis will be impacted to a greater extent by fluctuations in the US dollar-to-Canadian dollar exchange rate. On an annual basis, including ITC, it is estimated that a 5 cent increase or decrease in the US dollar relative-to-Canadian dollar exchange rate would increase or decrease earnings per common share of Fortis by approximately 7 cents. 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 (Note 17).
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. Aitken Creek is exposed to commodity price risk associated with changes in the market price of gas and enters into derivative contracts to manage the financial risk posed by physical transactions. These derivative instruments are recorded on the consolidated balance sheet at fair value and any change in the fair value is deferred as a regulatory asset or liability, as permitted by the regulators, for recovery from, or refund to, customers in future rates, except at Aitken Creek where the changes in fair value are recorded in earnings (Note 17).
20. 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.
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 September 30, 2016.
UNS Energy is party to renewable power purchase agreements totalling approximately US$1,236 million as at September 30, 2016, which require UNS Energy to purchase 100% of the output of certain renewable energy generation facilities that have achieved commercial operation. In March and July 2016 two of the facilities achieved commercial operation, increasing estimated future payments of renewable power purchase contracts by US$58 million and US$86 million, respectively, as at September 30, 2016.
21. 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 provided that TEP would purchase the third-party owners’ 50.5% undivided interest in Springerville Unit 1 for US$85 million and the third-party owners would pay TEP US$13 million for operating costs related to Springerville Unit 1 incurred on behalf of the third-party owners.
In September 2016 TEP received FERC authorization to complete the transactions contemplated in the Agreement. In accordance with the Agreement, TEP purchased the undivided interest in Springerville Unit 1 for US$85 million, increasing TEP’s total ownership interest to 100%, and TEP received US$13 million from the third-party owners in full satisfaction of all previously unreimbursed operating costs. Following the purchase, all outstanding disputes, pending litigation and arbitration proceedings between TEP and the third-party owners were dismissed with prejudice.
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 September 30, 2016 was US$24 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
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 September 30, 2016, an obligation of US$79 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 New York State Public Service Commission (“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, a cash recovery of approximately US$19 million during the period through June 2018 was approved, with US$5 million recovered year-to-date 2016 (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 3,361 asbestos cases have been raised, 1,174 remained pending as at September 30, 2016. Of the cases no longer pending against Central Hudson, 2,031 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. In May 2016 the Federal Court entered a decision dismissing the Coldwater Band’s application for judicial review of the ministerial consent. The Band has appealed that decision. The outcome cannot be reasonably determined and estimated at this time and, accordingly, no amount has been accrued in the consolidated financial statements.
Fortis and ITC
Following announcement of the acquisition of ITC on February 9, 2016, complaints which named Fortis and other defendants were filed in the Oakland County Circuit Court in the State of Michigan (“Superior Court”) and the United States District Court in and for the Eastern District of Michigan. The complaints generally allege, among other things, that the directors of ITC breached their fiduciary duties in connection with the merger agreement and that ITC, Fortis, FortisUS Inc. and Element Acquisition Sub Inc. aided and abetted those purported breaches. The complaints seek class action certification and a variety of relief including, among other things, unspecified rescissory and compensatory damages, and costs, including attorneys’ fees and expenses. In July 2016 the federal actions were voluntarily dismissed by the federal plaintiffs. The federal plaintiffs reserved the right to make certain other claims, and ITC and the individual members of the ITC board of directors reserved the right to oppose any such claim. In June 2016 the Superior Court granted a motion for summary disposition dismissing the aiding and abetting claims asserted against Fortis, FortisUS Inc. and Element Acquisition Sub Inc. In July 2016 the Superior Court issued a scheduling order, which, among other things, requires the parties, including ITC, to complete discovery by March 2017, and set a trial date for June 2017. The outcome of these lawsuits cannot be predicted with any certainty and, accordingly, no amount has been accrued in the consolidated financial statements.
22. SUBSEQUENT EVENT
On October 14, 2016, Fortis and GIC acquired all of the outstanding common shares of ITC for an aggregate purchase price of approximately US$11.8 billion on closing, including approximately US$4.8 billion of ITC consolidated indebtedness at fair value. ITC is now a subsidiary of Fortis, with an affiliate of GIC owning a 19.9% minority interest in ITC.
On October 4, 2016 Fortis issued US$2.0 billion unsecured notes, comprised of 5-year US$500 million notes at 2.100% and 10-year US$1.5 billion notes at 3.055%. The net proceeds were used to finance a portion of the cash purchase price of the acquisition of ITC.
On October 14, 2016, approximately 114.4 million common shares of Fortis were issued to shareholders of ITC, representing the portion of share consideration associated with the acquisition.
For details on the business acquisition, refer to Note 16.
23. COMPARATIVE FIGURES
Certain comparative figures have been reclassified to comply with current period presentation. Acquisition-related expenses were previously included in other income, net of expenses, on the consolidated statement of earnings and have been reclassified to operating expenses.
CORPORATE INFORMATION
Fortis Inc. is a leader in the North American regulated electric and gas utility industry, with total assets of approximately $47 billion, on a pro forma basis as at September 30, 2016 including the acquisition of ITC Holdings Corp. The Corporation’s 8,000 employees serve utility customers in five Canadian provinces, nine U.S. states and three Caribbean countries.
The Common Shares; 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.F, FTS.PR.G, FTS.PR.H, FTS.PR.I, FTS.PR.J, FTS.PR.K, and FTS.PR.M, respectively. The Common Shares are also listed on the New York Stock Exchange and trade under the ticker symbol FTS.
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Vice President, Investor Relations
Fortis Inc.
709.737.2863